ER26-3515-000 · 2026-08-13 · PJM Interconnection, L.L.C.

Attachment B- Clean Tariff 4930-8837-2935 v.2.pdf

Attachment B 
Revisions to the 
PJM Open Access Transmission Tariff 
and Resource Adequacy Agreement 
(Clean Format)

Definitions – A - B 
 
30-minute Reserve:  
 
“30-minute 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 of a request from the Office of the Interconnection dispatcher, 
and is comprised of Synchronized Reserve, Non-Synchronized Reserve and Secondary Reserve.  
 
30-minute Reserve Requirement:  
 
“30-minute Reserve Requirement” shall mean the megawatts required to be maintained in a 
Reserve Zone or Reserve Sub-zone, as Secondary Reserve, absent any increase to account for 
additional reserves scheduled to address operational uncertainty.  The 30-minute Reserve 
Requirement is calculated in accordance with the PJM Manuals.  The requirement can be 
satisfied by any combination of Synchronized Reserve, Non Synchronized Reserve or Secondary 
Reserve resources.  
 
Abnormal Condition: 
 
“Abnormal Condition” shall mean any condition on the Interconnection Facilities which, 
determined in accordance with Good Utility Practice, is: (i) outside normal operating parameters 
such that facilities are operating outside their normal ratings or that reasonable operating limits 
have been exceeded; and (ii) could reasonably be expected to materially and adversely affect the 
safe and reliable operation of the Interconnection Facilities; but which, in any case, could 
reasonably be expected to result in an Emergency Condition.  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, standing alone, constitute an Abnormal Condition. 
 
Acceleration Request: 
 
“Acceleration Request” shall mean a request pursuant to Operating Agreement, Schedule 1, 
section 1.9.4A, and the parallel provisions of Tariff, Attachment K-Appendix, section 1.9.4A, to 
accelerate or reschedule a transmission outage scheduled pursuant to Operating Agreement, 
Schedule 1, section 1.9.2 or Operating Agreement, Schedule 1, section 1.9.4, and the parallel 
provisions of Tariff, Attachment K-Appendix, section 1.9.2 or Tariff, Attachment K-Appendix, 
section 1.9.4. 
 
Affected System: 
 
“Affected System” shall mean an electric system other than the Transmission Provider’s 
Transmission System that may be affected by a proposed interconnection or on which a proposed 
interconnection or addition of facilities or upgrades may require modifications or upgrades to the 
Transmission System. 
 
Affected System Operator:

“Affected System Operator” shall mean an entity that operates an Affected System or, if the 
Affected System is under the operational control of an independent system operator or a regional 
transmission organization, such independent entity. 
 
Affiliate: 
 
“Affiliate” shall mean any two or more entities, one of which Controls the other or that are 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 an entity.  Ownership 
of publicly-traded equity securities of another entity shall not result in Control or affiliation for 
purposes of the Tariff or Operating Agreement if the securities are held as an investment, the 
holder owns (in its name or via intermediaries) less than 10 percent (10%) of the outstanding 
securities of the entity, the holder does not have representation on the entity’s board of directors 
(or equivalent managing entity) or vice versa, and the holder does not in fact exercise influence 
over day-to-day management decisions.  Unless the contrary is demonstrated to the satisfaction 
of the Members Committee, Control shall be presumed to arise from the ownership of or the 
power to vote, directly or indirectly, ten percent or more of the voting securities of such entity. 
 
Agreements: 
 
“Agreements” shall mean the Amended and Restated Operating Agreement of PJM 
Interconnection, L.L.C., the PJM Open Access Transmission Tariff, the Reliability Assurance 
Agreement, and/or other agreements between PJM Interconnection, L.L.C. and its Members. 
 
Allocated RBP UCAP MW: 
 
“Allocated RBP UCAP MW” shall mean the RBP UCAP MW allocated to a New Large Load in 
accordance with Tariff, Attachment DD-4, section IX. 
 
Ambient-Adjusted Rating: 
 
“Ambient-Adjusted Rating” (AAR) shall mean a Transmission Facility Rating that:  
 
(a) Applies to a time period of not greater than one hour. 
(b) Reflects an up-to-date forecast of ambient air temperature across the time period to 
which the rating applies. 
(c) Reflects the absence of solar heating during nighttime periods, where the local 
sunrise/sunset times used to determine daytime and nighttime periods are updated at 
least monthly, if not more frequently. 
(d) Is evaluated at least each hour, if not more frequently.   
 
Ancillary Services: 
 
“Ancillary Services” shall mean those services that are necessary to support the transmission of 
capacity and energy from resources to loads while maintaining reliable operation of the 
Transmission Provider’s Transmission System in accordance with Good Utility Practice.

Annual Demand Resource: 
 
“Annual Demand Resource” shall have the meaning specified in the Reliability Assurance 
Agreement. 
 
Annual Energy Efficiency Resource: 
 
“Annual Energy Efficiency Resource” shall have the meaning specified in the Reliability 
Assurance Agreement. 
 
Annual Resource:  
 
“Annual Resource” shall mean a Generation Capacity Resource, an Annual Energy Efficiency 
Resource or an Annual Demand Resource.  
 
Annual Resource Price Adder:  
 
“Annual Resource Price Adder” shall mean, for Delivery Years starting June 1, 2014 and ending 
May 31, 2017,  an addition to the marginal value of Unforced Capacity and the Extended 
Summer Resource Price Adder as necessary to reflect the price of Annual Resources required to 
meet the applicable Minimum Annual Resource Requirement. 
 
Annual Revenue Rate: 
 
“Annual Revenue Rate” shall mean the rate employed to assess a compliance penalty charge on a 
Curtailment Service Provider under Tariff, Attachment DD, section 11. 
 
Annual Transmission Costs: 
 
“Annual Transmission Costs” shall mean the total annual cost of the Transmission System for 
purposes of Network Integration Transmission Service shall be the amount specified in 
Attachment H for each Zone until amended by the applicable Transmission Owner or modified 
by the Commission. 
 
Applicable Laws and Regulations: 
 
“Applicable Laws and Regulations” shall mean all duly promulgated applicable federal, State 
and local laws, regulations, rules, ordinances, codes, decrees, judgments, directives, or judicial or 
administrative orders, permits and other duly authorized actions of any Governmental Authority 
having jurisdiction over the relevant parties, their respective facilities, and/or the respective 
services they provide. 
 
Applicable Regional Entity: 
 
“Applicable Regional Entity” shall mean the Regional Entity for the region in which a Network

Customer, Transmission Customer, New Service Customer, or Transmission Owner operates. 
 
Applicable Standards: 
 
“Applicable Standards” shall mean the requirements and guidelines of NERC, the Applicable 
Regional Entity, and the Control Area in which the Customer Facility is electrically located; the 
PJM Manuals; and Applicable Technical Requirements and Standards. 
 
Applicable Technical Requirements and Standards: 
 
“Applicable Technical Requirements and Standards” shall mean those certain technical 
requirements and standards applicable to interconnections of generation and/or transmission 
facilities with the facilities of an Interconnected Transmission Owner or, as the case may be and 
to the extent applicable, of an Electric Distributor, as published by Transmission Provider in a 
PJM Manual provided, however, that, with respect to any generation facilities with maximum 
generating capacity of 2 MW or less (synchronous) or 5 MW or less (inverter-based) for which 
the Interconnection Customer executes a Construction Service Agreement or Interconnection 
Service Agreement on or after March 19, 2005, “Applicable Technical Requirements and 
Standards” shall refer to the “PJM Small Generator Interconnection Applicable Technical 
Requirements and Standards.”  All Applicable Technical Requirements and Standards shall be 
publicly available through postings on Transmission Provider’s internet website. 
 
Applicant: 
 
“Applicant” shall mean an entity desiring to become a PJM Member, become a Market 
Participant, engage in market activities, or to take Transmission Service that has submitted the 
PJMSettlement credit application, PJMSettlement credit agreement and other required submittals 
as set forth in Tariff, Attachment Q. 
 
Application: 
 
“Application” shall mean a request by an Eligible Customer for transmission service pursuant to 
the provisions of the Tariff. 
 
Attachment Facilities: 
 
“Attachment Facilities” shall mean the facilities necessary to physically connect a Customer 
Facility to the Transmission System or interconnected distribution facilities. 
 
Attachment H: 
 
“Attachment H” shall refer collectively to the Attachments to the PJM Tariff with the prefix  
“H” that set forth, among other things, the Annual Transmission Rates for Network Integration 
Transmission Service in the PJM Zones. 
 
Auction Revenue Rights:

“Auction Revenue Rights” or “ARRs” shall mean the right to receive the revenue from the 
Financial Transmission Right auction, as further described in Operating Agreement, Schedule 1, 
section 7.4, and the parallel provisions of Tariff, Attachment K-Appendix, section 7.4. 
 
Auction Revenue Rights Credits: 
 
“Auction Revenue Rights Credits” shall mean the allocated share of total FTR auction revenues 
or costs credited to each holder of Auction Revenue Rights, calculated and allocated as specified 
in Operating Agreement, Schedule 1, section 7.4.3, and the parallel provisions of Tariff, 
Attachment K-Appendix, section 7.4.3. 
 
Authorized Government Agency: 
 
“Authorized Government Agency” means a regulatory body or government agency, with 
jurisdiction over PJM, the PJM Market, or any entity doing business in the PJM Market, including, 
but not limited to, the Commission, State Commissions, and state and federal attorneys general. 
 
Avoidable Cost Rate: 
 
“Avoidable Cost Rate” shall mean a component of the Market Seller Offer Cap calculated in 
accordance with Tariff, Attachment DD, section 6. 
 
Balancing Congestion Charges: 
 
“Balancing Congestion Charges” shall be equal to the sum of congestion charges collected from 
Market Participants that are purchasing energy in the Real-time Energy Market minus [the sum 
of congestion charges paid to Market Participants that are selling energy in the Real-time Energy 
Market 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, plus any charges or credits calculated pursuant to 
Operating Agreement, Schedule 1, section 3.8, and the parallel provisions of Tariff, Attachment 
K-Appendix, section 3.8, as applicable)]. 
 
Balancing Ratio: 
 
“Balancing Ratio” shall have the meaning provided in Tariff, Attachment DD, section 10A. 
 
Base Capacity Demand Resource:  
 
“Base Capacity Demand Resource” shall have the meaning specified in the Reliability Assurance 
Agreement.

Base Capacity Demand Resource Constraint: 
 
“Base Capacity Demand Resource Constraint” for the PJM Region or an LDA, shall mean, for 
the 2018/2019 and 2019/2020 Delivery Years, the maximum Unforced Capacity amount, 
determined by PJM, of Base Capacity Demand Resources and Base Capacity Energy Efficiency 
Resources that is consistent with the maintenance of reliability.  As more fully set forth in the 
PJM Manuals, PJM calculates the Base Capacity Demand Resource Constraint for the PJM 
Region or an LDA, by first determining a reference annual loss of load expectation (“LOLE”) 
assuming no Base Capacity Resources, including no Base Capacity Demand Resources or Base 
Capacity Energy Efficiency Resources.  The calculation for the PJM Region uses a daily 
distribution of loads under a range of weather scenarios (based on the most recent load forecast 
and iteratively shifting the load distributions to result in the Installed Reserve Margin established 
for the Delivery Year in question) and a weekly capacity distribution (based on the cumulative 
capacity availability distributions developed for the Installed Reserve Margin study for the 
Delivery Year in question).  The calculation for each relevant LDA uses a daily distribution of 
loads under a range of weather scenarios (based on the most recent load forecast for the Delivery 
Year in question) and a weekly capacity distribution (based on the cumulative capacity 
availability distributions developed for the Installed Reserve Margin study for the Delivery Year 
in question).  For the relevant LDA calculation, the weekly capacity distributions are adjusted to 
reflect the Capacity Emergency Transfer Limit for the Delivery Year in question. 
 
For both the PJM Region and LDA analyses, PJM then models the commitment of varying 
amounts of Base Capacity Demand Resources and Base Capacity Energy Efficiency Resources 
(displacing otherwise committed generation) as interruptible from June 1 through September 30 
and unavailable the rest of the Delivery Year in question and calculates the LOLE at each DR 
and EE level.  The Base Capacity Demand Resource Constraint is the combined amount of Base 
Capacity Demand Resources and Base Capacity Energy Efficiency Resources, stated as a 
percentage of the unrestricted annual peak load, that produces no more than a five percent 
increase in the LOLE, compared to the reference value.  The Base Capacity Demand Resource 
Constraint shall be expressed as a percentage of the forecasted peak load of the PJM Region or 
such LDA and is converted to Unforced Capacity by multiplying [the reliability target 
percentage] times [the Forecast Pool Requirement] times [the forecasted peak load of the PJM 
Region or such LDA, reduced by the amount of load served under the FRR Alternative]. 
 
Base Capacity Demand Resource Price Decrement: 
 
“Base Capacity Demand Resource Price Decrement” shall mean, for the 2018/2019 and 
2019/2020 Delivery Years, a difference between the clearing price for Base Capacity Demand 
Resources and Base Capacity Energy Efficiency Resources and the clearing price for Base 
Capacity Resources and Capacity Performance Resources, representing the cost to procure 
additional Base Capacity Resources or Capacity Performance Resources out of merit order when 
the Base Capacity Demand Resource Constraint is binding. 
 
Base Capacity Energy Efficiency Resource:

“Base Capacity Energy Efficiency Resource” shall have the meaning specified in the Reliability 
Assurance Agreement. 
 
Base Capacity Resource:  
 
“Base Capacity Resource” shall mean a Capacity Resource as described in Tariff, Attachment 
DD, section 5.5A(b). 
 
Base Capacity Resource Constraint: 
 
“Base Capacity Resource Constraint” for the PJM Region or an LDA, shall mean, for the 
2018/2019 and 2019/2020 Delivery Years, the maximum Unforced Capacity amount, determined 
by PJM, of Base Capacity Resources, including Base Capacity Demand Resources and Base 
Capacity Energy Efficiency Resources, that is consistent with the maintenance of reliability.  As 
more fully set forth in the PJM Manuals, PJM calculates the above Base Capacity Resource 
Constraint for the PJM Region or an LDA, by first determining a reference annual loss of load 
expectation (“LOLE”) assuming no Base Capacity Resources, including no Base Capacity 
Demand Resources or Base Capacity Energy Efficiency Resources.  The calculation for the PJM 
Region uses the weekly load distribution from the Installed Reserve Margin study for the 
Delivery Year in question (based on the most recent load forecast and iteratively shifting the load 
distributions to result in the Installed Reserve Margin established for the Delivery Year in 
question) and a weekly capacity distribution (based on the cumulative capacity availability 
distributions developed for the Installed Reserve Margin study for the Delivery Year in 
question).  The calculation for each relevant LDA uses a weekly load distribution (based on the 
Installed Reserve Margin study and the most recent load forecast for the Delivery Year in 
question) and a weekly capacity distribution (based on the cumulative capacity availability 
distributions developed for the Installed Reserve Margin study for the Delivery Year in 
question).  For the relevant LDA calculation, the weekly capacity distributions are adjusted to 
reflect the Capacity Emergency Transfer Limit for the Delivery Year in question.  Additionally, 
for the PJM Region and relevant LDA calculation, the weekly capacity distributions are adjusted 
to reflect winter ratings. 
 
For both the PJM Region and LDA analyses, PJM models the commitment of an amount of Base 
Capacity Demand Resources and Base Capacity Energy Efficiency Resources equal to the Base 
Capacity Demand Resource Constraint (displacing otherwise committed generation).  PJM then 
models the commitment of varying amounts of Base Capacity Resources (displacing otherwise 
committed generation) as unavailable during the peak week of winter and available the rest of 
the Delivery Year in question and calculates the LOLE at each Base Capacity Resource level.  
The Base Capacity Resource Constraint is the combined amount of Base Capacity Demand 
Resources, Base Capacity Energy Efficiency Resources and Base Capacity Resources, stated as a 
percentage of the unrestricted annual peak load, that produces no more than a ten percent 
increase in the LOLE, compared to the reference value.  The Base Capacity Resource Constraint 
shall be expressed as a percentage of the forecasted peak load of the PJM Region or such LDA 
and is converted to Unforced Capacity by multiplying [the reliability target percentage] times 
[one minus the pool-wide average EFORd] times [the forecasted peak load of the PJM Region or 
such LDA, reduced by the amount of load served under the FRR Alternative].

Base Capacity Resource Price Decrement: 
 
“Base Capacity Resource Price Decrement” shall mean, for the 2018/2019 and 2019/2020 
Delivery Years, a difference between the clearing price for Base Capacity Resources and the 
clearing price for Capacity Performance Resources, representing the cost to procure additional 
Capacity Performance Resources out of merit order when the Base Capacity Resource Constraint 
is binding. 
 
Base Load Generation Resource 
 
“Base Load Generation Resource” shall mean a Generation Capacity Resource that operates at 
least 90 percent of the hours that it is available to operate, as determined by the Office of the 
Interconnection in accordance with the PJM Manuals. 
 
Base Offer Segment: 
 
“Base Offer Segment” shall mean a component of a Sell Offer based on an existing Generation 
Capacity Resource, equal to the Unforced Capacity of such resource, as determined in 
accordance with the PJM Manuals.  If the Sell Offers of multiple Market Sellers are based on a 
single Existing Generation Capacity Resource, the Base Offer Segments of such Market Sellers 
shall be determined pro rata based on their entitlements to Unforced Capacity from such 
resource. 
 
Base Residual Auction:  
 
“Base Residual Auction” shall mean the auction conducted three years prior to the start of the 
Delivery Year to secure commitments from Capacity Resources as necessary to satisfy any 
portion of the Unforced Capacity Obligation of the PJM Region not satisfied through Self-
Supply. 
 
Batch Load Economic Load Response Participant Resource: 
 
“Batch Load Economic Load Response Participant Resource” shall mean an Economic Load 
Response Participant Resource that has a cyclical production process such that at most times 
during the process it is consuming energy, but at consistent regular intervals, ordinarily for 
periods of less than ten minutes, it reduces its consumption of energy for its production processes 
to minimal or zero megawatts. 
 
Behind The Meter Generation: 
 
“Behind The Meter Generation” shall refer to a generation 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 has 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 (ii) in an 
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 Service: 
 
“Black Start Service” shall mean the capability of generating units to start without an outside 
electrical supply or the demonstrated ability of a generating unit with a high operating factor 
(subject to Transmission Provider concurrence) to automatically remain operating at reduced 
levels when disconnected from the grid. 
 
Border Yearly Charge: 
 
“Border Yearly Charge” shall mean the yearly charge determined in accordance with Tariff, 
Schedule 7. 
 
Breach: 
 
“Breach” shall mean the failure of a party to perform or observe any material term or condition 
of Tariff, Part IV or Tariff, Part VI, or any agreement entered into thereunder as described in the 
relevant provisions of such agreement. 
 
Breaching Party: 
 
“Breaching Party” shall mean a party that is in Breach of Tariff, Part IV or Tariff, Part VI and/or 
an agreement entered into thereunder. 
 
Bring Your Own New Capacity: 
 
“Bring Your Own New Capacity” or “BYONC” shall mean megawatts of Unforced Capacity 
that meet the eligibility criteria set forth in Tariff, Attachment DD-4, section VI.  Megawatts of 
Unforced Capacity that have been previously included in an FRR Capacity Plan prior to the 
2027/2028 Delivery Year do not qualify as BYONC. However, to the extent three consecutive 
Delivery Years meet the requirements of Tariff, Attachment DD-4, section IV(b)(iii), then 
BYONC that has been included previously in an FRR Capacity Plan prior to the first Delivery 
Year for which the requirements of Tariff, Attachment DD-4, section IV(b)(iii) are not met and 
(2) meet the eligibility criteria set forth in Tariff, Attachment DD-4, section VI do not qualify as 
BYONC. 
 
Business Day: 
 
“Business Day” shall mean a day in which the Federal Reserve System is open for business and 
is not a scheduled PJM holiday. 
 
Buy Bid:

“Buy Bid” shall mean a bid to buy Capacity Resources in any Incremental Auction. 
 
Buyer-Side Market Power: 
 
“Buyer-Side Market Power” shall mean the ability of Capacity Market Sellers with a Load 
Interest to suppress RPM Auction clearing prices for the overall benefit of their (and/or affiliates) 
portfolio of generation and load.

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.

Eligible New Large Loads: 
 
“Eligible New Large Loads” shall mean a New Large Load eligible to provide Interim Resource 
Adequacy Service in accordance with Tariff, Attachment DD-4, section V. 
 
Eligible New Large Load Amount: 
 
“Eligible New Large Load Amount” shall mean the total megawatt value of load an Eligible 
New Large Load may be required to make available for Interim Resource Adequacy Service in 
an Electric Distributor zone/area. 
 
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 participates in the PJM Energy, Capacity 
and/or Ancillary Services markets as a Market Participant.  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.   
 
Excluded LDA New Large Load Amounts: 
 
“Excluded LDA New Large Load Amounts” shall mean, converted in UCAP terms by estimating 
the impact on required imports to a Locational Deliverability Area and exclusive of any load in

an FRR Service Area, [the sum of all New Large Loads in the relevant Locational Deliverability 
Area that were included in the load forecast for the relevant Delivery Year] minus [New Large 
Loads in the relevant Locational Deliverability Area that were included in the load forecast used 
for the 2028/2029 Delivery Year] minus [the total MW quantity of New Large Load that is added 
on or after the 2029/2030 Delivery Year and is (i) in an arrangement with BYONC in the 
Locational Deliverability Area or (ii) assigned Allocated RBP UCAP MW in Locational 
Deliverability Area]. 
 
Excluded RTO New Large Load Amounts 
 
“Excluded RTO New Large Load Amounts” shall mean, converted in UCAP terms by using the 
Forecast Pool Requirement and exclusive of any load in an FRR Service Area, [the sum of all 
New Large Loads across the PJM Region in the load forecast for the relevant Delivery Year] 
minus [New Large Loads across the PJM Region that were included in the load forecast used for 
the 2028/2029 Delivery Year] minus [the total MW quantity of New Large Load that is added on 
or after the 2029/2030 Delivery Year and is (i) in an arrangement with BYONC in the RTO or 
(ii) assigned Allocated RBP UCAP MW in the RTO]. 
 
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 – I – J - K 
 
IDR Transfer Agreement: 
 
“IDR Transfer Agreement” shall mean an agreement to transfer, subject to the terms of Tariff, 
Part VI, section 237, Incremental Deliverability Rights to a party for the purpose of eliminating 
or reducing the need for Local or Network Upgrades that would otherwise have been the 
responsibility of the party receiving such rights. 
 
Immediate-need Reliability Project: 
 
“Immediate-need Reliability Project” shall have the same meaning provided in the Operating 
Agreement. 
 
Inadvertent Interchange: 
 
“Inadvertent Interchange” shall mean the difference between net actual energy flow and net 
scheduled energy flow into or out of the individual Control Areas operated by PJM. 
 
Incidental Expenses: 
 
“Incidental Expenses” shall mean those expenses incidental to the performance of construction 
pursuant to an Interconnection Construction Service Agreement, including, but not limited to, the 
expense of temporary construction power, telecommunications charges, Interconnected 
Transmission Owner expenses associated with, but not limited to, document preparation, design 
review, installation, monitoring, and construction-related operations and maintenance for the 
Customer Facility and for the Interconnection Facilities. 
 
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, 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. 
 
Incremental Auction Revenue Rights: 
 
“Incremental Auction Revenue Rights” shall mean the additional Auction Revenue Rights, not 
previously feasible, created by the addition of Incremental Rights-Eligible Required 
Transmission Enhancements, Merchant Transmission Facilities, or of one or more Customer-
Funded Upgrades.  
 
Incremental Available Transfer Capability Revenue Rights: 
 
“Incremental Available Transfer Capability Revenue Rights” shall mean the rights to revenues 
that are derived from incremental Available Transfer Capability created by the addition of 
Merchant Transmission Facilities or of one of more Customer-Funded Upgrades. 
 
Incremental Capacity Transfer Right: 
 
“Incremental Capacity Transfer Right” shall mean a Capacity Transfer Right allocated to a 
Generation Interconnection Customer or Transmission Interconnection Customer obligated to 
fund a transmission facility or upgrade, to the extent such upgrade or facility increases the 
transmission import capability into a Locational Deliverability Area, or a Capacity Transfer 
Right allocated to a Responsible Customer in accordance with Tariff, Schedule 12A.  
 
