ER27-454-000 · 2026-11-09 · PJM

Attachment A -Marked Tariff

Attachment A 
 
 
Revisions to the Tariff 
(in redline format)

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

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

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

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

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

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

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

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

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

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

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

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

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

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

to receive electric energy and capacity from the Generating Facility at the Point of Interconnection, 
pursuant to the terms of the Interconnection Service Agreement and, if applicable, the Tariff. 
 
Pseudo-Tie: 
 
“Pseudo-Tie” shall have the same meaning provided in the Operating Agreement. 
 
Public Policy Objectives: 
 
“Public Policy Objectives” shall have the same meaning provided in the Operating Agreement. 
 
Public Policy Requirements: 
 
“Public Policy Requirements” shall have the same meaning provided in the Operating 
Agreement. 
 
Qualifying RBP Offset UCAP MW: 
 
“Qualifying RBP Offset UCAP MW” shall mean unforced capacity that: (i) pursuant to Tariff, 
Attachment DD, section 18.2, has not received an RPM commitment or been committed in an 
FRR Plan for the 2028/2029 or earlier Delivery Year as of the commencement of the Reliability 
Backstop Procurement (except for capacity that is first committed in the Third Incremental 
Auction associated with the 2027/2028 Delivery Year), (ii) is supplied by eligible Capacity 
Resources in accordance with Tariff, Attachment DD, section 18.2(b), and (iii) is supported by 
evidence, in accordance with Tariff, Attachment DD, section 18.2(c). 
 
Qualifying Transmission Upgrade: 
 
“Qualifying Transmission Upgrade” shall mean a proposed enhancement or addition to the 
Transmission System that: (a) will increase the Capacity Emergency Transfer Limit into an LDA 
by a megawatt quantity certified by the Office of the Interconnection; (b) the Office of the 
Interconnection has determined will be in service on or before the commencement of the first 
Delivery Year for which such upgrade is the subject of a Sell Offer in the Base Residual 
Auction; (c) is the subject of a Facilities Study Agreement executed before the conduct of the 
Base Residual Auction for such Delivery Year and (d) a New Service Customer is obligated to 
fund through a rate or charge specific to such facility or upgrade. 
 
Queue Position: 
 
“Queue Position” shall mean the priority assigned to an Interconnection Request, a Completed 
Application, or an Upgrade Request pursuant to applicable provisions of Tariff, Part VI.

Definitions – R - S 
 
Ramping Capability: 
 
“Ramping Capability” shall mean the sustained rate of change of generator output, in megawatts 
per minute. 
 
Rating Agency: 
 
“Rating Agency” shall mean a Nationally Recognized Statistical Rating Organization that 
assesses the financial condition, strength and stability of companies and governmental entities 
and their ability to timely make principal and interest payments on their debts and the likelihood 
of default, and assigns a rating that reflects its assessment of the ability of the company or 
governmental entity to make the debt payments. 
 
RBP Charges: 
 
“RBP Charges” shall mean the $/day value of the total RBP Settlement Credits, positive or 
negative, of all committed RBP Resources across the PJM Region. 
 
RBP Collateral: 
 
“RBP Collateral” shall mean: either any one of: (1) a cash deposit, including any interest 
thereon, (2) a surety bond in an amount andwith a provider, amount and form determined by and 
acceptable to PJM or PJMSettlement, or (23) a letter of credit issued for the benefit of PJM or 
PJMSettlement, in anwith a provider, amount and form determined by and acceptable to PJM or 
PJMSettlement. 
 
RBP Obligation: 
 
“RBP Obligation” or “RBO” shall mean the state and/or RERRA-determined allocation of RBP 
UCAP MW to Load Serving Entities within each Electric Distributor’s zone/area. 
 
RBP Resources: 
 
“RBP Resources” shall mean generation resources, Energy Storage Resources, Demand 
Resources, or DER Aggregation Resources, as set forth in Tariff, Attachment DD, section 18.5, 
offered to provide RBP UCAP MW from the Reliability Backstop Procurement, in accordance 
with Tariff, Attachment DD, section 18. 
 
RBP Seller: 
 
“RBP Seller” shall mean an entity that owns or controls an RBP Resource that is offered into the 
Reliability Backstop Procurement.

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

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

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

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

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

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

“Secondary Systems” shall mean control or power circuits that operate below 600 volts, AC or 
DC, including, but not limited to, any hardware, control or protective devices, cables, conductors, 
electric raceways, secondary equipment panels, transducers, batteries, chargers, and voltage and 
current transformers. 
 
Second Incremental Auction: 
 
“Second Incremental Auction” shall mean an Incremental Auction conducted ten months before 
the Delivery Year to which it relates.   
 
Security: 
 
“Security” shall mean the security provided by the New Service Customer pursuant to Tariff, 
section 212.4 or Tariff, Part VI, section 213.4 to secure the New Service Customer’s responsibility 
for Costs under the Interconnection Service Agreement or Upgrade Construction Service 
Agreement and Tariff, Part VI, section 217.  
 