Incremental Deliverability Rights (IDRs): 
 
“Incremental Deliverability Rights” or “IDRs” shall mean the rights to the incremental ability, 
resulting from the addition of Merchant Transmission Facilities, to inject energy and capacity at 
a point on the Transmission System, such that the injection satisfies the deliverability 
requirements of a Capacity Resource. Incremental Deliverability Rights may be obtained by a 
generator or a Generation Interconnection Customer, pursuant to an IDR Transfer Agreement, to 
satisfy, in part, the deliverability requirements necessary to obtain Capacity Interconnection 
Rights. 
 
Incremental Energy Offer: 
 
“Incremental Energy Offer” shall mean the cost in dollars per MWh of providing an additional 
MWh from a synchronized unit. It consists primarily of the cost of fuel, as determined by the 
unit’s incremental heat rate (adjusted by the performance factor) times the fuel cost. It also 
includes operating costs, Maintenance Adders, emissions allowances, tax credits, and energy 
market opportunity costs. 
 
Incremental Multi-Driver Project:

“Incremental Multi-Driver Project” shall have the same meaning provided in the Operating 
Agreement. 
 
Incremental Rights-Eligible Required Transmission Enhancements: 
 
“Incremental Rights-Eligible Required Transmission Enhancements” shall mean Regional 
Facilities and Necessary Lower Voltage Facilities or Lower Voltage Facilities (as defined in 
Tariff, Schedule 12) and meet one of the following criteria: (1) cost responsibility is assigned to 
non-contiguous Zones that are not directly electrically connected; or (2) cost responsibility is 
assigned to Merchant Transmission Providers that are Responsible Customers. 
 
Increment Offer: 
 
“Increment Offer” shall mean a type of Virtual Transaction that is an offer to sell energy at a 
specified location in the Day-ahead Energy Market.  A cleared Increment Offer results in 
scheduled generation at the specified location in the Day-ahead Energy Market. 
 
Independent Auditor: 
 
“Independent Auditor” shall mean an external accountant or external accounting firm who is not 
an employee of, not otherwise related to, not obligated to, has no interest in, and is independent 
in the performance of professional services for, the entity he/she/it is auditing, its management 
and/or its owners. 
 
Initial Operation: 
 
“Initial Operation” shall mean the commencement of operation of the Customer Facility and 
Customer Interconnection Facilities after satisfaction of the conditions of Tariff, Attachment O- 
Appendix 2, section 1.4 (an Interconnection Service Agreement). 
 
Integer Relaxation: 
 
“Integer Relaxation” shall mean the process by which the commitment status variable for an 
Eligible Fast-Start Resource is allowed to vary between zero and one, inclusive of zero and one, 
as further described in Tariff, Attachment K-Appendix, section 2.2. 
 
Interconnected Entity: 
 
“Interconnected Entity” shall mean either the Interconnection Customer or the Interconnected 
Transmission Owner; Interconnected Entities shall mean both of them. 
 
Interconnected Transmission Owner: 
 
“Interconnected Transmission Owner” shall mean the Transmission Owner to whose 
transmission facilities or distribution facilities Customer Interconnection Facilities are, or as the 
case may be, a Customer Facility is, being directly connected.  When used in an Interconnection

Construction Service Agreement, the term may refer to a Transmission Owner whose facilities 
must be upgraded pursuant to the Facilities Study, but whose facilities are not directly 
interconnected with those of the Interconnection Customer. 
 
Interconnection Construction Service Agreement: 
 
“Interconnection Construction Service Agreement” shall mean the agreement entered into by an 
Interconnection Customer, Interconnected Transmission Owner and the Transmission Provider 
pursuant to Tariff, Part VI, Subpart B and in the form set forth in Tariff, Attachment P, relating 
to construction of Attachment Facilities, Network Upgrades, and/or Local Upgrades and 
coordination of the construction and interconnection of an associated Customer Facility.  A 
separate Interconnection Construction Service Agreement will be executed with each 
Transmission Owner that is responsible for construction of any Attachment Facilities, Network 
Upgrades, or Local Upgrades associated with interconnection of a Customer Facility. 
 
Interconnection Customer: 
 
“Interconnection Customer” shall mean a Generation Interconnection Customer and/or a 
Transmission Interconnection Customer. 
 
Interconnection Facilities: 
 
“Interconnection Facilities” shall mean the Transmission Owner Interconnection Facilities and 
the Customer Interconnection Facilities. 
 
Interconnection Feasibility Study: 
 
“Interconnection Feasibility Study” shall mean either a Generation Interconnection Feasibility 
Study or Transmission Interconnection Feasibility Study. 
 
Interconnection Party: 
 
“Interconnection Party” shall mean a Transmission Provider, Interconnection Customer, or the 
Interconnected Transmission Owner. Interconnection Parties shall mean all of them. 
 
Interconnection Request: 
 
“Interconnection Request” shall mean a Generation Interconnection Request, a Transmission 
Interconnection Request and/or an IDR Transfer Agreement. 
 
Interconnection Service: 
 
“Interconnection Service” shall mean the physical and electrical interconnection of the Customer 
Facility with the Transmission System pursuant to the terms of Tariff, Part IV and Tariff, Part VI 
and the Interconnection Service Agreement entered into pursuant thereto by Interconnection 
Customer, the Interconnected Transmission Owner and Transmission Provider.

Interconnection Service Agreement: 
 
“Interconnection Service Agreement” shall mean an agreement among the Transmission 
Provider, an Interconnection Customer and an Interconnected Transmission Owner regarding 
interconnection under Tariff, Part IV and Tariff, Part VI. 
 
Interconnection Studies: 
 
“Interconnection Studies” shall mean the Interconnection Feasibility Study, the System Impact 
Study, and the Facilities Study described in Tariff, Part IV and Tariff, Part VI. 
 
Interface Pricing Point: 
 
“Interface Pricing Point” shall have the meaning specified in Operating Agreement, Schedule 1, 
section 2.6A, and the parallel provisions of Tariff, Attachment K-Appendix, section 2.6A. 
 
Interim Resource Adequacy Service: 
 
“Interim Resource Adequacy Service” shall mean a load reduction service through which New 
Large Loads reduce load as directed by the applicable Electric Distributor in response to an 
Interim Resource Adequacy Service Action requested by the Office of the Interconnection. Such 
reductions in load may be eligible for compensation pursuant to Attachment DD-4, section X. 
 
Interim Resource Adequacy Service Action: 
 
“Interim Resource Adequacy Service Action” shall mean an Operating Instruction, as defined by 
NERC, issued from the Office of the Interconnection to reduce load prior to calling on Pre-
Emergency Load Management Reductions after determining that available economic real-time 
supply may not be sufficient to maintain reserves to meet applicable Reserve Requirements 
and/or Interconnection Reliability Operating Limits within prescribed limits and prevent 
cascading outages. 
 
Intermittent Resource: 
 
“Intermittent Resource” shall mean a Generation Capacity Resource with output that can vary as 
a function of its energy source, such as wind, solar, run of river hydroelectric power and other 
renewable resources.  
 
Internal Credit Score: 
 
“Internal Credit Score” shall mean a composite numerical score determined by PJMSettlement 
using quantitative and qualitative metrics to estimate various predictors of a credit event 
happening to a Market Participant that may trigger a credit event. 
 
Internal Market Buyer:

“Internal Market Buyer” shall mean a Market Buyer making purchases of energy from the PJM 
Interchange Energy Market for ultimate consumption by end-users inside the PJM Region that 
are served by Network Transmission Service. 
 
Interregional Transmission Project: 
 
“Interregional Transmission Project” shall mean transmission facilities that would be located 
within two or more neighboring transmission planning regions and are determined by each of 
those regions to be a more efficient or cost effective solution to regional transmission needs. 
 
Interruption: 
 
“Interruption” shall mean a reduction in non-firm transmission service due to economic reasons 
pursuant to Tariff, Part II, section 14.7. 
 
IROL Critical Resource: 
 
“IROL Critical Resource” shall mean a generation resource that the Office of the Interconnection 
designates, pursuant to NERC Reliability Standards, as having an interconnection reliability 
operating limit that, if violated, could lead to instability, uncontrolled separation, or cascading 
outages that adversely impact the reliability of the bulk electric system.   
 
Jointly Owned Cross-Subsidized Capacity Resource: 
 
“Jointly Owned Cross-Subsidized Capacity Resource” shall mean a Capacity Resource that is 
supported by a facility that is jointly owned, where at least one owner is entitled to or receives a 
State Subsidy associated with such Capacity Resource, and therefore shall be considered a 
Capacity Resource with State Subsidy; provided however, in the event that the material rights 
and obligations of such generating facility are in pari passu, meaning that such rights and 
obligations are allocated among the owners pro rata based on ownership share, only Capacity 
Resources of those owners entitled to receive or receiving a State Subsidy shall have their share 
of such resource considered a Capacity Resource with a State Subsidy and Capacity Resources of 
owners not entitled to a State Subsidy shall not be considered a Capacity Resource with a State 
Subsidy.  Each of these designations may be overcome by either Capacity Market Seller 
demonstrating to the Office of Interconnection, with advice and input from the Market 
Monitoring Unit, that there is no cross-subsidization or the Office of the Interconnection, with 
review and input from the Market Monitor, finds based on sufficient evidence, that there is cross-
subsidization.

Definitions – L – M – N 
 
Large Load: 
 
“Large Load” shall have the meaning provided in the Reliability Assurance Agreement. 
 
Legacy Policy: 
 
“Legacy Policy” shall mean any legislative, executive, or regulatory action that specifically 
directs a payment outside of PJM Markets to a designated or prospective Generation Capacity 
Resource and the enactment of such action predates October 1, 2021, regardless of when any 
implementing governmental action to effectuate the action to direct payment outside of PJM 
Markets occurs. 
 
Limited Demand Resource:  
 
“Limited Demand Resource” shall have the meaning specified in the Reliability Assurance 
Agreement. 
 
Limited Demand Resource Reliability Target:  
 
“Limited Demand Resource Reliability Target” for the PJM Region or an LDA, shall mean the 
maximum amount of Limited Demand Resources determined by PJM to be consistent with the 
maintenance of reliability, stated in Unforced Capacity that shall be used to calculate the 
Minimum Extended Summer Demand Resource Requirement for Delivery Years through May 
31, 2017 and the Limited Resource Constraint for the 2017/2018 and 2018/2019 Delivery Years 
for the PJM Region or such LDA.  As more fully set forth in the PJM Manuals, PJM calculates 
the Limited Demand Resource Reliability Target by first:  i) testing the effects of the ten-
interruption requirement by comparing possible loads on peak days under a range of weather 
conditions (from the daily load forecast distributions for the Delivery Year in question) against 
possible generation capacity on such days under a range of conditions (using the cumulative 
capacity distributions employed in the Installed Reserve Margin study for the PJM Region and in 
the Capacity Emergency Transfer Objective study for the relevant LDAs for such Delivery Year) 
and, by varying the assumed amounts of DR that is committed and displaces committed 
generation, determines the DR penetration level at which there is a ninety percent probability 
that DR will not be called (based on the applicable operating reserve margin for the PJM Region 
and for the relevant LDAs) more than ten times over those peak days;  ii) testing the six-hour 
duration requirement by calculating the MW difference between the highest hourly unrestricted 
peak load and seventh highest hourly unrestricted peak load on certain high peak load days (e.g., 
the annual peak, loads above the weather normalized peak, or days where load management was 
called) in recent years, then dividing those loads by the forecast peak for those years and 
averaging the result; and (iii) (for the 2016/2017 and 2017/2018 Delivery Years) testing the 
effects of the six-hour duration requirement by comparing possible hourly loads on peak days 
under a range of weather conditions (from the daily load forecast distributions for the Delivery 
Year in question) against possible generation capacity on such days under a range of conditions 
(using a Monte Carlo model of hourly capacity levels that is consistent with the capacity model

employed in the Installed Reserve Margin study for the PJM Region and in the Capacity 
Emergency Transfer Objective study for the relevant LDAs for such Delivery Year) and, by 
varying the assumed amounts of DR that is committed and displaces committed generation, 
determines the DR penetration level at which there is a ninety percent probability that DR will 
not be called (based on the applicable operating reserve margin for the PJM Region and for the 
relevant LDAs) for more than six hours over any one or more of the tested peak days.  Second, 
PJM adopts the lowest result from these three tests as the Limited Demand Resource Reliability 
Target.  The Limited Demand Resource Reliability Target shall be expressed as a percentage of 
the forecasted peak load of the PJM Region or such LDA and is converted to Unforced Capacity 
by multiplying [the reliability target percentage] times [the Forecast Pool Requirement] times 
[the DR Factor] times [the forecasted peak load of the PJM Region or such LDA, reduced by the 
amount of load served under the FRR Alternative]. 
 
Limited Resource Constraint: 
 
“Limited Resource Constraint” shall mean, for the 2017/2018 Delivery Year and for FRR 
Capacity Plans the 2017/2018 and Delivery Years, for the PJM Region or each LDA for which 
the Office of the Interconnection is required under Tariff, Attachment DD, section 5.10(a) to 
establish a separate VRR Curve for a Delivery Year, a limit on the total amount of Unforced 
Capacity that can be committed as Limited Demand Resources for the 2017/2018 Delivery Year 
in the PJM Region or in such LDA, calculated as the Limited Demand Resource Reliability 
Target for the PJM Region or such LDA, respectively, minus the Short Term Resource 
Procurement Target for the PJM Region or such LDA, respectively. 
 
Limited Resource Price Decrement: 
“Limited Resource Price Decrement” shall mean, for the 2017/2018 Delivery Year, a difference 
between the clearing price for Limited Demand Resources and the clearing price for Extended 
Summer Demand Resources and Annual Resources, representing the cost to procure additional 
Extended Summer Demand Resources or Annual Resources out of merit order when the Limited 
Resource Constraint is binding. 
 
List of Approved Contractors: 
 
“List of Approved Contractors” shall mean a list developed by each Transmission Owner and 
published in a PJM Manual of (a) contractors that the Transmission Owner considers to be 
qualified to install or construct new facilities and/or upgrades or modifications to existing 
facilities on the Transmission Owner’s system, provided that such contractors may include, but 
need not be limited to, contractors that, in addition to providing construction services, also 
provide design and/or other construction-related services, and (b) manufacturers or vendors of 
major transmission-related equipment (e.g., high-voltage transformers, transmission line, circuit 
breakers) whose products the Transmission Owner considers acceptable for installation and use 
on its system. 
 
Load Interest:

“Load Interest” shall mean, for the purposes of the minimum offer price rule, responsibility for 
serving load within the PJM Region, whether by the Capacity Market Seller, an affiliate of the 
Capacity Market Seller, or by an entity with which the Capacity Market Seller is in contractual 
privity with respect to the subject Generation Capacity Resource. 
 
Load Management: 
 
“Load Management” shall mean a Demand Resource (“DR”) as defined in the Reliability 
Assurance Agreement. 
 
Load Management Event: 
 
“Load Management Event” shall mean a) a single temporally contiguous dispatch of Demand 
Resources in a Compliance Aggregation Area during an Operating Day, or b) multiple dispatches 
of Demand Resources in a Compliance Aggregation Area during an Operating Day that are 
temporally contiguous.  
 
Load Ratio Share: 
 
“Load Ratio Share” shall mean the ratio of a Transmission Customer’s Network Load to the 
Transmission Provider’s total load. 
 
Load Reduction Event: 
 
“Load Reduction Event” shall mean a reduction in demand by a Member or Special Member for 
the purpose of participating in the PJM Interchange Energy Market. 
 
Load Serving Charging Energy:  
 
“Load Serving Charging Energy” shall mean energy that is purchased from the PJM Interchange 
Energy Market and stored in an Energy Storage Resource or Open-Loop Hybrid Resource for 
later resale to end-use load. 
 
Load Serving Entity (LSE): 
 
“Load Serving Entity” or “LSE” shall have the meaning specified in the Reliability Assurance 
Agreement. 
 
Load Shedding: 
 
“Load Shedding” shall mean the systematic reduction of system demand by temporarily 
decreasing load in response to transmission system or area capacity shortages, system instability, 
or voltage control considerations under Tariff, Part II or Part III. 
 
Local Upgrades:

“Local Upgrades” shall mean modifications or additions of facilities to abate any local thermal 
loading, voltage, short circuit, stability or similar engineering problem caused by the 
interconnection and delivery of generation to the Transmission System.  Local Upgrades shall 
include: 
 
 
(i) Direct Connection Local Upgrades which are Local Upgrades that only serve the 
Customer Interconnection Facility and have no impact or potential impact on the Transmission 
System until the final tie-in is complete; and  
 
 
(ii) Non-Direct Connection Local Upgrades which are parallel flow Local Upgrades that 
are not Direct Connection Local Upgrades. 
 
Location: 
 
“Location” as used in the Economic Load Response rules shall mean an end-use customer site as 
defined by the relevant electric distribution company account number. 
 
LOC Deviation:   
 
“LOC Deviation,” shall mean, for units other than wind units, the LOC Deviation shall equal the 
desired megawatt amount for the resource determined according to the point on the Final Offer 
curve corresponding to the Real-time Settlement Interval real-time Locational Marginal Price at 
the resource’s bus and adjusted for any reduction in megawatts due to Regulation, Synchronized 
Reserve, or Secondary Reserve assignments and limited to the lesser of the unit’s Economic 
Maximum or the unit’s Generation Resource Maximum Output, minus the actual output of the 
unit.  For wind units, the LOC Deviation shall mean the deviation of the generating unit’s output 
equal to the lesser of the PJM forecasted output for the unit or the desired megawatt amount for 
the resource determined according to the point on the Final Offer curve corresponding to the 
Real-time Settlement Interval integrated real-time Locational Marginal Price at the resource’s 
bus, and shall be limited to the lesser of the unit’s Economic Maximum or the unit’s Generation 
Resource Maximum Output, minus the actual output of the unit. 
 
Locational Deliverability Area (LDA): 
 
“Locational Deliverability Area” or “LDA” shall mean a geographic area within the PJM Region 
that has limited transmission capability to import capacity to satisfy such area’s reliability 
requirement, as determined by the Office of the Interconnection in connection with preparation 
of the Regional Transmission Expansion Plan, and as specified in Reliability Assurance 
Agreement, Schedule 10.1. 
 
Locational Deliverability Area Reliability Requirement: 
 
“Locational Deliverability Area Reliability Requirement” shall mean the projected internal 
capacity in the Locational Deliverability Area plus the Capacity Emergency Transfer Objective 
for the Delivery Year, as determined by the Office of the Interconnection in connection with

preparation of the Regional Transmission Expansion Plan, less the minimum internal resources 
required for all FRR Entities in such Locational Deliverability Area. 
 
Locational Price Adder: 
 
“Locational Price Adder” shall mean an addition to the marginal value of Unforced Capacity 
within an LDA as necessary to reflect the price of Capacity Resources required to relieve 
applicable binding locational constraints.  
 
Locational Reliability Charge: 
 
“Locational Reliability Charge” shall have the meaning specified in the Reliability Assurance 
Agreement.  
 
Locational UCAP: 
 
“Locational UCAP” shall mean unforced capacity that a Member with available uncommitted 
capacity sells in a bilateral transaction to a Member that previously committed capacity through 
an RPM Auction but now requires replacement capacity to fulfill its RPM Auction commitment.  
The Locational UCAP Seller retains responsibility for performance of the resource providing 
such replacement capacity.   
 
Locational UCAP Seller: 
 
“Locational UCAP Seller” shall mean a Member that sells Locational UCAP. 
 
Long-lead Project: 
 
“Long-lead Project” shall have the same meaning provided in the Operating Agreement. 
 
Long-Term Firm Point-To-Point Transmission Service: 
 
“Long-Term Firm Point-To-Point Transmission Service” shall mean firm Point-To-Point 
Transmission Service under Tariff, Part II with a term of one year or more. 
 
Loss Price: 
 
“Loss Price” shall mean the loss component of the Locational Marginal Price, which is the effect 
on transmission loss 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 losses, calculated 
as specified in Operating Agreement, Schedule 1, section 2, and the parallel provisions of Tariff, 
Attachment K-Appendix, section 2. 
 
M2M Flowgate:

“M2M Flowgate” shall have the meaning provided in the Joint Operating Agreement between 
the Midcontinent Independent Transmission System Operator, Inc. and PJM Interconnection, 
L.L.C. 
 
Maintenance Adder:   
 
“Maintenance Adder” shall mean an adder that may be included to account for variable operation 
and maintenance expenses in a Market Seller’s Fuel Cost Policy.  The Maintenance Adder is 
calculated in accordance with the applicable provisions of PJM Manual 15, and may only include 
expenses incurred as a result of electric production. 
 
Manual Load Dump Action: 
 
“Manual Load Dump Action” shall mean an Operating Instruction, as defined by NERC, from 
PJM to shed firm load when the PJM Region cannot provide adequate capacity to meet the PJM 
Region’s load and tie schedules, or to alleviate critically overloaded transmission lines or other 
equipment. 
 
Manual Load Dump Warning: 
 
“Manual Load Dump Warning” shall mean a notification from PJM to warn Members of an 
increasingly critical condition of present operations that may require manually shedding load. 
 
Marginal Value:  
 
“Marginal Value” shall mean the incremental change in system dispatch costs, measured as a 
$/MW value incurred by providing one additional MW of relief to the transmission constraint. 
 
Market Monitor: 
 
“Market Monitor” means the head of the Market Monitoring Unit. 
 
Market Monitoring Unit or MMU: 
 
“Market Monitoring Unit” or “MMU” means the independent Market Monitoring Unit defined in 
18 CFR § 35.28(a)(7) and established under the PJM Market Monitoring Plan (Attachment M) to 
the PJM Tariff that is responsible for implementing the Market Monitoring Plan, including the 
Market Monitor.  The Market Monitoring Unit may also be referred to as the IMM or 
Independent Market Monitor for PJM 
 
Market Monitoring Unit Advisory Committee or MMU Advisory Committee: 
 
“Market Monitoring Unit Advisory Committee” or “MMU Advisory Committee” shall mean the 
committee established under Tariff, Attachment M, section III.H. 
 
Market Operations Center:

“Market Operations Center” shall mean the equipment, facilities and personnel used by or on 
behalf of a Market Participant to communicate and coordinate with the Office of the 
Interconnection in connection with transactions in the PJM Interchange Energy Market or the 
operation of the PJM Region. 
 
Market Participant: 
 
“Market Participant” shall mean a Market Buyer, a Market Seller, an Economic Load Response 
Participant, or all three, except when such term is used in Tariff, Attachment M, in which case 
Market Participant shall mean an entity that generates, transmits, distributes, purchases, or sells 
electricity, ancillary services, or any other product or service provided under the PJM Tariff or 
Operating Agreement within, into, out of, or through the PJM Region, but it shall not include an 
Authorized Government Agency that consumes energy for its own use but does not purchase or 
sell energy at wholesale. 
 
Market Participant Energy Injection: 
 
“Market Participant Energy Injection” shall mean transactions in the Day-ahead Energy Market 
and Real-time Energy Market, including but not limited to Day-ahead generation schedules, real-
time generation output, Increment Offers, internal bilateral transactions and import transactions, 
as further described in the PJM Manuals.  
 
Market Participant Energy Withdrawal: 
 
“Market Participant Energy Withdrawal” shall mean transactions in the Day-ahead Energy 
Market and Real-time Energy Market, including but not limited to Demand Bids, Decrement 
Bids, real-time load (net of Behind The Meter Generation expected to be operating, but not to be 
less than zero), internal bilateral transactions and Export Transactions, as further described in the 
PJM Manuals.  
 
Market Revenue Neutrality Offset:  
 
“Market Revenue Neutrality Offset” shall mean the revenue in excess of the cost for a resource 
from the energy, Synchronized Reserve, Non-Synchronized Reserve, and Secondary Reserve 
markets realized from an increase in real-time market megawatt assignment from a day-ahead 
market megawatt assignment in any of these markets due to the decrease in the real-time reserve 
market megawatt assignment from a day-ahead reserve market megawatt assignment in any of 
the reserve markets. 
 
Market Seller Offer Cap: 
 
“Market Seller Offer Cap” shall mean a maximum offer price applicable to certain Market 
Sellers under certain conditions, as determined in accordance with Tariff, Attachment DD. 
section 6 and Tariff, Attachment M-Appendix, section II.E.

Market Violation: 
 
“Market Violation” shall mean a tariff violation, violation of a Commission-approved order, rule 
or regulation, market manipulation, or inappropriate dispatch that creates substantial concerns 
regarding unnecessary market inefficiencies, as defined in 18 C.F.R. § 35.28(b)(8). 
 
Material Modification: 
 
“Material Modification” shall mean any modification to an Interconnection Request that has a 
material adverse effect on the cost or timing of Interconnection Studies related to, or any 
Network Upgrades or Local Upgrades needed to accommodate, any Interconnection Request 
with a later Queue Position. 
 
Maximum Daily Starts: 
 
“Maximum Daily Starts” shall mean the maximum number of times that a generating unit can be 
started in an Operating Day under normal operating conditions. 
 
Maximum Emergency: 
 
“Maximum Emergency” shall mean the designation of all or part of the output of a generating 
unit for which the designated output levels may require extraordinary procedures and therefore 
are available to the Office of the Interconnection only when the Office of the Interconnection 
declares a Maximum Generation Emergency and requests generation designated as Maximum 
Emergency to run.  The Office of the Interconnection shall post on the PJM website the 
aggregate amount of megawatts that are classified as Maximum Emergency. 
 
Maximum Facility Output: 
 
“Maximum Facility Output” shall mean the maximum (not nominal) net electrical power output 
in megawatts, specified in the Interconnection Service Agreement, after supply of any parasitic 
or host facility loads, that a Generation Interconnection Customer’s Customer Facility is 
expected to produce, provided that the specified Maximum Facility Output shall not exceed the 
output of the proposed Customer Facility that Transmission Provider utilized in the System 
Impact Study. 
 
Maximum Generation Emergency: 
 
“Maximum Generation Emergency” shall mean an Emergency declared by the Office of the 
Interconnection to address either a generation or transmission emergency in which the Office of 
the Interconnection anticipates requesting one or more Generation Capacity Resources, or Non-
Retail Behind The Meter Generation resources to operate at its maximum net or gross electrical 
power output, subject to the equipment stress limits for such Generation Capacity Resource or 
Non-Retail Behind The Meter resource in order to manage, alleviate, or end the Emergency. 
 
Maximum Generation Emergency Alert:

“Maximum Generation Emergency Alert” shall mean an alert issued by the Office of the 
Interconnection to notify PJM Members, Transmission Owners, resource owners and operators, 
customers, and regulators that a Maximum Generation Emergency may be declared, for any 
Operating Day in either, as applicable, the Day-ahead Energy Market or the Real-time Energy 
Market, for all or any part of such Operating Day. 
 
Maximum Run Time: 
 
“Maximum Run Time” shall mean the maximum number of hours a generating unit can run over 
the course of an Operating Day, as measured by PJM’s State Estimator. 
 
Maximum State of Charge: 
 
“Maximum State of Charge” shall mean the maximum State of Charge that should not be 
exceeded, measured in units of megawatt-hours. 
 
Maximum Weekly Starts: 
 
“Maximum Weekly Starts” shall mean the maximum number of times that a generating unit can 
be started in one week, defined as the 168 hour period starting Monday 0001 hour, under normal 
operating conditions. 
 
Member: 
  
“Member” shall have the meaning provided in the Operating Agreement. 
 
Merchant A.C. Transmission Facilities: 
 
“Merchant A.C. Transmission Facility” shall mean Merchant Transmission Facilities that are 
alternating current (A.C.) transmission facilities, other than those that are Controllable A.C. 
Merchant Transmission Facilities.  
 
Merchant D.C. Transmission Facilities: 
 
“Merchant D.C. Transmission Facilities” shall mean direct current (D.C.) transmission facilities 
that are interconnected with the Transmission System pursuant to Tariff, Part IV and Part VI.  
 
Merchant Network Upgrades: 
 
“Merchant Network Upgrades” shall mean additions to, or modifications or replacements of, 
physical facilities of the Interconnected Transmission Owner that, on the date of the pertinent 
Transmission Interconnection Customer’s Upgrade Request, are part of the Transmission System 
or are included in the Regional Transmission Expansion Plan. 
 
Merchant Transmission Facilities:

“Merchant Transmission Facilities” shall mean A.C. or D.C. transmission facilities that are 
interconnected with or added to the Transmission System pursuant to Tariff, Part IV and Part VI 
and that are so identified in Tariff, Attachment T, provided, however, that Merchant 
Transmission Facilities shall not include (i) any Customer Interconnection Facilities, (ii) any 
physical facilities of the Transmission System that were in existence on or before March 20, 
2003 ; (iii) any expansions or enhancements of the Transmission System that are not identified as 
Merchant Transmission Facilities in the Regional Transmission Expansion Plan and Attachment 
T to the Tariff, or (iv) any transmission facilities that are included in the rate base of a public 
utility and on which a regulated return is earned. 
 
Merchant Transmission Provider: 
 
“Merchant Transmission Provider” shall mean an Interconnection Customer that (1) owns,  
controls, or controls the rights to use the transmission capability of, Merchant D.C. Transmission 
Facilities and/or Controllable A.C. Merchant Transmission Facilities that connect the 
Transmission System with another control area, (2) has elected to receive Transmission Injection 
Rights and Transmission Withdrawal Rights associated with such facility pursuant to Tariff, Part 
IV, section 36, and (3) makes (or will make) the transmission capability of such facilities 
available for use by third parties under terms and conditions approved by the Commission and 
stated in the Tariff, consistent with Tariff, section 38. 
 
Metering Equipment: 
 
“Metering Equipment” shall mean all metering equipment installed at the metering points 
designated in the appropriate appendix to an Interconnection Service Agreement. 
 
Minimum Annual Resource Requirement: 
 
“Minimum Annual Resource Requirement” shall mean, for Delivery Years through May 31, 
2017,   the minimum amount of capacity that PJM will seek to procure from Annual Resources 
for the PJM Region and for each Locational Deliverability Area for which the Office of the 
Interconnection is required under Tariff, Attachment DD, section 5.10(a) to establish a separate 
VRR Curve for such Delivery Year.  For the PJM Region, the Minimum Annual Resource 
Requirement shall be equal to the RTO Reliability Requirement minus [the Sub-Annual 
Resource Reliability Target for the RTO in Unforced Capacity].  For an LDA, the Minimum 
Annual Resource Requirement shall be equal to the LDA Reliability Requirement minus [the 
LDA CETL] minus [the Sub-Annual Resource Reliability Target for such LDA in Unforced 
Capacity]. The LDA CETL may be adjusted pro rata for the amount of load served under the 
FRR Alternative. 
 
Minimum Down Time: 
 
For all generating units that are not combined cycle units, “Minimum Down Time” shall mean 
the minimum number of hours under normal operating conditions between unit shutdown and 
unit startup, calculated as the shortest time difference between the unit’s generator breaker

opening and after the unit’s generator breaker closure, which is typically indicated by 
telemetered or aggregated State Estimator megawatts greater than zero. For combined cycle 
units, “Minimum Down Time” shall mean the minimum number of hours between the last 
generator breaker opening and after first combustion turbine generator breaker closure, which is 
typically indicated by telemetered or aggregated State Estimator megawatts greater than zero. 
 
Minimum Extended Summer Resource Requirement: 
 
“Minimum Extended Summer Resource Requirement” shall mean, for Delivery Years through 
May 31, 2017, the minimum amount of capacity that PJM will seek to procure from Extended 
Summer Demand Resources and Annual Resources for the PJM Region and for each Locational 
Deliverability Area for which the Office of the Interconnection is required under Tariff, 
Attachment DD, section 5.10(a) to establish a separate VRR Curve for such Delivery Year.  For 
the PJM Region, the Minimum Extended Summer Resource Requirement shall be equal to the 
RTO Reliability Requirement minus [the Limited Demand Resource Reliability Target for the 
PJM Region in Unforced Capacity].  For an LDA, the Minimum Extended Summer Resource 
Requirement shall be equal to the LDA Reliability Requirement minus [the LDA CETL] minus 
[the Limited Demand Resource Reliability Target for such LDA in Unforced Capacity].  The 
LDA CETL may be adjusted pro rata for the amount of load served under the FRR Alternative. 
 
Minimum Generation Emergency: 
 
“Minimum Generation Emergency” shall mean an Emergency declared by the Office of the 
Interconnection in which the Office of the Interconnection anticipates requesting one or more 
generating resources to operate at or below Normal Minimum Generation, in order to manage, 
alleviate, or end the Emergency. 
 
Minimum Participation Requirements: 
 
“Minimum Participation Requirements” shall mean a set of minimum training, risk management, 
communication and capital or collateral requirements required for Participants in the PJM 
Markets, as set forth herein and in the Form of Annual Certification set forth as Tariff, 
Attachment Q, Appendix 1.  Participants transacting in FTRs in certain circumstances will be 
required to demonstrate additional risk management procedures and controls as further set forth 
in the Annual Certification found in Tariff, Attachment Q, Appendix 1. 
 
Minimum Run Time: 
 
For all generating units that are not combined cycle units, “Minimum Run Time” shall mean the 
minimum number of hours a unit must run, in real-time operations, from the time after generator 
breaker closure, which is typically indicated by telemetered or aggregated State Estimator 
megawatts greater than zero, to the time of generator breaker opening, as measured by PJM's 
State Estimator. For combined cycle units, “Minimum Run Time” shall mean the time period 
after the first combustion turbine generator breaker closure, which is typically indicated by 
telemetered or aggregated State Estimator megawatts greater than zero, and the last generator 
breaker opening as measured by PJM’s State Estimator.

Minimum State of Charge: 
 
“Minimum State of Charge” shall mean the minimum State of Charge that should be maintained 
in units of megawatt-hours. 
 
MISO: 
 
“MISO” shall mean the Midcontinent Independent System Operator, Inc. or any successor 
thereto. 
 
Mixed Technology Facility: 
 
“Mixed Technology Facility” shall mean a facility composed of distinct generation and/or 
electric storage technology types behind the same Point of Interconnection.  Co-Located 
Resources and Hybrid Resources form all or part of Mixed Technology Facilities. 
 
MOPR Floor Offer Price: 
 
“MOPR Floor Offer Price” shall mean a minimum offer price applicable to certain Market 
Seller’s Capacity Resources under certain conditions, as determined in accordance with Tariff, 
Attachment DD, sections 5.14(h), 5.14(h-1), and 5.14(h-2). 
 
Multi-Driver Project: 
 
“Multi-Driver Project” shall have the same meaning provided in the Operating Agreement. 
 
Native Load Customers: 
 
“Native Load Customers” shall mean the wholesale and retail power customers of a 
Transmission Owner on whose behalf the Transmission Owner, by statute, franchise, regulatory 
requirement, or contract, has undertaken an obligation to construct and operate the Transmission 
Owner’s system to meet the reliable electric needs of such customers. 
 
Near-Term Transmission Service: 
 
“Near-Term Transmission Service” shall mean Transmission Service which ends not more than 
10 days after the Transmission Service request date.  When the description of obligations below 
refers to either a request for information about the availability of potential Transmission Service 
(including, but not limited to, a request for ATC), or to the posting of ATC or other information 
related to potential service, the date that the information is requested or posted will serve as the 
Transmission Service request date.  “Near-Term Transmission Service” includes any Point-To-
Point Transmission Service and Network Integration Transmission Service where the start and 
end date of the designation or request is within the next 10 days. 
 
NERC:

“NERC” shall mean the North American Electric Reliability Corporation or any successor 
thereto. 
 
NERC Interchange Distribution Calculator: 
 
“NERC Interchange Distribution Calculator” shall mean the NERC mechanism that is in effect 
and being used to calculate the distribution of energy, over specific transmission interfaces, from 
energy transactions. 
 
Net Benefits Test:  
 
“Net Benefits Test” shall mean a calculation to determine whether the benefits of a reduction in 
price resulting from the dispatch of Economic Load Response exceeds the cost to other loads 
resulting from the billing unit effects of the load reduction, as specified in Operating Agreement, 
Schedule 1, section 3.3A.4 and the parallel provisions of Tariff, Attachment K-Appendix, section 
3.3A.4. 
 
Net Cost of New Entry:   
 
“Net Cost of New Entry” shall mean the Cost of New Entry minus the Net Energy and Ancillary 
Service Revenue Offset. 
 
Net Obligation: 
  
“Net Obligation” shall mean the amount owed to PJMSettlement and PJM for purchases from the 
PJM Markets, Transmission Service, (under Tariff, Parts II and III , and other services pursuant 
to the Agreements, after applying a deduction for amounts owed to a Participant by 
PJMSettlement as it pertains to monthly market activity and services.  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. 
 
Net Sell Position: 
  
“Net Sell Position” shall mean the amount of Net Obligation when Net Obligation is negative. 
 
Network Customer: 
 
“Network Customer” shall mean an entity receiving transmission service pursuant to the terms of 
the Transmission Provider’s Network Integration Transmission Service under Tariff, Part III. 
 
Network External Designated Transmission Service: 
 
“Network External Designated Transmission Service” shall have the meaning set forth in 
Reliability Assurance Agreement, Article I.

Network Integration Transmission Service: 
 
“Network Integration Transmission Service” shall mean the transmission service provided under 
Tariff, Part III. 
 
Network Load: 
 
“Network Load” shall mean the load that a Network Customer designates for Network 
Integration Transmission Service under Tariff, Part III.  The Network Customer’s Network Load 
shall include all load (including losses, Non-Dispatched Charging Energy, and Load Serving 
Charging Energy) served by the output of any Network Resources designated by the Network 
Customer.  A Network Customer may elect to designate less than its total load as Network Load 
but may not designate only part of the load at a discrete Point of Delivery.  Where an Eligible 
Customer has elected not to designate a particular load at discrete points of delivery as Network 
Load, the Eligible Customer is responsible for making separate arrangements under Tariff, Part 
II for any Point-To-Point Transmission Service that may be necessary for such non-designated 
load.  Network Load shall not include Dispatched Charging Energy. 
 
Network Operating Agreement: 
 
“Network Operating Agreement” shall mean an executed agreement that contains the terms and 
conditions under which the Network Customer shall operate its facilities and the technical and 
operational matters associated with the implementation of Network Integration Transmission 
Service under Tariff, Part III. 
 
Network Operating Committee: 
 
“Network Operating Committee” shall mean a group made up of representatives from the 
Network Customer(s) and the Transmission Provider established to coordinate operating criteria 
and other technical considerations required for implementation of Network Integration 
Transmission Service under Tariff, Part III.  
 
Network Resource: 
 
“Network Resource” shall mean any designated generating resource owned, purchased, or leased 
by a Network Customer under the Network Integration Transmission Service Tariff.  Network 
Resources do not include any resource, or any portion thereof, that is committed for sale to third 
parties or otherwise cannot be called upon to meet the Network Customer’s Network Load on a 
non-interruptible basis, except for purposes of fulfilling obligations under a reserve sharing 
program. 
 
Network Service User: 
 
“Network Service User” shall mean an entity using Network Transmission Service. 
 
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. 
 
Network Upgrades: 
 
“Network Upgrades” shall mean modifications or additions to transmission-related facilities that 
are integrated with and support the Transmission Provider’s overall Transmission System for the 
general benefit of all users of such Transmission System. Network Upgrades shall include: 
 
 
(i) Direct Connection Network Upgrades which are Network Upgrades that are not part 
of an Affected System; only serve the Customer Interconnection Facility; and have no impact or 
potential impact on the Transmission System until the final tie-in is complete.  Both 
Transmission Provider and Interconnection Customer must agree as to what constitutes Direct 
Connection Network Upgrades and identify them in the Interconnection Construction Service 
Agreement, Schedule D.  If the Transmission Provider and Interconnection Customer disagree 
about whether a particular Network Upgrade is a Direct Connection Network Upgrade, the 
Transmission Provider must provide the Interconnection Customer a written technical 
explanation outlining why the Transmission Provider does not consider the Network Upgrade to 
be a Direcct Connection Network Upgrade within 15 days of its determination. 
 
 
(ii) Non-Direct Connection Network Upgrades which are parallel flow Network 
Upgrades that are not Direct Connection Network Upgrades. 
 
Neutral Party: 
 
“Neutral Party” shall have the meaning provided in Tariff, Part I, section 9.3(v). 
 
New Entry Capacity Resource with State Subsidy: 
 
“New Entry Capacity Resource with State Subsidy” shall mean (1) starting with the 2022/2023 
Delivery Year, the MWs (in installed capacity) comprising a Capacity Resource with State 
Subsidy that have not cleared in 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 or (2) starting with the Base Residual Auction for the 2022/2023 Delivery Year, any 
of those MWs (in installed capacity) comprising a Capacity Resource with State Subsidy that 
was not included in an FRR Capacity Plan at the time of the Base Residual Auction or the 
subject of a Sell Offer in a Base Residual Auction occurring for a Delivery Year after it last 
cleared an RPM Auction and since then has yet to clear 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.  Notwithstanding the foregoing, any Capacity Resource that 
previously cleared an RPM Auction before it became entitled to receive a State Subsidy shall not 
be deemed a New Entry Capacity Resource, unless, starting with the Base Residual Auction for 
the 2022/2023 Delivery Year, the Capacity Resource with State Subsidy was not the subject of a

Sell Offer in a Base Residual Auction or included in an FRR Capacity Plan at the time of the 
Base Residual Auction for a Delivery Year after it last cleared an RPM Auction. 
 
New Large Load: 
 
“New Large Load” shall mean end-use customer load that is either (a) a Large Load that goes 
into service after June 1, 2027, or (b) incremental load in-service after June 1, 2027, that 
increases the existing end-use customer load at a single electrical site that, prior to such 
incremental load, did not previously meet the definition of Large Load.  However, to the extent 
three consecutive Delivery Years meet the requirements of Tariff, Attachment DD-4, section 
IV(b)(iii), then New Large Load shall mean end-use customer load that is either (a) a Large Load 
that goes into service after June 1 of the first Delivery Year for which the requirements of Tariff, 
Attachment DD-4, section IV(b)(iii) are not met or (b) incremental load in-service after June 1 of 
the first Delivery Year for which the requirements of Tariff, Attachment DD-4, section IV(b)(iii) 
are not met that increases the existing end-use customer load at a single electrical site that, prior 
to such incremental load, did not previously meet the definition of Large Load. 
 
New PJM Zone(s): 
 
“New PJM Zone(s)” shall mean the Zone included in the Tariff, along with applicable Schedules 
and Attachments, for Commonwealth Edison Company, The Dayton Power and Light Company 
and the AEP East Operating Companies (Appalachian Power Company, Columbus Southern 
Power Company, Indiana Michigan Power Company, Kentucky Power Company, Kingsport 
Power Company, Ohio Power Company and Wheeling Power Company). 
 
New Service Customers: 
 
“New Service Customers” shall mean all customers that submit an Interconnection Request, a 
Completed Application, or an Upgrade Request that is pending in the New Services Queue. 
 
New Service Request: 
 
“New Service Request” shall mean an Interconnection Request, a Completed Application, or an 
Upgrade Request. 
 
New Services Queue: 
 
“New Services Queue” shall mean all Interconnection Requests, Completed Applications, and 
Upgrade Requests that are received within each six-month period ending on March 31 and 
September 30 of each year shall collectively comprise a New Services Queue. 
 
New York ISO or NYISO: 
 
“New York ISO” or “NYISO” shall mean the New York Independent System Operator, Inc. or 
any successor thereto.

Nodal Reference Price: 
  
The “Nodal Reference Price” at each location shall mean the 97th percentile price differential 
between day-ahead and real-time prices experienced over the corresponding two-month 
reference period in the prior calendar year.   Reference periods will be Jan-Feb, Mar-Apr, May-
Jun, Jul-Aug, Sept-Oct, Nov-Dec.  For any given current-year month, the reference period 
months will be the set of two months in the prior calendar year that include the month 
corresponding to the current month.  For example, July and August 2003 would each use July-
August 2002 as their reference period. 
 
No-load Cost:  
 
“No-load Cost” shall mean the hourly cost required to theoretically operate a synchronized unit 
at zero MW. It consists primarily of the cost of fuel, as determined by the unit’s no load heat 
(adjusted by the performance factor) times the fuel cost. It also includes operating costs, 
Maintenance Adders, and emissions allowances. 
 
Nominal Rated Capability: 
 
“Nominal Rated Capability” shall mean the nominal maximum rated capability in megawatts of 
a Transmission Interconnection Customer’s Customer Facility or the nominal increase in 
transmission capability in megawatts of the Transmission System resulting from the 
interconnection or addition of a Transmission Interconnection Customer’s Customer Facility, as 
determined in accordance with pertinent Applicable Standards and specified in the 
Interconnection Service Agreement. 
 
Nominated Demand Resource Value: 
 
“Nominated Demand Resource Value” shall mean the amount of load reduction that a Demand 
Resource commits to provide either through direct load control, firm service level or guaranteed 
load drop programs.  For existing Demand Resources, the maximum Nominated Demand 
Resource Value is limited, in accordance with the PJM Manuals, to the value appropriate for the 
method by which the load reduction would be accomplished, at the time the Base Residual 
Auction or Incremental Auction is being conducted. 
 
Nominated Energy Efficiency Value:  
 
“Nominated Energy Efficiency Value” shall mean the amount of load reduction that an Energy 
Efficiency Resource commits to provide through installation of more efficient devices or 
equipment or implementation of more efficient processes or systems. 
 
Non-Curtailment Charge: 
 
“Non-Curtailment Charge” shall mean the charge applicable to Demand Resources and Price 
Responsive Demand as defined in Tariff, Attachment DD, section 10B(b).

Non-Dispatched Charging Energy:  
 
“Non-Dispatched Charging Energy” shall mean all Direct Charging Energy that an Energy 
Storage Resource Model Participant or Open-Loop Hybrid Resource receives from the electric 
grid that is not otherwise Dispatched Charging Energy. 
 
Non-Firm Point-To-Point Transmission Service: 
 
“Non-Firm Point-To-Point Transmission Service” shall mean Point-To-Point Transmission 
Service under the Tariff that is reserved and scheduled on an as-available basis and is subject to 
Curtailment or Interruption as set forth in Tariff, Part II, section 14.7.  Non-Firm Point-To-Point 
Transmission Service is available on a stand-alone basis for periods ranging from one hour to 
one month. 
 
Non-Firm Sale: 
 
“Non-Firm Sale” shall mean an energy sale for which receipt or delivery may be interrupted for 
any reason or no reason, without liability on the part of either the buyer or seller. 
 
Non-Firm Transmission Withdrawal Rights: 
 
“No-Firm Transmission Withdrawal Rights” shall mean the rights to schedule energy 
withdrawals from a specified point on the Transmission System. Non-Firm Transmission 
Withdrawal Rights may be awarded only to a Merchant D.C. Transmission Facility that connects 
the Transmission System to another control area. Withdrawals scheduled using Non-Firm 
Transmission Withdrawal Rights have rights similar to those under Non-Firm Point-to-Point 
Transmission Service. 
 
Non-PAI Event: 
 
“Non-PAI Event” shall mean, effective for the 2028/2029 Delivery Year and subsequent 
Delivery Years, any intervals when a Demand Resource is dispatched or when Price Responsive 
Demand is required to respond and a Performance Assessment Interval is not in effect for such 
intervals for the same registration. 
 
Non-Performance Charge: 
 
“Non-Performance Charge” shall mean the charge applicable to Capacity Performance 
Resources as defined in Tariff, Attachment DD, section 10A(e). 
 
Nonincumbent Developer: 
 
“Nonincumbent Developer” shall have the same meaning provided in the Operating Agreement. 
 
Non-Regulatory Opportunity Cost:

“Non-Regulatory Opportunity Cost” shall mean the difference between (a) the forecasted cost to 
operate a specific generating unit when the unit only has a limited number of starts or available 
run hours resulting from (i) the physical equipment limitations of the unit, for up to one year, due 
to original equipment manufacturer recommendations or insurance carrier restrictions, (ii) a fuel 
supply limitation, for up to one year, resulting from an event of Catastrophic Force Majeure; and,  
(b) the forecasted future Locational Marginal Price at which the generating unit could run while 
not violating such limitations.  Non-Regulatory 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 period of time in which the unit is bound by the 
referenced restrictions, and is reflected in the rules set forth in PJM Manual 15.  Non-Regulatory 
Opportunity Costs shall be limited to those resources which are specifically delineated in 
Operating Agreement, Schedule 2.  
 
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, or electric distribution companies to serve 
load. 
 
Non-Synchronized Reserve: 
 
“Non-Synchronized Reserve” shall mean the reserve capability of non-emergency generation 
resources that can be converted fully into energy within ten minutes of a request from the Office 
of the Interconnection dispatcher, and is provided by equipment that is not electrically 
synchronized to the Transmission System. 
 
Non-Synchronized Reserve Event: 
 
“Non-Synchronized Reserve Event” shall mean a request from the Office of the Interconnection 
to generation resources able and assigned to provide Non-Synchronized Reserve in one or more 
specified Reserve Zones or Reserve Sub-zones, within ten minutes to increase the energy output 
by the amount of assigned Non-Synchronized Reserve capability. 
 
Non-Variable Loads: 
“Non-Variable Loads” shall have the meaning specified in Operating Agreement, Schedule 1, 
section 1.5A.6, and the parallel provisions of Tariff, Attachment K-Appendix, section 1.5A.6. 
 
Non-Zone Network Load: 
 
“Non-Zone Network Load shall mean Network Load that is located outside of the PJM Region. 
 
Normal Maximum Generation: 
 
“Normal Maximum Generation” shall mean the highest output level of a generating resource 
under normal operating conditions.

Normal Minimum Generation: 
 
“Normal Minimum Generation” shall mean the lowest output level of a generating resource 
under normal operating conditions.

Definitions – T – U - V 
 
Tangible Net Worth: 
 
“Tangible Net Worth” shall mean total assets less goodwill and other intangible assets, minus 
total liabilities.   
 
Target Allocation: 
 
“Target Allocation” shall mean the allocation of Transmission Congestion Credits as set forth in 
Operating Agreement, Schedule 1, section 5.2.3, and the parallel provisions of Tariff, 
Attachment K-Appendix, section 5.2.3, or the allocation of Auction Revenue Rights Credits as 
set forth in Operating Agreement, Schedule 1, section 7.4.3, and the parallel provisions of Tariff, 
Attachment K-Appendix, section 7.4.3. 
 
Third Incremental Auction: 
 
“Third Incremental Auction” shall mean an Incremental Auction conducted three months before 
the Delivery Year to which it relates. 
 
Third-Party Sale: 
 
“Third-Party Sale” shall mean any sale for resale in interstate commerce to a Power Purchaser 
that is not designated as part of Network Load under the Network Integration Transmission 
Service but not including a sale of energy through the PJM Interchange Energy Market 
established under the PJM Operating Agreement. 
 
Tie Line: 
 
“Tie Line” shall mean a circuit connecting two balancing authority areas, Control Areas or fully 
metered electric system regions. Tie Lines may be classified as external or internal as set forth in 
the PJM Manuals. 
 
Total Lost Opportunity Cost Offer:   
 
“Total Lost Opportunity Cost Offer” shall mean the applicable offer used to calculate lost 
opportunity cost credits.  For pool-scheduled resources specified in PJM Operating Agreement, 
Schedule 1, section 3.2.3(f-1), and the parallel provisions of Tariff, Attachment K-Appendix, 
section 3.2.3(f-1), the Total Lost Opportunity Cost Offer shall equal the Real-time Settlement 
Interval offer integrated under the applicable offer curve for the LOC Deviation, as determined by 
the greater of the Committed Offer or last Real-Time Offer submitted for the offer on which the 
resource was committed in the Day-ahead Energy Market for each hour in an Operating Day.  For 
all other pool-scheduled resources, the Total Lost Opportunity Cost Offer shall equal the Real-
time Settlement Interval offer integrated under the applicable offer curve for the LOC Deviation, 
as determined by the offer curve associated with the greater of the Committed Offer or Final Offer 
for each hour in an Operating Day.   For self-scheduled generation resources, the Total Lost

Opportunity Cost Offer shall equal the Real-time Settlement Interval offer integrated under the 
applicable offer curve for the LOC Deviation, where for self-scheduled generation resources (a) 
operating pursuant to a cost-based offer, the applicable offer curve shall be the greater of the 
originally submitted cost-based offer or the cost-based offer that the resource was dispatched on 
in real-time; or (b) operating pursuant to a market-based offer, the applicable offer curve shall be 
determined in accordance with the following process: (1) select the greater of the cost-based day-
ahead offer and updated cost-based Real-time Offer; (2) for resources with multiple cost-based 
offers, first, for each cost-based offer select the greater of the day-ahead offer and updated Real-
time Offer, and then select the lesser of the resulting cost-based offers; and (3) compare the offer 
selected in (1), or for resources with multiple cost-based offers the offer selected in (2), with the 
market-based day-ahead offer and the market-based Real-time Offer and select the highest offer. 
 
Total Net Obligation: 
  
“Total Net Obligation” shall mean all unpaid billed Net Obligations plus any unbilled Net 
Obligation incurred to date, as determined by PJMSettlement on a daily basis, plus any other 
Obligations owed to PJMSettlement at the time. 
 
Total Net Sell Position: 
 
“Total Net Sell Position” shall mean all unpaid billed Net Sell Positions plus any unbilled Net 
Sell Positions accrued to date, as determined by PJMSettlement on a daily basis. 
 
Total Operating Reserve Offer:   
 
“Total Operating Reserve Offer” shall mean the applicable offer used to calculate Operating 
Reserve credits.  The Total Operating Reserve Offer shall equal the sum of all individual Real-
time Settlement Interval energy offers, inclusive of Start-Up Costs (shut-down costs for Demand 
Resources) and No-load Costs, for every Real-time Settlement Interval in a Segment, integrated 
under the applicable offer curve up to the applicable megawatt output as further described in the 
PJM Manuals.  The applicable offer used to calculate day-ahead Operating Reserve credits shall 
be the Committed Offer, and the applicable offer used to calculate balancing Operating Reserve 
credits shall be lesser of the Committed Offer or Final Offer for each hour in an Operating Day. 
 
Trade Reference:  
 
“Trade Reference” shall mean a reference from a contact or firm that had or has a material 
business relationship with a Participant. 
 
Transmission Congestion Charge: 
 
“Transmission Congestion Charge” shall mean a charge attributable to the increased cost of 
energy delivered at a given load bus when the transmission system serving that load bus is 
operating under constrained conditions, or as necessary to provide energy for third-party 
transmission losses which shall be calculated and allocated as specified in Operating Agreement,

Schedule 1, section 5.1 and the parallel provisions of Tariff, Attachment K-Appendix, section 
5.1. 
 
Transmission Congestion Credit: 
 
“Transmission Congestion Credit” shall mean the allocated share of total Transmission 
Congestion Charges credited to each FTR Holder, calculated and allocated as specified in 
Operating Agreement, Schedule 1, section 5.2, and the parallel provisions of Tariff, Attachment 
K-Appendix, section 5.2. 
 
Transmission Constraint Penalty Factor: 
 
“Transmission Constraint Penalty Factor” shall mean the maximum cost of the re-dispatch 
incurred to control the flows across a transmission constraint and establishes the maximum limit 
on the Marginal Value. 
 
Transmission Customer: 
 
“Transmission Customer” shall mean any Eligible Customer (or its Designated Agent) that (i) 
executes a Service Agreement, or (ii) requests in writing that the Transmission Provider file with 
the Commission a proposed unexecuted Service Agreement, to receive transmission service 
under Tariff, Part II.  This term is used in Tariff, Part I and Tariff, Part VI to include customers 
receiving transmission service under Tariff, Part II and Tariff, Part III. 
 
Where used in Tariff, Attachment K-Appendix and the parallel provisions of Operating 
Agreement, Schedule 1, Transmission Customer shall mean an entity using Point-to-Point 
Transmission Service. 
 
Transmission Facilities: 
 
“Transmission Facilities” shall have the meaning set forth in the Operating Agreement. 
 
Transmission Forced Outage: 
 
“Transmission Forced Outage” shall mean an immediate removal from service of a transmission 
facility by reason of an Emergency or threatened Emergency, unanticipated failure, or other 
cause beyond the control of the owner or operator of the transmission facility, as specified in the 
relevant portions of the PJM Manuals.  A removal from service of a transmission facility at the 
request of the Office of the Interconnection to improve transmission capability shall not 
constitute a Forced Transmission Outage. 
 
Transmission Facility Rating: 
 
“Transmission Facility Rating” shall mean the maximum transfer capability, or the maximum or 
minimum voltage, current, frequency, or real or reactive power flow, through a Transmission 
Facility that does not violate the applicable rating of relevant transmission equipment.

Transmission Facility Ratings are computed in accordance with a written Transmission Facility 
Rating methodology and consistent with Good Utility Practice, considering the technical 
limitations on conductors and relevant transmission equipment (such as thermal flow limits).  
Relevant transmission equipment may include, but is not limited to, circuit breakers, line traps, 
and transformers.  Transmission Facility Ratings also encompass AARs, AAR Exceptions, and 
Temporary Conditional Transmission Facility Ratings. 
 
Transmission Injection Rights: 
 
“Transmission Injection Rights” shall mean Capacity Transmission Injection Rights and Energy 
Transmission Injection Rights. 
 
Transmission Interconnection Customer: 
 
“Transmission Interconnection Customer” shall mean an entity that submits an Interconnection 
Request to interconnect or add Merchant Transmission Facilities to the Transmission System or 
to increase the capacity of Merchant Transmission Facilities interconnected with the 
Transmission System in the PJM Region or an entity that submits an Upgrade Request for 
Merchant Network Upgrades (including accelerating the construction of any transmission 
enhancement or expansion, other than Merchant Transmission Facilities, that is included in the 
Regional Transmission Expansion Plan prepared pursuant to Operating Agreement, Schedule 6). 
 
Transmission Interconnection Facilities Study: 
 
“Transmission Interconnection Facilities Study” shall mean a Facilities Study related to a 
Transmission Interconnection Request. 
 
Transmission Interconnection Feasibility Study: 
 
“Transmission Interconnection Feasibility Study” shall mean a study conducted by the 
Transmission Provider in accordance with Tariff, Part IV, section 36.2. 
 
Transmission Interconnection Request: 
 
“Transmission Interconnection Request” shall mean a request by a Transmission Interconnection 
Customer pursuant to Tariff, Part IV to interconnect or add Merchant Transmission Facilities to 
the Transmission System or to increase the capacity of existing Merchant Transmission Facilities 
interconnected with the Transmission System in the PJM Region. 
 
Transmission Loading Relief: 
 
“Transmission Loading Relief” shall mean NERC’s procedures for preventing operating security 
limit violations, as implemented by PJM as the security coordinator responsible for maintaining 
transmission security for the PJM Region. 
 
Transmission Loss Charge:

“Transmission Loss Charge” shall mean the charges to each Market Participant, Network 
Customer, or Transmission Customer for the cost of energy lost in the transmission of electricity 
from a generation resource to load as specified in Operating Agreement, Schedule 1, section 5, 
and the parallel provisions of Tariff, Attachment K-Appendix, section 5. 
 
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. 
 
Transmission Owner Attachment Facilities: 
 
“Transmission Owner Attachment Facilities” shall mean that portion of the Transmission Owner 
Interconnection Facilities comprised of all Attachment Facilities on the Interconnected 
Transmission Owner’s side of the Point of Interconnection.  
 
Transmission Owner Interconnection Facilities: 
 
“Transmission Owner Interconnection Facilities” shall mean all Interconnection Facilities that 
are not Customer Interconnection Facilities and that, after the transfer under Tariff, Attachment 
P, Appendix 2, section 5.5 to the Interconnected Transmission Owner of title to any 
Transmission Owner Interconnection Facilities that the Interconnection Customer constructed, 
are owned, controlled, operated and maintained by the Interconnected Transmission Owner on 
the Interconnected Transmission Owner’s side of the Point of Interconnection identified in 
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 or interconnected distribution facilities. 
 
Transmission Owner Upgrade:  
 
“Transmission Owner Upgrade” shall have the same meaning provided in the Operating 
Agreement. 
 
Transmission Planned Outage: 
 
“Transmission Planned Outage” shall mean any transmission outage scheduled in advance for a 
pre-determined duration and which meets the notification requirements for such outages 
specified in Operating Agreement, Schedule 1, and the parallel provisions of Tariff, Attachment 
K-Appendix or the PJM Manuals. 
 
Transmission Provider:

The “Transmission Provider” shall be the Office of the Interconnection for all purposes, provided 
that the Transmission Owners will have the responsibility for the following specified activities: 
 
(a) 
The Office of the Interconnection shall direct the operation and coordinate the 
maintenance of the Transmission System, except that the Transmission Owners will continue to 
direct the operation and maintenance of those transmission facilities that are not listed in the PJM 
Designated Facilities List contained in the PJM Manual on Transmission Operations; 
 
(b) 
Each Transmission Owner shall physically operate and maintain all of the facilities that it 
owns; and 
 
(c) 
When studies conducted by the Office of the Interconnection indicate that enhancements 
or modifications to the Transmission System are necessary, the Transmission Owners shall have 
the responsibility, in accordance with the applicable terms of the Tariff, Operating Agreement 
and/or the Consolidated Transmission Owners Agreement to construct, own, and finance the 
needed facilities or enhancements or modifications to facilities. 
 
Transmission Provider’s Monthly Transmission System Peak: 
 
“Transmission Provider’s Monthly Transmission System Peak” shall mean the maximum firm 
usage of the Transmission Provider’s Transmission System in a calendar month. 
 
Transmission Service: 
 
“Transmission Service” shall mean Point-To-Point Transmission Service provided under Tariff, 
Part II on a firm and non-firm basis. 
 
Transmission Service Request: 
 
“Transmission Service Request” shall mean a request for Firm Point-To-Point Transmission 
Service or a request for Network Integration Transmission Service. 
 
Transmission System: 
 
“Transmission System” shall mean the facilities controlled or operated by the Transmission 
Provider within the PJM Region that are used to provide transmission service under Tariff, Part 
II and Part III. 
 
Transmission Withdrawal Rights: 
 
“Transmission Withdrawal Rights” shall mean Firm Transmission Withdrawal Rights and Non-
Firm Transmission Withdrawal Rights. 
 
Turn Down Ratio:

“Turn Down Ratio” shall mean the ratio of a generating unit’s economic maximum megawatts to 
its economic minimum megawatts. 
 
Unconstrained LDA Group: 
 
“Unconstrained LDA Group” shall mean a combined group of LDAs that form an electrically 
contiguous area and for which a separate Variable Resource Requirement Curve has not been 
established under Tariff, Attachment DD, section 5.10.  Any LDA for which a separate Variable 
Resource Requirement Curve has not been established under Tariff, Attachment DD, section 
5.10 shall be combined with all other such LDAs that form an electrically contiguous area. 
 
Unforced Capacity: 
 
“Unforced Capacity” shall have the meaning specified in the Reliability Assurance Agreement. 
 
Unsecured Credit: 
  
“Unsecured Credit” shall mean any credit granted by PJMSettlement to a Participant that is not 
secured by Collateral. 
 
Unsecured Credit Allowance: 
  
“Unsecured Credit Allowance” shall mean Unsecured Credit extended by PJMSettlement in an 
amount determined by PJMSettlement’s evaluation of the creditworthiness of a Participant.  This 
is also defined as the amount of credit that a Participant qualifies for based on the strength of its 
own financial condition without having to provide Collateral.  See also: “Working Credit Limit.” 
 
Updated VRR Curve: 
 
“Updated VRR Curve” shall mean the Variable Resource Requirement Curve for use in the Base 
Residual Auction of the relevant Delivery Year, updated to reflect any changes in the Reliability 
Requirement, Excluded RTO New Large Load Amounts, and/or Excluded LDA New Large 
Load Amounts from the Base Residual Auction to the relevant Incremental Auction. 
 
Updated VRR Curve Decrement: 
 
“Updated VRR Curve Decrement” shall mean the portion of the Updated VRR Curve to the left 
of a vertical line at the level of Unforced Capacity on the x-axis of such curve equal to the net 
Unforced Capacity committed to the PJM Region as a result of all prior auctions conducted for 
such Delivery Year and adjusted, if applicable, by a change in Unforced Capacity commitments 
associated with Tariff, Attachment DD, section 5.5A(c)(i)(B), and RAA, Schedule 6, section L.9.   
 
Updated VRR Curve Increment: 
 
“Updated VRR Curve Increment” shall mean the portion of the Updated VRR Curve to the right 
of a vertical line at the level of Unforced Capacity on the x-axis of such curve equal to the net

Unforced Capacity committed to the PJM Region as a result of all prior auctions conducted for 
such Delivery Year and adjusted, if applicable, by a change in Unforced Capacity commitments 
associated with Tariff, Attachment DD, section 5.5A(c)(i)(B), and RAA, Schedule 6, section L.9. 
 
Upgrade Construction Service Agreement: 
 
“Upgrade Construction Service Agreement” shall mean that agreement entered into by an 
Eligible Customer, Upgrade Customer or Interconnection Customer proposing Merchant 
Network Upgrades, a Transmission Owner, and the Transmission Provider, pursuant to Tariff, 
Part VI, Subpart B, and in the form set forth in Tariff, Attachment GG. 
 
Upgrade Customer: 
 
“Upgrade Customer” shall mean a customer that submits an Upgrade Request pursuant to 
Operating Agreement, Schedule 1, section 7.8, and the parallel provisions of Tariff, Attachment 
K-Appendix, section 7.8. 
 
Upgrade Feasibility Study: 
 
“Upgrade Feasibility Study” shall mean a study conducted by the Transmission Provider in 
accordance with Tariff, Part IV, section 36.3. 
 
Upgrade-Related Rights: 
 
“Upgrade-Related Rights” shall mean Incremental Auction Revenue Rights, Incremental 
Available Transfer Capability Revenue Rights, Incremental Deliverability Rights, and 
Incremental Capacity Transfer Rights. 
 
Upgrade Request: 
 
“Upgrade Request” shall mean a request submitted in the form prescribed in Tariff, Attachment 
EE, for evaluation by the Transmission Provider of the feasibility and estimated costs of (a) a 
Merchant Network Upgrade or (b) the Customer-Funded Upgrades that would be needed to 
provide Incremental Auction Revenue Rights specified in a request pursuant to Operating 
Agreement, Schedule 1, section 7.8, and the parallel provisions of Tariff, Attachment K-
Appendix, section 7.8. 
 
Up-to Congestion Counterflow Transaction: 
 
“Up-to Congestion Counterflow Transaction” shall mean an Up-to Congestion Transaction will 
be deemed an Up-to Congestion Counterflow Transaction if the following value is negative:  (a) 
when bidding, the lower of the bid price and the prior Up-to Congestion Historical Month’s 
average real-time value for the transaction; or (b) for cleared Virtual Transactions, the cleared 
day-ahead price of the Virtual Transactions. 
 
Up-to Congestion Historical Month:

“Up-to Congestion Historical Month” shall mean a consistently-defined historical period 
nominally one month long that is as close to a calendar month as PJM determines is practical. 
 
Up-to Congestion Prevailing Flow Transaction: 
 
An Up-to Congestion Transaction shall mean an “Up-to Congestion Prevailing Flow 
Transaction” if it is not an Up-to Congestion Counterflow Transaction. 
 
Up-to Congestion Reference Price: 
 
“Up-to Congestion Reference Price” for an Up-to Congestion Transaction, shall be the specified 
percentile price differential between source and sink (defined as sink price minus source price) 
for real-time prices experienced over the prior Up-to Congestion Historical Month, averaged 
with the same percentile value calculated for the second prior Up-to Congestion Historical 
Month.  Up-to Congestion Reference Prices shall be calculated using the following historical 
percentiles: 
 
For Up-to Congestion Prevailing Flow Transactions: 30th percentile 
 
For Up-to Congestion Counterflow Transactions when bid:  20th percentile 
 
For Up-to Congestion Counterflow Transactions when cleared:  5th percentile 
 
Up-to Congestion Transaction: 
 
“Up-to Congestion Transaction” shall have the meaning specified in Operating Agreement, 
Schedule 1, section 1.10.1A, and the parallel provisions of Tariff, Attachment K-Appendix, 
section 1.10.1A. 
 
Variable Loads: 
“Variable Loads” shall have the meaning specified in Operating Agreement, Schedule 1, section 
1.5A.6, and the parallel provisions of Tariff, Attachment K-Appendix, section 1.5A.6. 
 
Variable Resource Requirement Curve:  
 
“Variable Resource Requirement Curve” shall mean a series of maximum prices that can be 
cleared in a Base Residual Auction for Unforced Capacity, corresponding to a series of varying 
resource requirements based on varying installed reserve margins, as determined by the Office of 
the Interconnection for the PJM Region and for certain Locational Deliverability Areas in 
accordance with the methodology provided in Tariff, Attachment DD, section 5. 
 
Virtual Credit Exposure:  
“Virtual Credit Exposure” shall mean the amount of potential credit exposure created by a 
market participant’s bid submitted into the Day-ahead market, as defined in Tariff, Attachment 
Q. 
 
Virtual Transaction:

“Virtual Transaction” shall mean a Decrement Bid, Increment Offer and/or Up-to Congestion 
Transaction. 
 
Virtual Transaction Screening: 
  
“Virtual Transaction Screening” shall be the process of reviewing the Virtual Credit Exposure of 
submitted Virtual Transactions against the Credit Available for Virtual Transactions.  If the 
credit required is greater than credit available, then the Virtual Transactions will not be accepted. 
 
Virtual Transactions Net Activity: 
 
“Virtual Transactions Net Activity” shall mean the aggregate net total, resulting from Virtual 
Transactions, of (i) Spot Market Energy charges, (ii) Transmission Congestion Charges, and (iii) 
Transmission Loss Charges, calculated as set forth in Tariff, Attachment K-Appendix, and the 
parallel provisions of Operating Agreement, Schedule 1.  Virtual Transactions Net Activity may 
be positive or negative. 
 
Voltage Reduction Action: 
 
“Voltage Reduction Action” shall mean a notification during capacity deficient conditions in 
which PJM notifies Members to reduce voltage on the distribution system in order to reduce 
demand and therefore provide a sufficient amount of reserves, maintain tie flow schedules and 
preserve limited energy sources. 
 
Voltage Reduction Alert: 
 
“Voltage Reduction Alert” shall mean a notification from PJM to alert Members that a voltage 
reduction may be required during a future critical period. 
 
Voltage Reduction Warning: 
 
“Voltage Reduction Warning” shall mean a notification from PJM to warn Members that PJM’s 
available Synchronized Reserve is less than the Synchronized Reserve Requirement and that 
present operations have deteriorated such that a voltage reduction may be required.

5.4 
Reliability Pricing Model Auctions 
 
The Office of the Interconnection shall conduct the following Reliability Pricing Model 
Auctions: 
 
 
a) 
Base Residual Auction. 
 
PJM shall conduct for each Delivery Year a Base Residual Auction to secure commitments of 
Capacity Resources as needed to satisfy the portion of the RTO Unforced Capacity Obligation 
not satisfied through Self-Supply of Capacity Resources for such Delivery Year.  All Self-Supply 
Capacity Resources must be offered in the Base Residual Auction.  As set forth in Tariff, 
Attachment DD, section 6.6, all other Capacity Resources, and certain other existing generation 
resources, must be offered in the Base Residual Auction.  The Base Residual Auction shall be 
conducted in the month of May that is three years prior to the start of such Delivery Year.  
Notwithstanding, the Base Residual Auction for the 2026/2027 Delivery Year shall be conducted 
in July 2025; the Base Residual Auction for the 2027/2028 Delivery Year shall be conducted in 
December 2025; the Base Residual Auction for the 2028/2029 Delivery Year shall be conducted 
in June 2026; and the Base Residual Auction for the 2029/2030 Delivery Year shall be 
conducted in December 2026.  The cost of payments to Capacity Market Sellers for Capacity 
Resources that clear such auction shall be paid by PJMSettlement from amounts collected by 
PJMSettlement from Load Serving Entities through the Locational Reliability Charge during 
such Delivery Year. PJMSettlement shall be the Counterparty to the sales that clear in such 
auction and to the obligations to pay, and the payments, by Load Serving Entities; provided, 
however, that PJMSettlement shall not be a Counterparty to committed Self-Supply Capacity 
Resources.  
 
 
b) 
Scheduled Incremental Auctions. 
 
PJM shall conduct for each Delivery Year a First, a Second, and a Third Incremental Auction.  
The First Incremental Auction shall be conducted in the month of September that is twenty 
months prior to the start of the Delivery Year; the Second Incremental Auction shall be 
conducted in the month of July that is ten months prior to the start of the Delivery Year; and the 
Third Incremental Auction shall be conducted in the month of February that is three months prior 
to the start of the Delivery Year.  Notwithstanding, for the 2025/2026 Delivery Year, only the 
Third Incremental Auction shall be conducted, which will commence on February 2025; for the 
2026/2027 Delivery Year, only the Third Incremental Auction shall be conducted, which will 
commence on February 2026; for the 2027/2028 Delivery Year, only the Second Incremental 
Auction and Third Incremental Auction shall be conducted, which will commence on July 2026 
and February 2027, respectively; for the 2028/2029 Delivery Year, only the Second Incremental 
Auction and Third Incremental Auction shall be conducted, which shall commence on July 2027 
and February 2028, respectively. 
 
 
c) 
Adjustment through Scheduled Incremental Auctions of Capacity Previously 
Committed.

The Office of the Interconnection shall recalculate the PJM Region Reliability Requirement and 
each LDA Reliability Requirement (inclusive of any updated adjustments to the Excluded RTO 
New Large Load Amounts and/or Excluded LDA New Large Load Amounts) prior to each 
Scheduled Incremental Auction, based on an updated peak load forecast, updated Installed 
Reserve Margin and an updated Capacity Emergency Transfer Objective; shall update such 
reliability requirements (and inclusive of any updated adjustments to the Excluded RTO New 
Large Load Amounts and/or Excluded LDA New Large Load Amounts) for the Third 
Incremental Auction to reflect any change from such recalculation; and shall update such 
reliability requirements (and inclusive of any updated adjustments to the Excluded RTO New 
Large Load Amounts and/or Excluded LDA New Large Load Amounts) for the First Incremental 
Auction or Second Incremental Auction only if the change is greater than or equal to the lesser 
of: (i) 500 MW or (ii) one percent of the applicable prior reliability requirement.  Based on such 
update, the Office of the Interconnection shall, under certain conditions, seek through the 
Scheduled Incremental Auction to secure additional commitments of capacity or release sellers 
from prior capacity commitments.  Specifically, the Office of the Interconnection shall: 
 
1) 
seek additional capacity commitments to serve the PJM Region or an LDA 
if the PJM Region Reliability Requirement or LDA Reliability Requirement utilized in the most 
recent prior auction conducted for the Delivery Year (including any reductions to such reliability 
requirements as a result of any Price Responsive Demand with a PRD Reservation Price equal to 
or lower than the clearing price in the Base Residual Auction for such Delivery Year and any 
adjustments associated with Excluded RTO New Large Load Amounts or Excluded LDA New 
Large Load Amounts) is less than, respectively, the updated PJM Region Reliability 
Requirement or updated LDA Reliability Requirement (inclusive of any updated adjustments to 
the Excluded RTO New Large Load Amounts and/or Excluded LDA New Large Load 
Amounts); provided, however, that in the First Incremental Auction or Second Incremental 
Auction the Office of the Interconnection shall seek such additional capacity commitments only 
if such shortfall is in an amount greater than or equal to the lesser of: (i) 500 MW or (ii) one 
percent of the applicable prior reliability requirement; 
 
2) 
seek additional capacity commitments to serve the PJM Region or an LDA 
if: 
 
i)  
the updated PJM Region Reliability Requirement or the LDA Reliability 
Requirement (inclusive of any adjustments associated with Excluded RTO New 
Large Load Amounts or Excluded LDA New Large Load Amounts) applicable to 
such auction, exceeds the total capacity committed in all prior auctions in such 
region or area, respectively, for such Delivery Year by an amount greater than or 
equal to the lesser of: (A) 500 MW or (B) one percent of the applicable prior 
reliability requirement;  
 
ii)   
PJM conducts a Conditional Incremental Auction for such Delivery Year 
and does not obtain all additional commitments of Capacity Resources sought in 
such Conditional Incremental Auction, in which case, PJM shall seek in the 
Incremental Auction the commitments that were sought in the Conditional 
Incremental Auction but not obtained; or

iii)  
regarding a Generation Capacity Resource that is subject to Tariff, 
Attachment DD, section 5.3(b), (a) the Office of Interconnection determines prior 
to the Third Incremental Auction that such resource will not meet the criteria set 
forth in Tariff, Attachment DD, section 5.3(b)(i) for the relevant Delivery Year or 
(b) such resource’s final Accredited UCAP is less than the UCAP amount 
considered in the Base Residual Auction in which the resource was deemed to be 
the subject of a Sell Offer. 
 
3) 
seek agreements to release prior capacity commitments to the PJM Region 
or to an LDA if: 
 
i)  
the PJM Region Reliability Requirement or LDA Reliability Requirement 
utilized in the most recent prior auction conducted for the Delivery Year 
(including any reductions to such reliability requirements as a result of any Price 
Responsive Demand with a PRD Reservation Price equal to or lower than the 
clearing price in the Base Residual Auction for such Delivery Year and any 
adjustments associated with Excluded RTO New Large Load Amounts or 
Excluded LDA New Large Load Amounts) exceeds, respectively, the updated 
PJM Region Reliability Requirement or updated LDA Reliability Requirement 
(inclusive of any updated adjustments to the Excluded RTO New Large Load 
Amounts and/or Excluded LDA New Large Load Amounts); provided, however, 
that in the First Incremental Auction or Second Incremental Auction the Office of 
the Interconnection shall seek such agreements only if such excess is in an 
amount greater than or equal to the lesser of: (A) 500 MW or (B) one percent of 
the applicable prior reliability requirement; or 
 
ii)   
PJM obtains additional commitments of Capacity Resources in a 
Conditional Incremental Auction, in which case PJM shall seek release of an 
equal number of megawatts (comparing the total purchase amount for all LDAs 
and the PJM Region related to the delay in Backbone Transmission with the total 
sell amount for all LDAs and the PJM Region related to the delay in Backbone 
Transmission) of prior committed capacity that would not have been committed 
had the delayed Backbone Transmission upgrade that prompted the Conditional 
Incremental Auction not been assumed, at the time of the Base Residual Auction, 
to be in service for the relevant Delivery Year; and if PJM obtains additional 
commitments of capacity in an incremental auction pursuant to subsection c.2.ii 
above, PJM shall seek in such Incremental Auction to release an equal amount of 
capacity (in total for all LDAs and the PJM Region related to the delay in 
Backbone Transmission) previously committed that would not have been 
committed absent the Backbone Transmission upgrade.  
 
4) 
The cost of payments to Market Sellers for additional Capacity Resources 
cleared in such auctions, and the credits from payments from Market Sellers for the release of 
previously committed Capacity Resources, shall be apportioned to Load Serving Entities in the

PJM Region or LDA, as applicable, through adjustments to the Locational Reliability Charge 
for such Delivery Year. 
 
5) 
PJMSettlement shall be the Counterparty to the sales (including releases) 
of Capacity Resources that clear in such auctions and to the obligations to pay, and the payments, 
by Load Serving Entities, provided, however, that PJMSettlement shall not be a Counterparty to 
committed Self-Supply Capacity Resources.   
 
 
d) 
Commitment of Replacement Capacity through Scheduled Incremental Auctions. 
 
Each Scheduled Incremental Auction for each Delivery Year shall allow Capacity 
Market Sellers that committed Capacity Resources in any prior Reliability Pricing Model 
Auction for such Delivery Year to submit Buy Bids for replacement Capacity Resources.  
Capacity Market Sellers that submit Buy Bids into an Incremental Auction must specify the type 
of Unforced Capacity desired, i.e., Annual Resource.  The need to purchase replacement 
Capacity Resources may arise for any reason, including but not limited to resource retirement, 
resource cancellation or construction delay, resource derating, EFORd increase, decrease in 
Accredited UCAP Factor, a decrease in the Nominated Demand Resource Value of a Planned 
Demand Resource, delay or cancellation of a Qualifying Transmission Upgrade, or similar 
occurrences.  The cost of payments to Capacity Market Sellers for Capacity Resources that clear 
such auction shall be paid by PJMSettlement from amounts collected by PJMSettlement from 
Capacity Market Buyers that purchase replacement Capacity Resources in such auction.  
PJMSettlement shall be the Counterparty to the sales and purchases that clear in such auction, 
provided, however, PJMSettlement shall not be a Counterparty to committed Self-Supply 
Capacity Resources. 
 
 
 
e) 
Conditional Incremental Auction. 
 
PJM shall conduct for any Delivery Year a Conditional Incremental Auction if the in service date 
of a Backbone Transmission Upgrade that was modeled in the Base Residual Auction is 
announced as delayed by the Office of the Interconnection beyond July 1 of the Delivery Year 
for which it was modeled and if such delay causes a reliability criteria violation.  If conducted, 
the Conditional Incremental Auction shall be for the purpose of securing commitments of 
additional capacity for the PJM Region or for any LDA to address the identified reliability 
criteria violation.  If PJM determines to conduct a Conditional Incremental Auction, PJM shall 
post on its website the date and parameters for such auction (including whether such auction is 
for the PJM Region or for an LDA, and the type of Capacity Resources required) at least one 
month prior to the start of such auction.  The cost of payments to Market Sellers for Capacity 
Resources cleared in such auction shall be collected by PJMSettlement from Load Serving 
Entities in the PJM Region or LDA, as applicable, through an adjustment to the Locational 
Reliability Charge for such Delivery Year.  PJMSettlement shall be the Counterparty to the sales 
that clear in such auction and to the obligations to pay, and payments, by Load Serving Entities, 
provided, however, that PJMSettlement shall not be a Counterparty to committed Self-Supply 
Capacity Resources.

5.10 
Auction Clearing Requirements 
 
The Office of the Interconnection shall clear each Base Residual Auction and Incremental 
Auction for a Delivery Year in accordance with the following: 
 
 
a) 
Variable Resource Requirement Curve  
 
The Office of the Interconnection shall determine Variable Resource Requirement Curves for the 
PJM Region and for such Locational Deliverability Areas as determined appropriate in 
accordance with subsection (a)(iii) for such Delivery Year to establish the level of Capacity 
Resources that will provide an acceptable level of reliability consistent with the Reliability 
Principles and Standards. It is recognized that the variable resource requirement reflected in the 
Variable Resource Requirement Curve can result in an optimized auction clearing in which the 
level of Capacity Resources committed for a Delivery Year exceeds the PJM Region Reliability 
Requirement or Locational Deliverability Area Reliability Requirement for such Delivery Year. 
For any auction, the Updated Forecast Peak Load applicable to such auction, shall be used, and 
Price Responsive Demand from any applicable approved PRD Plan, including any associated 
PRD Reservation Prices, shall be reflected in the derivation of the Variable Resource 
Requirement Curves, in accordance with the methodology specified in the PJM Manuals. 
 
i) 
Methodology to Establish the Variable Resource Requirement Curve  
 
Prior to the Base Residual Auction, in accordance with the schedule in the PJM Manuals, the 
Office of the Interconnection shall establish the Variable Resource Requirement Curve for the 
PJM Region as follows: 
 
 
Each Variable Resource Requirement Curve shall be plotted on a graph on 
which Unforced Capacity is on the x-axis and price is on the y-axis. 
 
 
For the 2025/2026 Delivery Year, the Variable Resource Requirement 
curve for the PJM Region shall be plotted by combining (i) a horizontal line 
from the y-axis to point (1), (ii) a straight line connecting points (1) and (2), 
and (iii) a straight line connecting points (2) and (3), where: 
 
 
 For point (1), price equals: {the greater of [the Cost of New Entry] 
or [1.5 times (the Cost of New Entry minus the Net Energy and 
Ancillary Service Revenue Offset)]} divided by (the applicable 
ELCC Class Rating of the Reference Resource) and Unforced 
Capacity equals: [the PJM Region Reliability Requirement 
multiplied by 98.9%]; 
 
 
 For point (2), price equals: [0.75 times (the Cost of New Entry 
minus the Net Energy and Ancillary Service Revenue Offset)] 
divided by (the applicable ELCC Class Rating of the Reference 
Resource) and Unforced Capacity equals: [the PJM Region 
Reliability Requirement multiplied by 101.6%]; and

 
 For point (3), price equals zero and Unforced Capacity equals: [the 
PJM Region Reliability Requirement multiplied by 106.8%]. 
 
 
For the 2026/2027 Delivery Year and 2027/2028 Delivery Years, the 
Variable Resource Requirement Curve for the PJM Region shall be plotted 
by a horizontal line from the y-axis equal to $256.75/MW-day ICAP 
divided by the applicable ELCC Class Rating for the Reference Resource 
until such line intersects the curve that is based on the following: (i) a 
straight line connecting points (1) and (2), and (ii) a straight line connecting 
points (2) and (3), where: 
 
 
For point (1), price equals: {the greater of [the Cost of New Entry] 
or [1.75 times (the Cost of New Entry minus the Net Energy and 
Ancillary Service Revenue Offset)]} divided by (the applicable 
ELCC Class Rating of the Reference Resource) and Unforced 
Capacity equals: [the PJM Region Reliability Requirement 
multiplied by 99%]; 
 
 
For point (2), price equals: [0.75 times (the Cost of New Entry minus 
the Net Energy and Ancillary Service Revenue Offset)] divided by 
(the applicable ELCC Class Rating of the Reference Resource) and 
Unforced 
Capacity 
equals: 
[the 
PJM 
Region 
Reliability 
Requirement multiplied by 101.5%]; and 
 
 
For point (3), price equals zero and Unforced Capacity equals: [the 
PJM Region Reliability Requirement multiplied by 104.5%]. 
 
 
Once the horizontal line intersects the above curve, the Variable Resource 
Requirement Curve shall follow the lines that are based on the above points 
until the price reaches $138.25/MW-day ICAP divided by the applicable 
ELCC Class Rating of the Reference Resource, at which point it shall be 
extended as a horizontal line at $138.25/MW-day ICAP divided by the 
applicable ELCC Class Rating of the Reference Resource for the remainder 
of the curve. 
 
 
For the 2028/2029 Delivery Year, the Variable Resource Requirement 
curve for the PJM Region shall be plotted by a horizontal line from the y-
axis equal to the lesser of $256.75/MW-day ICAP divided by the applicable 
ELCC Class Rating for the Reference Resource or the value of point 1, until 
such line intersects the curve that is based on the following: (i) a straight 
line connecting points (1) and (2), and (ii) a straight line connecting points 
(2) and (3), where: 
 
 
For point (1), price equals: {the greater of [1.15 times Cost of New 
Entry minus 0.75 times the Net Energy and Ancillary Service 
Revenue Offset] or [0.2 times Cost of New Entry)]} divided by (the

applicable ELCC Class Rating of the Reference Resource) and 
Unforced 
Capacity 
equals: 
[the 
PJM 
Region 
Reliability 
Requirement multiplied by 99%]; 
 
 
For point (2), price equals: [0.5 times the price calculated for point 
1] divided by (the applicable ELCC Class Rating of the Reference 
Resource) and Unforced Capacity equals: [the PJM Region 
Reliability Requirement multiplied by 101.5%]; and 
 
 
For point (3), price equals zero and Unforced Capacity equals: [the 
PJM Region Reliability Requirement multiplied by 106.0%]. 
 
 
Once the horizontal line intersects the above curve, the Variable Resource 
Requirement Curve shall follow the lines that are based on the above points 
until the price reaches $138.25/MW-day ICAP divided by the applicable 
ELCC Class Rating of the Reference Resource, at which point it shall be 
extended as a horizontal line at $138.25/MW-day ICAP divided by the 
applicable ELCC Class Rating of the Reference Resource for the remainder 
of the curve. 
 
 
For the 2029/2030 Delivery Year, the Variable Resource Requirement 
curve for the PJM Region shall be plotted by a horizontal line from the y-
axis equal to the lesser of $256.75/MW-day ICAP divided by the applicable 
ELCC Class Rating for the Reference Resource or the value of point 1, until 
such line intersects the curve that is based on the following: (i) a straight 
line connecting points (1) and (2), and (ii) a straight line connecting points 
(2) and (3), where: 
 
 
For point (1), price equals: {the greater of [1.15 times Cost of New 
Entry minus 0.75 times the Net Energy and Ancillary Service 
Revenue Offset] or [0.2 times Cost of New Entry)]} divided by (the 
applicable ELCC Class Rating of the Reference Resource) and 
Unforced 
Capacity 
equals: 
[the 
PJM 
Region 
Reliability 
Requirement minus Excluded RTO New Large Load Amounts] 
multiplied by 99%); 
 
 
For point (2), price equals: [0.5 times the price calculated for point 
1] divided by (the applicable ELCC Class Rating of the Reference 
Resource) and Unforced Capacity equals: [the PJM Region 
Reliability Requirement minus Excluded RTO New Large Load 
Amounts] multiplied by 101.5%; and 
 
 
For point (3), price equals zero and Unforced Capacity equals: [the 
PJM Region Reliability Requirement minus Excluded RTO New 
Large Load Amounts] multiplied by 106.0%.

 
Once the horizontal line intersects the above curve, the Variable Resource 
Requirement Curve shall follow the lines that are based on the above points 
until the price reaches $138.25/MW-day ICAP divided by the applicable 
ELCC Class Rating of the Reference Resource, at which point it shall be 
extended as a horizontal line at $138.25/MW-day ICAP divided by the 
applicable ELCC Class Rating of the Reference Resource for the remainder 
of the curve. 
 
 
For the 2030/2031 Delivery Year and for subsequent Delivery Years, the 
Variable Resource Requirement curve for the PJM Region shall be plotted 
by combining (i) a horizontal line from the y-axis to point (1), (ii) a straight 
line connecting points (1) and (2), and (iii) a straight line connecting points 
(2) and (3), where: 
 
 
For point (1), price equals: {the greater of [1.15 times Cost of New 
Entry minus 0.75 times the Net Energy and Ancillary Service 
Revenue Offset] or [0.2 times Cost of New Entry)]} divided by (the 
applicable ELCC Class Rating of the Reference Resource) and 
Unforced 
Capacity 
equals: 
[the 
PJM 
Region 
Reliability 
Requirement minus Excluded RTO New Large Load Amounts] 
multiplied by 99%]; 
 
 
For point (2), price equals: [0.5 times the price calculated for point 
1] divided by (the applicable ELCC Class Rating of the Reference 
Resource) and Unforced Capacity equals: [the PJM Region 
Reliability Requirement minus Excluded RTO New Large Load 
Amounts] multiplied by 101.5%; and 
 
 
For point (3), price equals zero and Unforced Capacity equals: [the 
PJM Region Reliability Requirement minus Excluded RTO New 
Large Load Amounts] multiplied by 106.0%]. 
 
ii) 
For any Delivery Year, the Office of the Interconnection shall establish a 
separate Variable Resource Requirement Curve for each LDA for which: 
 
A. 
the Capacity Emergency Transfer Limit is less than 1.15 times the Capacity 
Emergency Transfer Objective, as determined by the Office of the 
Interconnection in accordance with NERC and Applicable Regional Entity 
guidelines; or 
 
B. 
such LDA had a Locational Price Adder in any one or more of the three 
immediately preceding Base Residual Auctions; or 
 
C. 
such LDA is determined in a preliminary analysis by the Office of the 
Interconnection to be likely to have a Locational Price Adder, based on 
historic offer price levels; provided however that for the Base Residual 
Auction conducted for the Delivery Year, the Eastern Mid-Atlantic Region

(“EMAR”), Southwest Mid-Atlantic Region (“SWMAR”), and Mid-
Atlantic Region (“MAR”) LDAs shall employ separate Variable Resource 
Requirement Curves regardless of the outcome of the above three tests; and 
provided further that the Office of the Interconnection may establish a 
separate Variable Resource Requirement Curve for an LDA not otherwise 
qualifying under the above three tests if it finds that such is required to 
achieve an acceptable level of reliability consistent with the Reliability 
Principles and Standards, in which case the Office of the Interconnection 
shall post such finding, such LDA, and such Variable Resource 
Requirement Curve on its internet site no later than the March 31 last 
preceding the Base Residual Auction for such Delivery Year.  The same 
process as set forth in subsection (a)(i) shall be used to establish the Variable 
Resource Requirement Curve for any such LDA, except that the Locational 
Deliverability Area Reliability Requirement for such LDA shall be 
substituted for the PJM Region Reliability Requirement and, beginning with 
the 2029/2030 Delivery Year, the points on the LDA Variable Resource 
Requirement Curves will be reduced by the relevant Excluded LDA New 
Large Load Amounts.  For purposes of calculating the Capacity Emergency 
Transfer Limit under this section, all generation resources located in the 
PJM Region that are, or that qualify to become, Capacity Resources, shall 
be modeled at their full capacity rating, regardless of the amount of capacity 
cleared from such resource for the immediately preceding Delivery Year. 
 
For Delivery Years up to and including the 2027/2028 Delivery Year for 
each such LDA, the Office of the Interconnection shall (a) determine the 
Net Cost of New Entry for each Zone in such LDA, with such Net Cost of 
New Entry equal to the applicable Cost of New Entry value for such Zone 
minus the Net Energy and Ancillary Services Revenue Offset value for 
such Zone, and (b) compute the average of the Net Cost of New Entry 
values of all such Zones to determine the Net Cost of New Entry for such 
LDA.   
 
For the 2028/2029 Delivery Year and for subsequent Delivery Years for 
each such LDA, the Office of the Interconnection shall determine the 
applicable Cost of New Entry and Net Energy and Ancillary Services 
Revenue Offset value for each LDA, with such Cost of New Entry equal 
to the average of all five Cost of New Entry areas for RTO and the 
average of the Cost of New Entry for all zones in an LDA, and the Net 
Energy and Ancillary Services Revenue Offset value equal to the 67th 
percentile of the Net Energy and Ancillary Services Revenue Offset for all 
zones in such LDA. 
 
iii) 
Procedure for ongoing review of Variable Resource Requirement Curve 
shape. 
 
Beginning with the Delivery Year that commences June 1, 2018, and continuing no later than for 
every fourth Delivery Year thereafter, the Office of the Interconnection shall perform a review of

the shape of the Variable Resource Requirement Curve, as established by the requirements of the 
foregoing subsection.  Such analysis shall be based on simulation of market conditions to 
quantify the ability of the market to invest in new Capacity Resources and to meet the applicable 
reliability requirements on a probabilistic basis.  Based on the results of such review, PJM shall 
prepare a recommendation to either modify or retain the existing Variable Resource Requirement 
Curve shape.  The Office of the Interconnection shall post the recommendation and shall review 
the recommendation through the stakeholder process to solicit stakeholder input. If a 
modification of the Variable Resource Requirement Curve shape is recommended, the following 
process shall be followed:   
 
A) 
If the Office of the Interconnection determines that the Variable 
Resource Requirement Curve shape should be modified, Staff of 
the Office of the Interconnection shall propose a new Variable 
Resource Requirement Curve shape on or before May 15, prior to 
the conduct of the Base Residual Auction for the first Delivery 
Year in which the new values would be applied.   
 
B) 
The PJM Members shall review the proposed modification to the 
Variable Resource Requirement Curve shape. 
 
C) 
The PJM Members shall either vote to (i) endorse the proposed 
modification, (ii) propose alternate modifications or (iii) 
recommend no modification, by August 31, prior to the conduct of 
the Base Residual Auction for the first Delivery Year in which the 
new values would be applied. 
 
D) 
The PJM Board of Managers shall consider a proposed 
modification to the Variable Resource Requirement Curve shape, 
and the Office of the Interconnection shall file any approved 
modified Variable Resource Requirement Curve shape 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. 
 
iv) 
Cost of New Entry  
 
A) 
For the Incremental Auctions, the Cost of New Entry for the PJM 
Region and for each LDA shall be the respective value used in the 
Base Residual Auction for each corresponding Delivery Year and 
LDA.  For the Delivery Year commencing on June 1, 2022 through 
and including the Delivery Year commencing on June 1, 2025, the 
Cost of New Entry for the PJM Region shall be the average of the 
Cost of New Entry for each CONE Area listed in this section as 
adjusted pursuant to subsection (a)(iv)(B).

Geographic Location Within the 
PJM Region Encompassing These 
Zones 
Cost of New Entry 
in $/MW-Year 
PS, JCP&L, AE, PECO, DPL, RECO 
(“CONE Area 1”) 
108,000 
BGE, PEPCO (“CONE Area 2”) 
109,700 
AEP, Dayton, ComEd, APS, DQL, 
ATSI, DEOK, EKPC, Dominion, 
OVEC (“CONE Area 3”) 
105,500 
PPL, MetEd, Penelec (“CONE Area 
4”) 
105,500 
 
A-1)  Cost of New Entry for 2025/2026 Delivery Year 
 
 
A new CONE Area 5 encompassing only the ComEd Zone shall be 
established and the ComEd Zone will be removed from CONE 
Area 3.  For the 2025/2026 Delivery Year, the Cost of New Entry 
for CONE Area 5 will be equal to the product of the Cost of New 
Entry determined for CONE Area 3 for the 2025/2026 Delivery 
Year multiplied by an asset life factor of 1.0069.  For the 
2025/2026 Delivery Year, the Cost of New Entry for the PJM 
Region shall be the average of the Cost of New Entry for all 
CONE Areas. 
 
B) 
Beginning with the 2023/2024 Delivery Year through and including 
the 2025/2026 Delivery Year, the CONE for each CONE Area 
(except for CONE Area 5) shall be adjusted to reflect changes in 
generating plant construction costs based on changes in the 
Applicable United States Bureau of Labor Statistics (“BLS”) 
Composite Index, and then adjusted further by a factor of 1.022 to 
reflect the annual decline in bonus depreciation scheduled under 
federal corporate tax law, in accordance with the following:   
 
 
(1) 
The Applicable BLS Composite Index for any 
Delivery Year and CONE Area shall be the most 
recently published twelve-month change, at the time 
CONE values are required to be posted for the Base 
Residual Auction for such Delivery Year, in a 
composite of the BLS Quarterly Census of 
Employment and Wages for Utility System 
Construction (weighted 20%), the BLS Producer 
Price Index for Construction Materials and 
Components (weighted 55%), and the BLS 
Producer Price Index Turbines and Turbine 
Generator Sets (weighted 25%), as each such index

is further specified for each CONE Area in the PJM 
Manuals.  
 
(2) 
The CONE in a CONE Area shall be adjusted prior 
to the Base Residual Auction for each Delivery 
Year by applying the Applicable BLS Composite 
Index for such CONE Area to the Benchmark 
CONE for such CONE Area, and then multiplying 
the result by 1.022. 
 
(3) 
The Benchmark CONE for a CONE Area shall be 
the CONE used for such CONE Area in the Base 
Residual Auction for the prior Delivery Year 
(provided, however that the Gross CONE values 
stated in subsection (a)(iv)(A) above shall be the 
Benchmark CONE values for the 2022/2023 
Delivery Year to which the Applicable BLS 
Composite Index shall be applied to determine the 
CONE for subsequent Delivery Years), and then 
multiplying the result by 1.022.   
 
(4) 
Notwithstanding the foregoing, CONE values for 
any CONE Area for any Delivery Year shall be 
subject to amendment pursuant to appropriate 
filings with FERC under the Federal Power Act, 
including, without limitation, any filings resulting 
from the process described in section 5.10(a)(vi)(C) 
or any filing to establish new or revised CONE 
Areas. 
 
C) 
For the 2026/2027 Delivery Year and 2027/2028 Delivery Year, 
the Cost of New Entry for the PJM Region shall be the average of 
the Cost of New Entry for each CONE Area listed in this section as 
adjusted pursuant to subsection (a)(iv)(C)(1). 
 
 
Geographic Location Within the 
PJM Region Encompassing These 
Zones 
Cost of New Entry 
 in $/MW-Year 
(ICAP) 
PS, JCP&L, AE, PECO, DPL, 
RECO (“CONE Area 1”) 
136,000 
BGE, PEPCO (“CONE Area 2”) 
142,000 
AEP, Dayton, APS, DQL, ATSI, 
DEOK, EKPC, 
Dominion, OVEC (“CONE Area 
3”) 
147,600

PPL, MetEd, Penelec (“CONE Area 
4”) 
143,500 
ComEd (“CONE Area 5”) 
150,800 
 
(1) 
For the 2027/2028 Delivery Year, the CONE for 
each CONE Area shall be adjusted to reflect 
changes in generating plant construction costs based 
on changes in the Applicable United States Bureau 
of Labor Statistics (“BLS”) Composite Index, in 
accordance with the following:  
 
(a) 
The Applicable BLS Composite Index for 
any Delivery Year and CONE Area shall 
be the most recently published twelve-
month change, at the time CONE values are 
required to be posted for the Base Residual 
Auction for such Delivery Year, in a 
composite of the BLS Quarterly Census of 
Employment and Wages for Utility System 
Construction (weighted 40%), the BLS 
Producer Price Index for Construction 
Materials and Components (weighted 45%), 
and the BLS Producer Price Index Turbines 
and Turbine Generator Sets (weighted 15%), 
as each such index is further specified for 
each CONE Area in the PJM Manuals.  
 
(b) 
For CONE Areas 1 through 4, the 
Benchmark CONE for each CONE Area 
shall be the CONE used for such CONE 
Area in the Base Residual Auction for the 
prior Delivery Year (provided, however that 
the Gross CONE values stated in subsection 
(a)(iv)(C) above shall be the Benchmark 
CONE values for the 2026/2027 Delivery 
Year to which the Applicable BLS 
Composite Index shall be applied to 
determine the CONE for subsequent 
Delivery Years). 
 
(c) 
For the 2027/2028 Delivery Year, the 
CONE for CONE Area 5 for a given 
Delivery Year shall be set equal to the 
product of the CONE of CONE Area 3 as 
determined for the relevant Delivery Year in 
accordance with (a) and (b) above, 
multiplied by the asset life factor applicable

to that Delivery Year where such asset life 
factors is 1.0376 for the 2027/2028 Delivery 
Year. 
 
(d) 
Notwithstanding the foregoing, CONE 
values for any CONE Area for any Delivery 
Year shall be subject to amendment pursuant 
to appropriate filings with FERC under the 
Federal Power Act, including, without 
limitation, any filings resulting from the 
process described in section 5.10(a)(vi)(C) 
or any filing to establish new or revised 
CONE Areas.  
 
D) 
For the 2028/2029 Delivery Year and for subsequent Delivery 
Years, the Cost of New Entry for the PJM Region shall be the 
average of the Cost of New Entry for each CONE Area listed in 
this section. 
 
 
 
Geographic Location Within the 
PJM Region Encompassing These 
Zones 
Cost of New Entry 
 in $/MW-Year 
(ICAP) 
PS, JCP&L, AE, PECO, DPL, 
RECO (“CONE Area 1”) 
218,000 
BGE, PEPCO (“CONE Area 2”) 
222,000 
AEP, Dayton, APS, DQL, ATSI, 
DEOK, EKPC, 
Dominion, OVEC (“CONE Area 
3”) 
215,000 
PPL, MetEd, Penelec (“CONE Area 
4”) 
216,000 
ComEd (“CONE Area 5”) 
248,000 
 
(1) 
Beginning with the 2029/2030 Delivery Year, the Cost of 
New Entry for each CONE Area shall be adjusted to reflect 
changes in generating plant construction costs based on 
changes in the Applicable United States Bureau of Labor 
Statistics (“BLS”) Composite Index, in accordance with the 
following: 
 
(a) 
The Applicable BLS Composite Index for any 
Delivery Year and CONE Area shall be the most 
recently published twelve-month change, at the time 
Cost of New Entry values are required to be posted 
for the Base Residual Auction for such Delivery 
Year, in a composite of the Quarterly Census of

Employment and Wages, which shall use  NAICS 
2371 Utility System Construction, Private, All 
Establishment Sizes (weighted 15%), BLS Producer 
Price Index for Commodities, Not Seasonally 
Adjusted, Intermediate Demand by Commodity 
Type, Materials and Components for Construction 
(weighted 10%), BLS Producer Price Index for 
Commodities, Not Seasonally Adjusted, Machinery 
and Equipment, Turbines and Turbine Generator 
Sets (weighted 46%), and the Bureau of Economic 
Analysis: Gross Domestic Product Implicit Price 
Deflator, Index 2017=100, Seasonally Adjusted 
(weighted 29%), as each such index is further 
specified for each CONE Area in the PJM Manuals. 
 
(b) 
For CONE Areas 1 through 5, the Benchmark 
CONE for each CONE Area shall be the Cost of 
New Entry used for such CONE Area in the Base 
Residual Auction for the prior Delivery Year 
(provided, however that the Cost of New Entry 
values stated in subsection (a)(iv)(C) above shall be 
the Benchmark CONE values for the 2028/2029 
Delivery Year to which the Applicable BLS 
Composite Index shall be applied to determine the 
Cost of New Entry for subsequent Delivery Years). 
 
(c) 
For the 2029/2030 Delivery Year through and 
including the 2031/2032 Delivery Year, the Cost of 
New Entry for CONE Area 5 for a given Delivery 
Year shall be multiplied by the asset life factor 
applicable to that Delivery Year where such asset 
life factors are 1.025 for the 2029/2030 Delivery 
Year, 1.054 for the 2030/2031 Delivery Year, and 
1.088 for the 2031/2032 Delivery Year. 
 
v) 
Net Energy and Ancillary Services Revenue Offset for 2023/2024 
Delivery Year through and including the 2025/2026 Delivery Years 
(except that the calculation of the MOPR Floor Price pursuant to Tariff, 
Attachment DD, section 5.14(h-2) for combustion turbine resources shall 
remain applicable beyond the 2025/2026 Delivery Year): 
 
A) 
The Office of the Interconnection shall determine the Net Energy 
and Ancillary Services Revenue Offset each year for  the PJM 
Region as (A) the annual average of the revenues that would have 
been received by the Reference Resource from the PJM energy 
markets during a period of three consecutive calendar years 
preceding the time of the determination, based on (1) the heat rate

and other characteristics of such Reference Resource; (2)  fuel 
prices reported during such period at an appropriate pricing point 
for the PJM Region with a fuel transmission adder appropriate for 
such region, as set forth in the PJM Manuals, assumed variable 
operation and maintenance expenses for such resource of $6.93 per 
MWh, and actual PJM hourly average Locational Marginal Prices 
recorded in the PJM Region during such period; and (3) an 
assumption that the Reference Resource would be dispatched for 
both the Day-Ahead and Real-Time Energy Markets on a Peak-
Hour Dispatch basis; plus (B) ancillary service revenues of $2,199 
per MW-year to be included through the 2025/2026 Delivery Year.   
 
B)  
The Office of the Interconnection also shall determine a Net 
Energy and Ancillary Service Revenue Offset each year for each 
Zone, using the same procedures and methods as set forth in the 
previous subsection; provided, however, that:  (1) the average 
hourly LMPs for such Zone shall be used in place of the PJM 
Region average hourly LMPs; (2) if such Zone was not integrated 
into the PJM Region for the entire applicable period, then the 
offset shall be calculated using only those whole calendar years 
during which the Zone was integrated; and (3) a posted fuel pricing 
point in such Zone, if available, and (if such pricing point is not 
available in such Zone) a fuel transmission adder appropriate to 
such Zone from an appropriate PJM Region pricing point shall be 
used for each such Zone. 
 
v-1) 
Net Energy and Ancillary Services Revenue Offset for the 2026/2027 
Delivery Year and subsequent Delivery Years: 
 
A) 
For the 2026/2027 and the 2027/2028 Delivery Years, the Office 
of the Interconnection shall determine the Net Energy and 
Ancillary Services Revenue Offset each year for the PJM Region 
as the average of the net energy and ancillary services revenues 
that the Reference Resource is projected to receive from the PJM 
energy and ancillary service markets for the applicable Delivery 
Year from three separate simulations, with each such simulation 
using forward prices shaped using historical data from one of the 
three consecutive calendar years preceding the time of the 
determination for the RPM Auction to take account of year-to-year 
variability in such hourly shapes.  Each net energy and ancillary 
services revenue simulation is based on (a) the heat rate and other 
characteristics of such Reference Resource such as assumed 
variable operation and maintenance expenses of $1.19 per MWh 
and $21,170 per start-up, and emissions costs; (b) Forward Hourly 
LMPs for the PJM Region; (c) Forward Hourly Ancillary Services 
Prices, (d) Forward Daily Natural Gas Prices at an appropriate 
pricing point for the PJM Region with a fuel transmission adder

appropriate for such region, as set forth in the PJM Manuals; and 
(e) an assumption that the Reference Resource would be 
dispatched on a Projected EAS Dispatch basis.   
 
A-1) 
For the 2028/2029 and subsequent Delivery Years, the Office of 
the Interconnection shall determine the Net Energy and Ancillary 
Services Revenue Offset each year for the PJM Region as the 67th 
percentile of all of the calculated zonal Net Energy and Ancillary 
Services Revenues Offsets that the Reference Resource is 
projected to receive from the PJM energy and ancillary service 
markets for the applicable Delivery Year from three separate 
simulations, with each such simulation using forward prices 
shaped using historical data from one of the three consecutive 
calendar years preceding the time of the determination for the 
RPM Auction to take account of year-to-year variability in such 
hourly shapes.  Each Net Energy and Ancillary Service Revenue 
Offset simulation is based on (a) the heat rate and other 
characteristics of such Reference Resource such as assumed 
variable operation and maintenance expenses of $2.65 per MWh, 
and emissions costs; (b) Forward Hourly LMPs for the PJM 
Region; (c) Forward Hourly Ancillary Services Prices, (d) Forward 
Daily Natural Gas Prices at an appropriate pricing point for the 
PJM Region with a fuel transmission adder appropriate for such 
region, as set forth in the PJM Manuals; and (e) an assumption that 
the Reference Resource would be dispatched on a Projected EAS 
Dispatch basis. 
 
B)  
The Office of the Interconnection also shall determine a Net 
Energy and Ancillary Service Revenue Offset each year for each 
Zone, using the same procedures and methods as set forth in the 
previous subsection; provided, however, that:  (1) the Forward 
Hourly LMPs for such Zone shall be used in place of the Forward 
Hourly LMP for the PJM Region; (2) if such Zone was not 
integrated into the PJM Region for the entire three calendar years 
preceding the time of the determination for the RPM Auction, then 
simulations shall rely on only those whole calendar years during 
which the Zone was integrated; and (3) Forward Daily Natural Gas 
Prices for the fuel pricing point mapped to such Zone. 
 
C) 
“Forward Hourly LMPs” shall be determined as follows:  
 
(1)  
Identify the liquid hub to which each Zone is mapped, as 
specified in the PJM Manuals. 
 
(2)  
For each liquid hub, calculate the average day-ahead on-
peak and day-ahead off-peak energy prices for each month 
during the Delivery Year over the most recent thirty trading

days as of 180 days prior to the Base Residual Auction.  
For each of the remaining steps, the historical prices used 
herein shall be taken from the most recent three calendar 
years preceding the time of the determination for the RPM 
Auction: 
 
(3)  
Determine and add monthly basis differentials between the 
hub and each of its mapped Zones to the forward monthly 
day-ahead on-peak and off-peak energy prices for the hub. 
This differential is developed using the prices for the 
Planning Period closest in time to the Delivery Year from 
the most recent long-term Financial Transmission Rights 
auction conducted prior to the Base Residual Auction. The 
difference between the annual long-term Financial 
Transmission Rights auction prices for the Zone and the 
hub are converted to monthly values by adding, for each 
month of the year, the difference between (a) the historical 
monthly average day-ahead congestion price differentials 
between the Zone and relevant hub and (b) the historical 
annual average day-ahead congestion price differentials 
between the Zone and hub. This step is only used when 
developing forward prices for locations other than the 
liquid hubs;  
 
(4)  
Determine and add marginal loss differentials to the 
forward monthly day-ahead on-peak and off-peak energy 
prices for the hub.  For each month of the year, calculate 
the marginal loss differential, which is  the average of the 
difference between the loss components of the historical on 
peak or off peak day-ahead LMPs for the Zone and relevant 
hub in that month across the three year period scaled by the 
ratio of (a) the forward monthly average on-peak or off-
peak day-ahead LMP at such hub to (b) the average of the 
historical on-peak or off-peak day-ahead LMPs for such 
hub in that month across the three year period.  This step is 
only used when developing forward prices for locations 
other than the liquid hubs;  
 
(5)  
Shape the forward monthly day-ahead on-peak and off-
peak prices to (a) forward hourly day-ahead LMPs using 
historic hourly day-ahead LMP shapes for the Zone and (b) 
forward hourly real-time LMPs using historic hourly real-
time LMP shapes for the Zone. The historic hourly shapes 
are based on the ratio of the historic day-ahead or real-time 
LMP for the Zone for each given hour in a monthly on-
peak or off-peak period to the average of the historic day-
ahead or real-time LMP for the Zone for all hours in such

monthly on-peak or off-peak period. The historical prices 
used in this step shall be taken from one of each of the most 
recent three calendar years preceding the time of the 
determination for the RPM Auction;  
 
(6)  
For unit-specific energy and ancillary service offset 
calculations, determine and apply basis differentials from 
the Zone to the generation bus to the forward day-ahead 
and real-time hourly LMPs for the Zone.  The differential 
for each hour of the year is developed using the difference 
between the historical DA or RT LMP for the generation 
bus and the historical DA or RT LMP for the Zone in 
which the generation bus is located for that same hour; and  
 
(7)  
Develop the Forward Hourly LMPs for the PJM Region 
pricing point. Calculate the load-weighted average of the 
monthly on-peak and off-peak Zonal LMPs developed in 
step (4) above, using the historical average load within each 
monthly on-peak or off-peak period.  The load-weighted 
average monthly on-peak or off-peak Zonal LMPs are then 
shaped to forward hourly day-ahead and real-time LMPs 
using the same procedure as defined in step (5) above, 
except using historical LMPs for the PJM Region pricing 
point.  
 
D) 
Forward Hourly Ancillary Services Prices shall include prices for 
Synchronized Reserve, Non-Synchronized Reserve and Secondary 
Reserve and shall be determined as follows.  The historical prices 
used herein shall be taken from one of each of the most recent 
three calendar years preceding the time of the determination for the 
RPM Auction: 
 
(1)  
For Synchronized Reserve, the forward real-time 
Synchronized Reserve market clearing price shall be 
calculated by multiplying the historical RTO real-time 
hourly Synchronized Reserve market clearing price for 
each hour of the Delivery Year by the ratio of the real-time 
Forward Hourly LMP at an appropriate pricing point, as 
defined in the PJM manuals, to the historic hourly real-time 
LMP at such pricing point for the corresponding hour of the 
year; 
 
(2)  
For Non-Synchronized Reserve, the forward real-time Non-
Synchronized Reserve market clearing price shall be 
calculated by multiplying the historical RTO real-time 
hourly Non-Synchronized Reserve market clearing price 
for each hour of the Delivery Year by the ratio of the real-

time Forward Hourly LMP at an appropriate pricing point, 
as defined in the PJM manuals, to the historic hourly real-
time LMP at such pricing point for the corresponding hour 
of the year; and 
 
(3)  
For Secondary Reserve, the forward day-ahead and real-
time Secondary Reserve market clearing price shall be 
$0.00/MWh for all hours. 
 
E) 
Forward Daily Natural Gas Prices shall be determined as follows: 
 
(1)  
Map each Zone to the appropriate natural gas hub in the 
PJM Region, as listed in the PJM Manuals; 
 
(2)  
Map each natural gas hub lacking sufficient liquidity to the 
liquid hub to which it has the highest historic price 
correlation; 
 
(3)  
For each sufficiently liquid natural gas hub, calculate the 
simple average natural gas monthly settlement prices over 
the most recent thirty trading days as of 180 days prior to 
the Base Residual Auction; 
 
(4)  
Calculate the forward monthly prices for each illiquid hub 
by scaling the forward monthly price of the mapped liquid 
hub by the average ratio of historical monthly prices at the 
insufficiently liquid hub to the historical monthly prices at 
the sufficiently liquid over the most recent three calendar 
years preceding the time of determination for the RPM 
Auction; 
 
(5)   
Shape the forward monthly prices for each hub to Forward 
Daily Natural Gas Prices using historic daily natural gas 
price shapes for the hub. The historic daily shapes are 
based on the ratio of the historic price for the hub for each 
given day in a month to the average of the historic prices 
for the hub for all days in such month. The daily prices are 
then assigned to each hour starting 10am Eastern Prevailing 
Time each day. The historical prices used in this step shall 
be taken from one of each of the most recent three calendar 
years preceding the time of the determination for the RPM 
Auction. 
 
vi) 
Process for Establishing Parameters of Variable Resource Requirement 
Curve

A) 
The parameters of the Variable Resource Requirement Curve will 
be established prior to the conduct of the Base Residual Auction 
for a Delivery Year and will be used for such Base Residual 
Auction. 
 
B) 
The Office of the Interconnection shall determine the PJM Region 
Reliability Requirement and the Locational Deliverability Area 
Reliability Requirement for each Locational Deliverability Area 
for which a Variable Resource Requirement Curve has been 
established for such Base Residual Auction on or before February 
1, prior to the conduct of the Base Residual Auction for the first 
Delivery Year in which the new values will be applied, in 
accordance with the Reliability Assurance Agreement.  The 
Variable Resource Requirement Curve shall be posted on the same 
timeline with the PJM Region Reliability Requirement and the 
Locational Deliverability Area Reliability Requirement. 
Notwithstanding, for the 2029/2030 Delivery Year, the updated 
VRR Curve that incorporates any Excluded RTO New Large Load 
Amounts and Excluded LDA New Large Load Amounts shall be 
posted one month prior to the commencement of the relevant RPM 
Auction. 
 
C) 
Beginning with the Delivery Year that commences June 1, 2018, 
and continuing no later than for every fourth Delivery Year 
thereafter, the Office of the Interconnection shall review the 
calculation of the Cost of New Entry for each CONE Area.  
 
1) 
If the Office of the Interconnection determines that the Cost 
of New Entry values should be modified, the Staff of the 
Office of the Interconnection shall propose new Cost of 
New Entry values on or before May 15, prior to the conduct 
of the Base Residual Auction for the first Delivery Year in 
which the new values would be applied. 
 
2) 
The PJM Members shall review the proposed values. 
 
3) 
The PJM Members shall either vote to (i) endorse the 
proposed values, (ii) propose alternate values or (iii) 
recommend no modification, by August 31, prior to the 
conduct of the Base Residual Auction for the first Delivery 
Year in which the new values would be applied. 
 
4) 
The PJM Board of Managers shall consider Cost of New 
Entry values, and the Office of the Interconnection shall 
file any approved modified Cost of New Entry values 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. 
 
D) 
Beginning with the Delivery Year that commences June 1, 2018, 
and continuing no later than for every fourth Delivery Year 
thereafter, the Office of the Interconnection shall review the 
methodology set forth in this Attachment for determining the Net 
Energy and Ancillary Services Revenue Offset for the PJM Region 
and for each Zone. 
 
1) 
If the Office of the Interconnection determines that the Net 
Energy and Ancillary Services Revenue Offset 
methodology should be modified, Staff of the Office of the 
Interconnection shall propose a new Net Energy and 
Ancillary Services Revenue Offset methodology on or 
before May 15, prior to the conduct of the Base Residual 
Auction for the first Delivery Year in which the new 
methodology would be applied.   
 
2) 
The PJM Members shall review the proposed methodology. 
 
3) 
The PJM Members shall either vote to (i) endorse the 
proposed methodology, (ii) propose an alternate 
methodology or (iii) recommend no modification, by 
August 31, prior to the conduct of the Base Residual 
Auction for the first Delivery Year in which the new 
methodology would be applied. 
 
4) 
The PJM Board of Managers shall consider the Net 
Revenue Offset methodology, and the Office of the 
Interconnection shall file any approved modified Net 
Energy and Ancillary Services Revenue Offset values 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.  
 
 
b) 
Locational Requirements 
 
The Office of Interconnection shall establish locational requirements prior to the Base Residual 
Auction to quantify the amount of Unforced Capacity that must be committed in each Locational 
Deliverability Area, in accordance with the Reliability Assurance Agreement. 
 
c) 
[Reserved] 
 
d) 
Preliminary PJM Region Peak Load Forecast for the Delivery Year

The Office of the Interconnection shall establish the Preliminary PJM Region Load Forecast for 
the Delivery Year in accordance with the PJM Manuals by February 1, prior to the conduct of the 
Base Residual Auction for such Delivery Year.   
 
 
e) 
Updated PJM Region Peak Load Forecasts for Incremental Auctions 
 
The Office of the Interconnection shall establish the updated PJM Region Peak Load Forecast for 
a Delivery Year in accordance with the PJM Manuals by February 1, prior to the conduct of the 
First, Second, and Third Incremental Auction for such Delivery Year.

5.11 
Posting of Information Relevant to the RPM Auctions 
 
 
a) 
In accordance with the schedule provided in the PJM Manuals, PJM will post the 
following information for a Delivery Year prior to conducting the Base Residual Auction for 
such Delivery Year: 
 
i) 
The Preliminary PJM Region Peak Load Forecast (for the PJM Region, 
and allocated to each Zone); 
 
ii) 
The PJM Region Installed Reserve Margin, the Pool-wide average 
EFORd, (through the 2024/2025 Delivery Year), the pool-wide average Accredited UCAP 
Factor (beginning with the 2025/2026 Delivery Year), the Forecast Pool Requirement, and all 
applicable Capacity Import Limits; 
 
iii) 
Beginning with the 2029/2030 Delivery Year, the quantity of Excluded 
RTO New Large Load Amounts and Excluded LDA New Large Load Amounts used in 
establishing the Variable Resource Requirement Curve; 
 
iv) 
The PJM Region Reliability Requirement, and the Variable Resource 
Requirement Curve for the PJM Region, including the details of any adjustments to account for 
Price Responsive Demand and any associated PRD Reservation Prices; 
 
v) 
The Locational Deliverability Area Reliability Requirement and the 
Variable Resource Requirement Curve for each Locational Deliverability Area for which a 
separate Variable Resource Requirement Curve has been established for such Base Residual 
Auction, including the details of any adjustments to account for Price Responsive Demand and 
any associated PRD Reservation Prices, and the CETO and CETL values for all Locational 
Deliverability Areas; 
 
vi) 
Any Transmission Upgrades that are expected to be in service for such 
Delivery Year, provided that a Transmission Upgrade that is Backbone Transmission satisfies 
the project development milestones set forth in Tariff, Attachment DD, section 5.11A; 
 
vii) 
The bidding window time schedule for each auction to be conducted for 
such Delivery Year; and 
 
viii) 
The Net Energy and Ancillary Services Revenue Offset values for the 
PJM Region for use in the Variable Resource Requirement Curves for the PJM Region and each 
Locational Deliverability Area for which a separate Variable Resource Requirement Curve has 
been established for such Base Residual Auction. 
 
 
b) 
The information listed in (a) will be posted and applicable for the First, Second, 
Third, and Conditional Incremental Auctions for such Delivery Year, except to the extent 
updated or adjusted as required by other provisions of this Tariff.

c) 
In accordance with the schedule provided in the PJM Manuals, PJM will post the 
Final PJM Region Peak Load Forecast and the allocation to each zone of the obligation resulting 
from such final forecast, following the completion of the final Incremental Auction (including 
any Conditional Incremental Auction) conducted for such Delivery Year;  
 
 
d) 
In accordance with the schedule provided in the PJM Manuals, PJM will advise 
owners of Generation Capacity Resources of the updated EFORd values for such Generation 
Capacity Resources prior to the conduct of the Third Incremental Auction for such Delivery 
Year. 
 
 
e) 
After conducting the Reliability Pricing Model Auctions, PJM will post the results 
of each auction as soon thereafter as possible, including any adjustments to PJM Region or LDA 
Reliability Requirements to reflect Price Responsive Demand with a PRD Reservation Price 
equal to or less than the applicable Base Residual Auction clearing price.  The posted results for 
each Base Residual Auction shall include graphical supply curves that are (a) provided for the 
entire PJM Region, (b) provided for any Locational Deliverability Area for which there are four 
(4) or more suppliers, and (c) developed using a formulaic approach to smooth the curves using a 
statistical technique that fits a smooth curve to the underlying supply curve data while ensuring 
that the point of intersection between supply and demand curves is at the market clearing price.   
 
If PJM discovers a potential error in the initial posting of auction results for a particular 
Reliability Pricing Model Auction, it shall notify Market Participants as soon as possible after it 
is found, but in no event later than 5:00 p.m. of the fifth Business Day following the initial 
publication of the results of the auction.  After this initial notification, if PJM determines it is 
necessary to post modified results, it shall provide notification of its intent to do so,  along with a 
description detailing the cause and scope of the error, by no later than 5:00 p.m. of the seventh 
Business Day following the initial publication of the results of the auction.  The provided 
description will not contain information that is market sensitive or confidential.  Thereafter, PJM 
must post on its Web site any corrected auction results by no later than 5:00 p.m. of the tenth 
Business Day following the initial publication of the results of the auction. Should any of the 
above deadlines pass without the associated action on the part of the Office of the 
Interconnection, the originally posted results will be considered final. Notwithstanding the 
foregoing, the deadlines set forth above shall not apply if the referenced auction results are under 
publicly noticed review by the FERC.

5.12 
Conduct of RPM Auctions 
 
The Office of the Interconnection shall employ an optimization algorithm for each Base Residual 
Auction and each Incremental Auction to evaluate the Sell Offers and other inputs to such auction 
to determine the Sell Offers that clear such auction.   
 
 
a) 
Base Residual Auction  
 
For each Base Residual Auction, the optimization algorithm shall consider: 
 
 
all Sell Offers submitted in such auction; 
 
 
the Variable Resource Requirement Curves for the PJM Region and each 
LDA; 
 
 
any constraints resulting from the Locational Deliverability Requirement 
and any applicable Capacity Import Limit; 
 
 
For the 2018/2019 Delivery Year and subsequent Delivery Years, the PJM 
Reliability Requirement; and 
 
 
For the 2020/2021 Delivery Year and subsequent Delivery Years, the   
requirement that the cleared quantity of Summer-Period Capacity 
Performance Resources equal the cleared quantity of Winter-Period 
Capacity Performance Resources for the PJM Region. 
 
The optimization algorithm shall be applied to calculate the overall clearing result to minimize the 
cost of satisfying the reliability requirements across the PJM Region, regardless of whether the 
quantity clearing the Base Residual Auction is above or below the applicable target quantity, while 
respecting all applicable requirements and constraints, including any restrictions specified in any 
Credit-Limited Offers.  Where the supply curve formed by the Sell Offers submitted in an auction 
falls entirely below the Variable Resource Requirement Curve, the auction shall clear at the price-
capacity point on the Variable Resource Requirement Curve corresponding to the total Unforced 
Capacity provided by all such Sell Offers.  Where the supply curve consists only of Sell Offers 
located entirely below the Variable Resource Requirement Curve and Sell Offers located entirely 
above the Variable Resource Requirement Curve, the auction shall clear at the price-capacity point 
on the Variable Resource Requirement Curve corresponding to the total Unforced Capacity 
provided by all Sell Offers located entirely below the Variable Resource Requirement Curve.  In 
determining the lowest-cost overall clearing result that satisfies all applicable constraints and 
requirements, the optimization may select from among multiple possible alternative clearing 
results that satisfy such requirements, including, for example (without limitation by such example), 
accepting a lower-priced Sell Offer that intersects the Variable Resource Requirement Curve and 
that specifies a minimum capacity block, accepting a higher-priced Sell Offer that intersects the 
Variable Resource Requirement Curve and that contains no minimum-block limitations, or 
rejecting both of the above alternatives and clearing the auction at the higher-priced point on the 
Variable Resource Requirement Curve that corresponds to the Unforced Capacity provided by all

Sell Offers located entirely below the Variable Resource Requirement Curve.  For the 2020/2021 
Delivery Year and subsequent Delivery Years, the supply curve formed by the Sell Offers 
submitted within an LDA for which a separate VRR Curve is established, shall only consider the 
quantity of MW from Summer-Period Capacity Performance Resources that are equally matched 
with Winter-Period Capacity Performance Resources within the LDA, such that only the equally 
matched quantity of opposite-season Sell Offers are considered in satisfying the LDA’s reliability 
requirement. 
 
The Sell Offer price of a Qualifying Transmission Upgrade shall be treated as a capacity price 
differential between the LDAs specified in such Sell Offer between which CETL is increased, and 
the Import Capability provided by such upgrade shall clear to the extent the difference in clearing 
prices between such LDAs is greater than the price specified in such Sell Offer.  The Capacity 
Resource clearing results and Capacity Resource Clearing Prices so determined shall be applicable 
for such Delivery Year.  The Capacity Resource clearing results and Capacity Resource Clearing 
Prices determined for Summer-Period Capacity Performance Resources shall be applicable for the 
calendar months of June through October and the following May of such Delivery Year; and shall 
be applicable for Winter-Period Capacity Performance Resources for the calendar months of 
November through April of such Delivery Year. 
 
 
b) 
Scheduled Incremental Auctions. 
 
 
For purposes of a Scheduled Incremental Auction, the optimization algorithm shall consider: 
 
  
For the 2018/2019 Delivery Year and subsequent Delivery Years, the PJM 
Reliability Requirement; 
 
 
Updated LDA Reliability Requirements taking into account any updated Capacity 
Emergency Transfer Objectives; 
 
 
The Capacity Emergency Transfer Limit used in the Base Residual Auction, or any 
updated value resulting from a Conditional Incremental Auction; 
 
 
All applicable Capacity Import Limits; 
 
 
For the 2018/2019 Delivery Year and subsequent Delivery Years, for each LDA, 
such LDA’s updated Reliability Requirement; 
 
 
 
For the 2020/2021 Delivery Year and subsequent Delivery Years, the   requirement 
that the cleared quantity of Summer-Period Capacity Performance Resources equal 
the cleared quantity of Winter-Period Capacity Performance Resources for the PJM 
Region; 
 
 
A demand curve consisting of the Buy Bids submitted in such auction and, if 
indicated for use in such auction in accordance with the provisions below, the 
Updated VRR Curve Increment;

 
The Sell Offers submitted in such auction; and 
 
 
The Unforced Capacity previously committed for such Delivery Year. 
 
(i) 
When the requirement to seek additional resource commitments in a 
Scheduled Incremental Auction is triggered by Tariff, Attachment DD, section 5.4(c)(2), the 
Office of the Interconnection shall employ in the clearing of such auction the Updated VRR Curve 
Increment.      
 
(ii) 
When the requirement to seek additional resource commitments in a 
Scheduled Incremental Auction is triggered by Tariff, Attachment DD, section 5.4(c)(1), and the 
conditions stated in Tariff, Attachment DD, section 5.4(c)(2) do not apply, the Office of the 
Interconnection first shall determine the total quantity of (A) the amount that the Office of the 
Interconnection sought to procure in prior Scheduled Incremental Auctions for such Delivery Year 
that does not clear such auction, minus (B) the amount that the Office of the Interconnection sought 
to sell back in prior Scheduled Incremental Auctions for such Delivery Year that does not clear 
such auction, plus (C) the difference between the updated PJM Region Reliability Requirement or 
updated LDA Reliability Requirement (inclusive of any updated adjustments to the Excluded RTO 
New Large Load Amounts and/or Excluded LDA New Large Load Amounts) and, respectively, 
the PJM Region Reliability Requirement, or LDA Reliability Requirement (inclusive of any 
updated adjustments to the Excluded RTO New Large Load Amounts and/or Excluded LDA New 
Large Load Amounts), utilized in the most recent prior auction conducted for such Delivery Year 
plus any amount required by section 5.4(c)(2)(ii), plus (D) the reduction in Unforced Capacity 
commitments associated with the transition provisions of Tariff, Attachment DD, section 
5.5A(c)(i)(B) and RAA, Schedule 6, section L.9.  If the result of such equation is a positive 
quantity, the Office of the Interconnection shall employ in the clearing of such auction a portion 
of the Updated VRR Curve Increment extending right from the left-most point on that curve in a 
megawatt amount equal to that positive quantity defined above, to seek to procure such quantity.  
If the result of such equation is a negative quantity, the Office of the Interconnection shall employ 
in the clearing of the auction a portion of the Updated VRR Curve Decrement, extending and 
ascending to the left from the right-most point on that curve in a megawatt amount corresponding 
to the negative quantity defined above, to seek to sell back such quantity.  
 
 (iii) 
When the possible need to seek agreements to release capacity 
commitments in any Scheduled Incremental Auction is indicated for the PJM Region or any 
LDA by Tariff, Attachment DD, section 5.4(c)(3)(i), the Office of the Interconnection first shall 
determine the total quantity of (A) the amount that the Office of the Interconnection sought to 
procure in prior Scheduled Incremental Auctions for such Delivery Year that does not clear such 
auction, minus (B) the amount that the Office of the Interconnection sought to sell back in prior 
Scheduled Incremental Auctions for such Delivery Year that does not clear such auction, plus 
(C) the difference between the updated PJM Region Reliability Requirement or updated LDA 
Reliability Requirement (inclusive of any updated adjustments to the Excluded RTO New Large 
Load Amounts and/or Excluded LDA New Large Load Amounts) and, respectively, the PJM 
Region Reliability Requirement, or LDA Reliability Requirement (inclusive of any updated 
adjustments to the Excluded RTO New Large Load Amounts and/or Excluded LDA New Large

Load Amounts), utilized in the most recent prior auction conducted for such Delivery Year 
minus any capacity sell-back amount determined by PJM to be required for the PJM Region or 
such LDA by Tariff, Attachment DD, section 5.4(c)(3)(ii), plus (D) the reduction in Unforced 
Capacity commitments associated with the transition provisions of Tariff, Attachment DD, 
section 5.5A(c)(i)(B) and RAA, Schedule 6, section L.9, provided, however, that the amount sold 
in total for all LDAs and the PJM Region related to a delay in a Backbone Transmission upgrade 
may not exceed the amounts purchased in total for all LDAs and the PJM Region related to a 
delay in a Backbone Transmission upgrade.  If the result of such equation is a positive quantity, 
the Office of the Interconnection shall employ in the clearing of such auction a portion of the 
Updated VRR Curve Increment extending right from the left-most point on that curve in a 
megawatt amount equal to that positive quantity defined above, to seek to procure such quantity.  
If the result of such equation is a negative quantity, the Office of the Interconnection shall 
employ in the clearing of the auction a portion of the Updated VRR Curve Decrement, extending 
and ascending to the left from the right-most point on that curve in a megawatt amount 
corresponding to the negative quantity defined above, to seek to sell back such quantity.   
 
(iv) 
If none of the tests for adjustment of capacity procurement in subsections 
(i), (ii), or (iii) is satisfied for the PJM Region or an LDA in a Scheduled Incremental Auction, the 
Office of the Interconnection first shall determine the total quantity of (A) the amount that the 
Office of the Interconnection sought to procure in prior Scheduled Incremental Auctions for such 
Delivery Year that does not clear such auction, minus (B) the amount that the Office of the 
Interconnection sought to sell back in prior Scheduled Incremental Auctions for such Delivery 
Year that does not clear such auction.  If the result of such equation is a positive quantity, the 
Office of the Interconnection shall employ in the clearing of such auction a portion of the Updated 
VRR Curve Increment extending right from the left-most point on that curve in a megawatt amount 
equal to that positive quantity defined above, to seek to procure such quantity.  If the result of such 
equation is a negative quantity, the Office of the Interconnection shall employ in the clearing of 
the auction a portion of the Updated VRR Curve Decrement, extending and ascending to the left 
from the right-most point on that curve in a megawatt amount corresponding to the negative 
quantity defined above, to seek to sell back such quantity.   
 
(v) 
 (reserved) 
 
 (vi) 
If the above tests are triggered for an LDA and for another LDA wholly 
located within the first LDA, the Office of the Interconnection may adjust the amount of any Sell 
Offer or Buy Bids otherwise required by subsections (i), (ii), or (iii) above in one LDA as 
appropriate to take into account any reliability impacts on the other LDA.  
 
 (vii) The optimization algorithm shall calculate the overall clearing result to 
minimize the cost to satisfy the Unforced Capacity Obligation of the PJM Region to account for 
the updated PJM Peak Load Forecast and the cost of committing replacement capacity in response 
to the Buy Bids submitted, while satisfying or honoring such reliability requirements and 
constraints, in the same manner as set forth in subsection (a) above. 
 
 (viii) Load Serving Entities may be entitled to certain credits (“Excess 
Commitment Credits”) under certain circumstances as follows:

(A) 
[Reserved] 
 
(B) 
For any Delivery Year beginning with the Delivery Year that commences 
June 1, 2012, the total amount  that the Office of the Interconnection sought 
to sell back pursuant to subsection (b)(iii) above in the Scheduled 
Incremental Auctions for such Delivery Year that does not clear such 
auctions, less the total amount that the Office of the Interconnection sought 
to procure pursuant to subsections (b)(i) and (b)(ii) above in the Scheduled 
Incremental Auctions for such Delivery Years that does not clear such 
auctions, will be allocated to Load Serving Entities as set forth below;  
 
(C) 
the amount from (A) or (B) above for the PJM Region shall be allocated 
among Locational Deliverability Areas pro rata based on the reduction for 
each such Locational Deliverability Area in the peak load forecast from the 
time of the Base Residual Auction to the time of the Third Incremental 
Auction; provided, however, that the amount allocated to a Locational 
Deliverability Area may not exceed the reduction in the corresponding 
Reliability Requirement for such Locational Deliverability Area; and 
provided further that any LDA with an increase in its load forecast shall not 
be allocated any Excess Commitment Credits; 
 
(D) 
the amount, if any, allocated to a Locational Deliverability Area shall be 
further allocated among Load Serving Entities in such areas that are charged 
a Locational Reliability Charge based on the Daily Unforced Capacity 
Obligation of such Load Serving Entities as of June 1 of the Delivery Year 
and shall be constant for the entire Delivery Year.  Excess Commitment 
Credits may be used as Replacement Capacity or traded bilaterally. 
 
 
c) 
Conditional Incremental Auction   
 
For each Conditional Incremental Auction, the optimization algorithm shall consider: 
 
 
The quantity and location of capacity required to address the identified reliability 
concern that gave rise to the Conditional Incremental Auction;  
 
 
 
All applicable Capacity Import Limits; 
 
 
the same Capacity Emergency Transfer Limits that were modeled in the Base 
Residual Auction, or any updated value resulting from a Conditional Incremental 
Auction; and  
 
 
the Sell Offers submitted in such auction.

The Office of the Interconnection shall submit a Buy Bid based on the quantity and location of 
capacity required to address the identified reliability violation at a Buy Bid price equal to 1.5 times 
Net CONE.   
 
The optimization algorithm shall calculate the overall clearing result to minimize the cost to 
address the identified reliability concern, while satisfying or honoring such reliability requirements 
and constraints. 
 
 
d) 
Equal-priced Sell Offers 
 
If two or more Sell Offers submitted in any auction satisfying all applicable constraints include 
the same offer price, and some, but not all, of the Unforced Capacity of such Sell Offers is required 
to clear the auction, then the auction shall be cleared in a manner that minimizes total costs, 
including total make-whole payments if any such offer includes a minimum block and, to the extent 
consistent with the foregoing, in accordance with the following additional principles: 
 
1) 
as necessary, the optimization shall clear such offers that have a flexible 
megawatt quantity, and the flexible portions of such offers that include a minimum block that 
already has cleared, where some but not all of such equal-priced flexible quantities are required to 
clear the auction, pro rata based on their flexible megawatt quantities; and  
 
2) 
when equal-priced minimum-block offers would result in equal overall 
costs, including make-whole payments, and only one such offer is required to clear the auction, 
then the offer that was submitted earliest to the Office of the Interconnection, based on its assigned 
timestamp, will clear.

ATTACHMENT DD-4 
INTERIM RESOURCE ADEQUACY SERVICE

I. 
INTRODUCTION 
 
This Attachment DD-4 sets forth the terms and conditions governing the provision of Interim 
Resource Adequacy Service.  As more fully set forth in this Attachment and the PJM Manuals, 
and in conjunction with the Reliability Assurance Agreement: 
 
 
(a) 
Interim Resource Adequacy Service is a load reduction service, effective starting 
with the 2027/2028 Delivery Year, through which Eligible New Large Loads may be compensated 
for providing load reductions requested by the Office of the Interconnection to maintain system 
reliability for the purpose of supporting the integration of New Large Loads to the PJM Region 
that are not in arrangements with new capacity additions to the PJM Region; 
 
 
(b) 
Starting with the 2027/2028 Delivery Year, the Office of the Interconnection may, 
in accordance with the Manuals, instruct the implementation of an Interim Resource Adequacy 
Service Action prior to calling on Pre-Emergency Load Management Reductions Actions after 
determining that available economic real-time supply may not be sufficient to maintain reserves 
to meet applicable Reserve Requirements and/or Interconnection Reliability Operating Limits 
within prescribed limits and prevent cascading outages; 
 
(c) 
The Large Load Registry maintained by the Office of the Interconnection, pursuant 
to the Reliability Assurance Agreement, shall inform which New Large Loads are eligible to be 
called on to provide Interim Resource Adequacy Service; and 
 
(d) 
The Office of the Interconnection shall coordinate with Electric Distributors, and 
other Members as appropriate, on the provision of Interim Resource Adequacy Service and the 
compensation for providing Interim Resource Adequacy Service.

II. 
RESPONSBILITIES OF THE OFFICE OF THE INTERCONNECTION  
 
The Office of the Interconnection shall: 
 
(a) 
maintain the Large Load Registry, pursuant to Reliability Assurance Agreement, 
Schedule 11; 
 
(b) 
identify Eligible New Large Loads;  
 
(c) 
determine the megawatt quantity of New Large Loads eligible to provide Interim 
Resource Adequacy Service in each Electric Distributor zone/area for a given 
Delivery Year;  
 
(d) 
starting with the 2027/2028 Delivery Year, issue an Interim Resource Adequacy 
Service Action based on system conditions; and 
 
(e) 
request Electric Distributors to direct that a quantity of Eligible New Large Load 
Amounts in their respective zone(s)/area(s) be reduced in accordance with an 
Interim Resource Adequacy Service Action.

III. 
RESPONSBILITIES OF ELECTRIC DISTRIBUTORS 
 
Electric Distributors shall: 
 
(a)  
execute the Office of the Interconnection’s directives to implement Interim 
Resource Adequacy Service Actions among the Eligible New Large Loads in the 
Electric Distributor’s zone/area, which is an area within a Zone for which the 
relevant Electric Distributor specifies a separate Obligation Peak Load MW value 
and is a service area of an Electric Distributor that is a separately identifiable, 
geographic area bounded by wholesale metering;  
 
(b) 
coordinate with the Office of the Interconnection in developing and maintaining the 
Large Load Registry by providing the Office of the Interconnection any information 
or data the Electric Distributor believes appropriate to facilitate an accurate Large 
Load Registry, including applicable state or RERRA retail tariff or contractual 
obligations;  
 
(c) 
coordinate, as appropriate, with the relevant state(s) or RERRA(s), individual Load 
Serving Entities, and customers served by the Load Serving Entities in its zone/area 
to support transparent, effective, and orderly deployment of Interim Resource 
Adequacy Service; and 
 
(d) 
implement compensation program consistent with Tariff, Attachment DD-4, 
section X.

IV. 
DETERMINATION OF MAXIMUM INTERIM RESOURCE ADEQUACY 
SERVICE EACH ELIGIBLE NEW LARGE LOAD MAY PROVIDE IN A 
DELIVERY YEAR 
 
(a) 
All Eligible New Large Loads shall be available to be requested to provide Interim 
Resource Adequacy Service by the Office of the Interconnection.   
 
(b) 
The amount of Interim Resource Adequacy Service available to the Office of the 
Interconnection may change for each Delivery Year depending on the relationship of the amount 
of Capacity Resources committed, through Tariff, Attachment DD, for a given Delivery Year, and 
the Eligible New Large Load Amounts. 
 
(i) 
In the event ([the amount of Capacity Resources committed for a given Delivery 
Year (as determined after the Third Incremental Auction) is less than the PJM 
Region Reliability Requirement determined prior to the Third Incremental Auction] 
divided by the Pool-wide Accredited UCAP Factor) by an amount greater than the 
sum (in MW) of all Eligible New Large Load Amounts, then all Eligible New Large 
Load Amounts is needed by the Office of the Interconnection to be available to 
provide Interim Resource Adequacy Service for that Delivery Year;  
 
(ii) 
In the event ([the amount of Capacity Resources committed for a given Delivery 
Year (as determined after the Third Incremental Auction) is less than the PJM 
Region Reliability Requirement determined prior to the Third Incremental Auction] 
divided by the Pool-wide Accredited UCAP Factor) by an amount less than the sum 
(in MW) of all Eligible New Large Load Amounts, then the difference (in MW) 
shall be the cumulative amount (in MW) of Eligible New Large Load Amounts that 
the Office of the Interconnection needs to be available to provide Interim Resource 
Adequacy Service for that Delivery Year; and 
 
(iii) 
In the event ([the amount of Capacity Resources committed for a given Delivery 
Year (as determined after the Third Incremental Auction) equals or exceeds the 
PJM Region Reliability Requirement determined prior to the Third Incremental 
Auction] divided by the Pool-wide Accredited UCAP Factor), then the Office of 
the Interconnection does not need any Eligible New Large Loads to be available to 
provide Interim Resource Adequacy Service for that Delivery Year. 
 
(c) 
For each Delivery Year that meets the requirements of Tariff, Attachment DD-4, sections 
IV(b)(i) or IV(b)(ii), the Office of the Interconnection shall determine:  
 
(i) 
the total amount of Interim Resource Adequacy Service (in MW) needed to be 
available on a daily basis across the PJM Region for the Delivery Year; and  
 
(ii) 
the total amount of Interim Resource Adequacy Service (in MW) needed to be 
available on a daily basis in each Electric Distributor zone/area for the Delivery 
Year, which shall be equal to

the product of the sum of all Eligible New Large Load Amounts 
needed in the PJM Region pursuant to Attachment DD-4, section 
IV(b) multiplied by the quotient of [(the sum of all Eligible New 
Large Load Amounts in the Electric Distributor’s zone/area) divided 
by (the sum of all Eligible New Large Load Amounts in the PJM 
Region)].

V. 
DETERMINATION OF NEW LARGE LOADS ELIGIBILITY TO PROVIDE 
INTERIM RESOURCE ADEQUACY SERVICE 
 
(a) 
All New Large Loads shall be Eligible New Large Loads to the extent that the sum of a 
New Large Load’s Eligible New Large Load Amount is less than the New Large Load’s registered 
peak load (in MW), as provided in the Large Load Registry.  New Large Loads with a cumulative 
installed capacity equivalent of their BYONC arrangements and assigned Allocated RBP UCAP 
MW that equals or exceeds the New Large Load’s registered peak load, as provided in the Large 
Load Registry, shall not be Eligible New Large Loads.  New Large Loads that are located within 
an FRR Service Area cannot be Eligible New Large Loads. 
 
(b) 
A New Large Load’s Eligible New Large Load Amount shall be determined as follows: 
 
(New Large Load’s registered peak load (in MW), as provided in the Large Load 
Registry) minus (the sum of all BYONC arrangements with the New Large Load 
in accordance with Tariff, Attachment DD-4, section VII divided by the Forecast 
Pool Requirement for the first Delivery Year in which the BYONC cleared an RPM 
Auction, plus Allocated RBP UCAP MW assigned to the New Large Load, in 
accordance with Tariff, Attachment DD-4, section IX divided by the Forecast Pool 
Requirement for the first Delivery Year in which the Allocated RBP UCAP MW 
cleared an RPM Auction). 
 
(c) 
For purposes of removing its eligibility to provide Interim Resource Adequacy Service, a 
New Large Load may enter into arrangements with BYONC supported by one or more resources.

VI. 
BRING YOUR OWN NEW CAPACITY CRITERIA 
 
(a) 
(i) 
Capacity Resources that cleared an RPM Auction for the first time in the Base 
Residual Auction for the 2027/2028, 2028/2029, and 2029/2030 Delivery Years may 
qualify as BYONC to the extent the underlying resource meets the criteria in subsection 
(b) below. 
 
(ii) 
Megawatts of Unforced Capacity that have not cleared an RPM Auction, other than 
those specified in subsection (a)(i) above, may qualify as BYONC to the extent the 
underlying resource meets the criteria in subsection (b) below.  To the extent three 
consecutive Delivery Years meet the requirements of Tariff, Attachment DD-4, section 
IV(b)(iii), then megawatts of Unforced Capacity may qualify as BYONC to the extent the 
underlying resource meets the criteria in subsection (b) below and such megawatts (1) have 
not cleared in an RPM Auction conducted for a Delivery Year prior to the first Delivery 
Year for which the requirements of Tariff, Attachment DD-4, section IV(b)(iii) are not met 
and (2) meet the eligibility criteria set forth in Tariff, Attachment DD-4, section VI. 
 
(iii) 
With the exception of the RPM Auctions listed in subsection (a)(i) above, to the 
extent megawatts of Unforced Capacity that have cleared an RPM Auction before any 
arrangement with a New Large Load based on such megawatts was reported to the Office 
of the Interconnection, then such megawatts of Unforced Capacity cannot qualify as 
BYONC even if the underlying resource meets the criteria in subsection (b) below. 
 
(b) 
To qualify as Bring Your Own New Capacity, resources must meet the following eligibility 
requirements: 
 
(i) 
For generation and storage resources, the resource must be supported by one of the 
following: 
 
(1) 
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; 
 
(2) 
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;  
 
(3) 
the incremental capacity created by the utilization of Surplus 
Interconnection Service;  
 
(4) 
repowering of a deactivated generation resource that deactivated prior to 
April 10, 2026; or

(5) 
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. 
 
(ii) 
For Demand Resources or DER Capacity Aggregation Resources, the resource 
must qualify as a Planned Demand Resource or DER Capacity Aggregation Resource, as 
described in the RAA, Schedule 6 and Schedule 6.2 and:  
 
(1) 
be composed of, or reliant on, any location not registered in or prior to the 
2026/2027 Delivery Year at which an incremental amount at that location 
is the result of the registration of new generation or storage assets at the 
location. However, to the extent three consecutive Delivery Years meet the 
requirements of Tariff, Attachment DD-4, section IV(b)(iii), then will be 
composed of, or reliant on, any location registered in the Delivery Year 
prior to the first Delivery Year for which the requirements of Tariff, 
Attachment DD-4, section IV(b)(iii) are not met; and/or 
 
(2) 
be composed of, or reliant on, locations that were not previously supported 
a Capacity Resource, a Peak Shaving Adjustment, or Price Responsive 
Demand for or prior to the 2026/2027 Delivery Year. However, to the extent 
three consecutive Delivery Years meet the requirements of Tariff, 
Attachment DD-4, section IV(b)(iii), then will be composed of, or reliant 
on, locations that were not previously supported a Capacity Resource, a 
Peak Shaving Adjustment, or Price Responsive Demand for the Delivery 
Year prior to the first Delivery Year for which the requirements of Tariff, 
Attachment DD-4, section IV(b)(iii) are not met.

VII. 
BRING YOUR OWN NEW CAPACITY ARRANGEMENTS WITH NEW LARGE 
LOADS 
 
(a) 
For any BYONC to be in an arrangement with a New Large Load,  
 
(i) 
the Load Serving Entity serving the New Large Load or the applicable Electric 
Distributor shall report the BYONC in an arrangement with the New Large Load, in 
accordance with the PJM Manuals.  The Office of the Interconnection may also accept 
information to the extent interconnection customers, Large Loads, Transmission Owners, 
or other entities voluntarily report any BYONC that may be in an arrangement with a New 
Large Load; and    
 
(ii) 
the resource owner or entity with contractual authority to enter into a BYONC 
arrangement must certify to the Office of Interconnection, in accordance with the PJM 
Manuals, attesting to the arrangement with the New Large Load and that the BYONC will 
follow the requirements of Tariff, Attachment DD-4, section VIII. 
 
(b) 
For an arrangement between a New Large Load and BYONC to be effective for the 
2027/2028 and 2028/2029 Delivery Years, for any BYONC arrangement to be considered, the 
requirements of Tariff, Attachment DD-4, section VII(a) must be met by April 1 for the first 
Delivery Year such arrangement is to result in a reduction in the New Large Load’s Eligible New 
Large Load Amount.  By April 15, the Office of the Interconnection shall update the Large Load 
Registry to reflect any verified arrangements between New Large Loads and BYONC.   
 
(c) 
For an arrangement between a New Large Load and BYONC to be effective for the 
2029/2030 Delivery Year, for any BYONC arrangement to be considered, the requirements of 
Tariff, Attachment DD-4, section VII(a) must be reported to the Office of the Interconnection no 
later than by 50 days prior to the commencement of the 2029/2030 Base Residual Auction or by 
30 days prior to the posting of the planning parameters for the Incremental Auctions arrangement 
for the 2029/2030 Delivery Year.  The Office of the Interconnection shall update the Large Load 
Registry to reflect any verified arrangements between New Large Loads and BYONC after the 
relevant RPM Auction. 
 
(d) 
For an arrangement between a New Large Load and BYONC to be effective for the 
2030/2031 Delivery Year and subsequent Delivery Years, the requirements of Tariff, Attachment 
DD-4, section VII(a) must be reported to the Office of the Interconnection no later than by 30 days 
prior to the posting of the planning parameters for the relevant RPM Auction for the initial Delivery 
Year the BYONC enters into an arrangement with the New Large Load.  The Office of the 
Interconnection shall update the Large Load Registry to reflect any verified arrangements between 
New Large Loads and BYONC after the relevant RPM Auction. 
 
(e) 
BYONC that is in an arrangement with a New Large Load must remain in such 
arrangement with that New Large Load unless and until the New Large Load is permanently out-
of-service. 
 
(f) 
A physical resource may support multiple BYONC, each of which may be in an

arrangement with different New Large Loads, as long as no BYONC is in an arrangement with 
more than one New Large Load. 
 
(g) 
A New Large Load may enter into an arrangement with discrete BYONC supported by 
different physical resources. 
 
(h) 
A New Large Load may enter into an arrangement with BYONC in excess of its current 
Eligible Large Load Amount, e.g., to allow for expected growth in the New Large Load, and the 
full megawatt quantity of such BYONC shall be offered in the first RPM Auction for which the 
New Large Load is included in the Variable Resource Requirement Curve. 
 
(i) 
(i) 
For any generation or storage resource, the Accredited UCAP of any BYONC shall 
be the Accredited UCAP for the RPM Auction in which the BYONC cleared for the initial 
Delivery Year the BYONC is in an arrangement with the New Large Load.  
 
(ii) 
For Demand Resources or DER Capacity Aggregation Resources, the Accredited 
UCAP shall be the Accredited UCAP for the RPM Auction in which the BYONC cleared 
for the initial Delivery Year the BYONC is in an arrangement with the New Large Load 
and must be demonstrated each year for a 10-year period using the Demand Response or 
DER Capacity Aggregation Resources installed capacity for the first Delivery Year after 
the BYONC is in an arrangement with the New Large Load.  For Demand Resources or 
DER Capacity Aggregation Resources that are also the actual New Large Load, there is no 
demonstration required for the initial Delivery Year only to not be an Eligible New Large 
Load.

VIII. BRING YOUR OWN NEW CAPACITY PARTICIPATION IN THE RELIABILITY 
PRICING MODEL 
 
(a) 
All BYONC in an arrangement with a New Large Load must meet the requirements in 
Tariff, Attachment DD, section 5.5A and become Capacity Resources eligible to participate in 
RPM Auctions.   
 
(b) 
All BYONC in an arrangement with a New Large Load must be offered into the RPM 
Auctions as Capacity Resources consistent with and pursuant to the capacity must-offer 
requirements and exceptions set forth in Tariff, Attachment DD, sections 6.6 and 6.6A.  BYONC 
may not seek an exception to the capacity must-offer requirement to provide an external sale, as 
available under Tariff, Attachment DD, section 6.6(g) for a 10-year period starting with the first 
Delivery Year which the BYONC is in an arrangement with the New Large Load. 
 
(c) 
All BYONC in an arrangement with a New Large Load and committed through RPM 
Auctions will be subject to all capacity market rules, as set forth in Tariff, Attachments DD and 
DD-1.   
 
(d) 
To the extent the resource supporting a BYONC arrangement is unavailable in a given 
Delivery Year, the seller of such resource will be subject to all relevant deficiency charges under 
Tariff, Attachment DD. 
 
(e)  
All BYONC in an arrangement with a New Large Load 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 for a 10-year period starting with the first 
Delivery Year which the BYONC is in an arrangement with the New Large Load. To the extent 
the resource is a Demand Resource or DER Capacity Aggregation Resource, the BYONC shall 
participate in RPM Auctions for ten (10) consecutive Delivery Years as an Annual Demand 
Resource or DER Capacity Aggregation Resource, as applicable; provided, however, the seller of 
such Demand Resource or DER Capacity Aggregation Resource may, in accordance with Tariff, 
Attachment DD-4, section VII(a)(i) report to the Office of the Interconnection BYONC that 
replaces such BYONC, where such replacement shall be for the remainder of the replaced 
BYONC’s ten-year RPM Auction participation commitment and the replaced BYONC (and its 
supporting registrations) may no longer provide BYONC.  In such event, the replacement BYONC 
would need to be supported by the certification required by Tariff, Attachment DD-4, section 
VII(a)(ii), and such replacement arrangement must be effective coincident with the initial BYONC 
releasing its arrangement.  
 
(f) 
To the extent three consecutive Delivery Years meet the requirements of Tariff, 
Attachment DD-4, section IV(b)(iii), then any existing BYONC are relieved of the obligations 
under this Tariff, Attachment DD-4, section VIII.

IX. 
ALLOCATION OF RBP UCAP MW  
 
(a) 
Each Electric Distributor zone/area allocated RBP Charges pursuant to Tariff, Attachment 
DD, section 18.3(a) shall be allocated RBP UCAP MW on a pro-rata basis using the Electric 
Distributor zone/area’s assigned share of the total Final RBP Target MW across all zone/areas. 
 
(b) 
Each New Large Load’s Allocated RBP UCAP MW shall be determined as follows: 
 
(i) 
Each Electric Distributor allocated RBP UCAP MW shall inform the Office of the 
Interconnection how such RBP UCAP MW should be further allocated among the New 
Large Loads located in the Electric Distributor’s zone/area; or  
 
(ii) 
In the event the Electric Distributor has not informed the Office of the 
Interconnection how its RBP UCAP MW should be further allocated by April 1 before a 
given Delivery Year, the Office of the Interconnection shall allocate such RBP UCAP MW 
to the Electric Distributor’s zone/area pro-rata among all New Large Loads located in the 
zone/area.  
 
(c) 
The Office of the Interconnection shall list in the Large Load Registry each New Large 
Load’s Allocated RBP UCAP MW.

X. 
COMPENSATION FOR PROVIDING INTERIM RESOURCE ADEQUACY 
SERVICE  
 
(a) 
The rate for the provision of Interim Resource Adequacy Service shall be 50% of the Non-
Performance Charge Rate specified in Tariff, Attachment DD, section 10A(e), unless any Eligible 
New Large Load elects to (i) accept in its retail rates a sum less than 50% of the Non-Performance 
Charge Rate as compensation for the provision of wholesale Interim Resource Adequacy Service, 
or (ii) waive receipt in its retail rates any compensation for the provision of wholesale Interim 
Resource Adequacy Service as contemplated by Tariff, Attachment DD-4, section X(c).  If any 
Eligible New Large Load so elects to accept less than 50% of the Non-Performance Charge Rate 
or waives in its entirety receipt of compensation for the provision of wholesale Interim Resource 
Adequacy Service, the wholesale rate for the provision of Interim Resource Adequacy Service 
shall reflect the accepted sum less than 50% of the Non-Performance Charge Rate or if 
compensation is waived entirely, the rate shall be zero dollars.   
 
(b) 
(i) 
Following an Interim Resource Adequacy Event, unless the Electric Distributor 
informs the Office of the Interconnection otherwise in accordance with Tariff, Attachment 
DD-4, section X(b)(ii), the Electric Distributor shall be responsible for compensating all 
Eligible New Large Loads that provided Interim Resource Adequacy Service for up to the 
amount of such service provided.  The Electric Distributor shall be responsible for charging 
customers in its zone/area to fund any such compensation.  
 
(ii) 
The Electric Distributor may request the Office of the Interconnection to 
compensate certain Members for the provision of Interim Resource Adequacy Service and 
to assess charges on certain Load Serving Entities within the Electric Distributor’s 
zone/area to fund such compensation.  In support of such request, as further set forth in the 
PJM Manuals, the Electric Distributor shall (1) identify each Member to be compensated 
and provide the level of compensation and (2) identify each Load Serving Entity to be 
charged and the level of charge. 
 
(iii) 
The Office of the Interconnection, PJMSettlement, and the Members will not 
assume financial responsibility for the failure of a party to pay any amounts owed to 
another party under this section.  In the event the Electric Distributor requests the Office 
of the Interconnection facilitate the billing associated with an Interim Resource Adequacy 
Event, such billing shall be considered a bilateral transaction between the Electric 
Distributor and the identified Members and PJMSettlement shall not be a contracting party 
to the settlement. 
 
(c) 
Nothing in this Tariff, Attachment DD-4, section X shall interfere with any Eligible New 
Large Load’s election to (i) accept in its retail rates a sum less than 50% of the Non-Performance 
Charge Rate as compensation for the provision of wholesale Interim Resource Adequacy Service, 
or (ii) waive receipt in its retail rates any compensation for the provision of wholesale Interim 
Resource Adequacy Service.

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. 
 
 
Bring Your Own New Capacity: 
 
“Bring Your Own New Capacity” or “BYONC” shall have the meaning provided in the Tariff. 
 
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: 
 
“Large Load” shall mean end-use customer(s) load that has a cumulative peak load of 50 
megawatts or greater at a single electrical site behind one or more points of interconnection, 
where for configurations involving multiple affiliated load facilities or multiple points of 
interconnection with affiliated load facilities behind them, all affiliated load facilities within a 
one-mile radius will be considered a single electrical site as further described in the PJM 
Manuals. 
 
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 Governing Agreements: 
 
“PJM Governing Agreements” shall have the meaning provided in the Operating Agreement. 
 
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.  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.

7.8  
Requirement to Designate Network Resources to Serve Capacity Needs for New 
Large Loads and Conditional Requirement to Provide Interim Resource Adequacy Service 
 
Effective June 1, 2027, each LSE that desires to provide Network Transmission Service to support 
New Large Loads must designate one or more Generation Capacity Resources or Capacity Storage 
Resources that had not cleared an RPM Auction as Network Resource(s) in a cumulative amount 
that equals or exceeds the LSE’s New Large Load’s peak load (in MW) as reported in the Large 
Load Registry pursuant to RAA, Schedule 11 or such New Large Load may be subject to load 
reduction requests during Emergencies prior to Pre-Emergency Load Management Response.  If, 
on June 1, 2027, an LSE has not so designated such Network Resource(s) as BYONC with which 
it has entered into an arrangement in accordance with this requirement and Tariff, Attachment DD-
4, then the amount of New Large Load that is the difference between its reported peak load and its 
designated Bring Your Own New Capacity and assigned Allocated RBP UCAP MW will be 
subject to the rates, terms, and conditions of Interim Resource Adequacy Service, as set forth in 
Tariff, Attachment DD-4.

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 include in its FRR Capacity Plan any MW 
quantity of Existing Generation Capacity Resource in excess of what such FRR Entity owned or 
contracted by such FRR Entity prior to June 1, 2027, to serve New Large Load. 
 
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.

SCHEDULE 11 
 
DATA SUBMITTALS 
 
A. 
To perform the studies required to determine the Forecast Pool Requirement and Daily 
Unforced Capacity Obligations under this Agreement and to determine compliance with the 
obligations imposed by this Agreement, each Party and other owner of a Capacity Resource shall 
submit data to the Office of the Interconnection in conformance with the following minimum 
requirements: 
 
1. 
All data submitted shall satisfy the requirements, as they may change from time to time, of 
any procedures adopted by the Members Committee. 
 
2. 
Data shall be submitted in an electronic format, or as otherwise specified by the Markets 
and Reliability Committee and approved by the PJM Board. 
 
3. 
Actual outage data for each month for Generator Forced Outages, Generator Maintenance 
Outages and Generator Planned Outages shall be submitted so that it is received by such 
date specified in the PJM Manuals. 
 
4. 
On or before the date specified in the PJM Manuals, planned and maintenance outage data 
for all Generation Resources shall be submitted. 
 
 
The Parties acknowledge that additional information required to determine the Forecast Pool 
Requirement is to be obtained by the Office of the Interconnection from Electric Distributors in 
accordance with the provisions of the Operating Agreement. 
 
B. 
1. 
(a) 
Each Party shall submit, or cause to be submitted, to the Office of the 
Interconnection the following information, as may be further described in the PJM 
Manuals, related to each Large Load served by the Party: 
 
 Eligible Customer/Network Customer for Large Load; 
 Description of Large Load; 
 Location(s) (Control Zone, Electric Distributor zone/area, where 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); 
 In-service date for each increment of load; 
 Peak shaving adjustment value pursuant to a state program codified in 
state law and whether and how it meets the requirements of Tariff, 
Attachment DD-2; 
 Delivery point / Point(s) of interconnection (include all if more than 
one); 
 Peak load quantity (MW) and ramp schedule, if applicable;

 Telemetry specifications; 
 BYONC quantity (MW) and ramp schedule, if applicable; 
 Allocated RBP UCAP MW quantity (MW), if applicable; 
 Backup generation (MW), including fuel type and relevant permitting 
limitations; 
 Contracts or service agreements between the Large Load and the LSE; 
 Points of contact at the applicable Transmission Owner, Electric 
Distributor, and Load Serving Entity; 
 EMS B1/B2/B3 name (for the applicable Transmission Owner, Electric 
Distributor); and  
 Additional details and contents as necessary, in accordance with the 
PJM Manuals. 
 
(b) 
The Parties acknowledge that information related to the development and 
maintenance of the Large Load Registry may be obtained by the Office of the 
Interconnection from Electric Distributors in accordance with the provisions of the 
Operating Agreement and the Tariff.   
 
(c) 
The Office of the Interconnection may review information and coordinate 
with the applicable Transmission Owner and Electric Distributor as needed, regarding the 
validity of the information provided, including through requesting additional information 
as the Office of the Interconnection deems necessary, as further set forth in the PJM 
Manuals.  The Office of the Interconnection also may consult with the Large Load. 
 
(d) 
Based on the information provided, or caused to be provided, by each Party, 
as well as other information provided by, for example, Electric Distributors, the Office of 
the Interconnection shall maintain a registry of all Large Loads, and update it periodically.  
To the extent such documents, data, or other information provided to the Office of the 
Interconnection has been designated as confidential by a Party, Electric Distributor, or 
other entity supplying the information, the Office of the Interconnection shall maintain the 
confidentiality of the information provided under this RAA, Schedule 11, section B 
consistent with its obligations under Operating Agreement, section 18.17.  Information 
maintained in the Large Load registry may be available to Authorized Commissions, 
Transmission Owners, Electric Distributors, Load Serving Entities, the Market Monitoring 
Unit, and FERC subject to appropriate data protection safeguards required by Operating 
Agreement, section 18.17. 
 
(e) 
The Office of the Interconnection shall post aggregate data from the Large 
Load Registry on the PJM website, aggregated by Electric Distributor zone/area, where 
possible and in a manner consistent with existing confidentiality protections in the PJM 
Governing Agreements. 
 
2. 
(a) 
Each Party serving or contracted to serve a Large Load that is or will be in 
service prior to June 1, 2027, shall provide the information required by RAA, Schedule 
11.B.1 to the Office of the Interconnection by March 1, 2027.

(b) 
Each Party serving or contracted to serve a New Large Load that will be in 
service on or after June 1, 2027, shall provide the information required by RAA, Schedule 
11.B.1 to the Office of the Interconnection before the in-service date of the Large Load. 
 
(c) 
Each Party contracted to serve a New Large Load shall provide the 
location(s) as required by RAA, Schedule 11.B.1 to the Office of the Interconnection 
before determination of the final PJM Regional Peak Load Forecast for the effective RPM 
Auction for the Delivery Year in which the New Large Load is expected to be in-service 
starting with the 2028 PJM Regional Peak Load Forecast. 
 
Each Party shall promptly inform the Office of the Interconnection of any change in the 
information required by RAA, Schedule 11.B.1 with respect to a Large Load served by the 
Party, including whether the Party no longer serves the Large Load or has acquired the 
contractual right to serve a registered Large Load. 
 
3. 
The information provided pursuant to RAA, Schedule 11, section B will be used, 
to the extent necessary, for purposes including but not limited to implementation of Interim 
Resource Adequacy Service, which is a load reduction service, effective starting with the 
2027/2028 Delivery Year, through which Eligible New Large Loads may be compensated for 
providing load reductions requested by the Office of the Interconnection to maintain system 
reliability for the purpose of supporting the integration of New Large Loads to the PJM Region 
that have not entered into an arrangement with new capacity additions to the PJM Region, as more 
fully set forth in Tariff, Attachment DD-4.