Segment:  
“Segment” shall have the same meaning as described in Operating Agreement, Schedule 1, 
section 3.2.3(e), and the parallel provisions of Tariff, Attachment K-Appendix, section 3.2.3(e). 
 
Self-Supply: 
 
“Self-Supply” shall mean Capacity Resources secured by a Load-Serving Entity, by ownership 
or contract, outside a Reliability Pricing Model Auction, and used to meet obligations under this 
Attachment or the Reliability Assurance Agreement through submission in a Base Residual 
Auction or an Incremental Auction of a Sell Offer indicating such Market Seller’s intent that 
such Capacity Resource be Self-Supply.  Self-Supply may be either committed regardless of 
clearing price or submitted as a Sell Offer with a price bid. A Load Serving Entity's Sell Offer 
with a price bid for an owned or contracted Capacity Resource shall not be deemed “Self-
Supply,” unless it is designated as Self-Supply and used by the LSE to meet obligations under 
this Attachment or the Reliability Assurance Agreement. 
 
Self-Supply Entity: 
 
“Self-Supply Entity” shall mean the following types of Load Serving Entity that operate under 
long-standing business models: single customer entity, public power entity, or vertically 
integrated utility, where “vertically integrated utility” means a utility that owns generation, 
includes such generation in its regulated rates, and earns a regulated return on its investment in 
such generation or receives any cost recovery for such generation through bilateral contracts; 
“single customer entity”  means a Load Serving Entity that serves at retail only customers that 
are under common control with such Load Serving Entity, where such control means holding 
51% or more of the voting securities or voting interests of the Load Serving Entity and all its 
retail customers; and “public power entity” means cooperative and municipal utilities, including 
public power supply entities comprised of either or both of the same and rural electric 
cooperatives, and joint action agencies.

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

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

Agreement, Schedule 1, section 2, and the parallel provisions of Tariff, Attachment K-Appendix, 
section 2. 
 
Start Additional Labor Costs: 
 
“Start Additional Labor Costs” shall mean additional labor costs for startup required above 
normal station manning levels.  
 
Start Fuel: 
 
For units without a soak process, “Start Fuel” shall consist of fuel consumed from first fire of the 
start process to first breaker closing, plus any fuel expended from last breaker opening to 
shutdown. 
 
For units with a soak process, “Start Fuel” is fuel consumed from first fire of the start process 
(initial reactor criticality for nuclear units) to dispatchable output (including auxiliary boiler 
fuel), plus any fuel expended from last breaker opening to shutdown, excluding normal plant 
heating/auxiliary equipment fuel requirements.  Start Fuel included for each temperature state 
from breaker closure to dispatchable output shall not exceed the unit specific soak time period 
reviewed and approved as part of the unit-specific parameter process detailed in Tariff, 
Attachment K-Appendix, section 6.6(c) or the defaults below: 
 Cold Soak Time = 0.73 * unit specific Minimum Run Time (in hours) 
 Intermediate Soak Time = 0.61 * unit specific Minimum Run Time (in hours) 
 Hot Soak Time = 0.43 * unit specific Minimum Run Time (in hours)   
 
Start-Up Costs: 
 
“Start-Up Costs” shall consist primarily of the cost of fuel, as determined by the unit’s start heat 
input (adjusted by the performance factor) times the fuel cost.  It also includes operating costs, 
Maintenance Adders, emissions allowances/adders, and station service cost.  Start-Up Costs can 
vary with the unit offline time being categorized in three unit temperature conditions: hot, 
intermediate and cold. 
 
For units with a steam turbine and a soak process (nuclear, steam, and combined cycle), “Start 
Fuel” is fuel consumed from first fire of start process (initial reactor criticality for nuclear units): 
Start-Up Costs shall mean the net unit costs from PJM’s notification to the level at which the unit 
can follow PJM’s dispatch, and from last breaker open to shutdown. 
 
For units without a steam turbine and no soak process (engines, combustion turbines, Intermittent 
Resources, and Energy Storage Resources): Start-Up Costs shall mean the unit costs from PJM’s 
notification to first breaker close and from last breaker open to shutdown.   
 
State: 
 
“State” shall mean the District of Columbia and any State or Commonwealth of the United States.

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

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

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

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

“System Impact Study” shall mean an assessment by the Transmission Provider of (i) the adequacy 
of the Transmission System to accommodate a Completed Application, an Interconnection 
Request or an Upgrade Request, (ii) whether any additional costs may be incurred in order to 
provide such transmission service or to accommodate an Interconnection Request, and (iii) with 
respect to an Interconnection Request, an estimated date that an Interconnection Customer’s 
Customer Facility can be interconnected with the Transmission System and an estimate of the 
Interconnection Customer’s cost responsibility for the interconnection; and (iv) with respect to an 
Upgrade Request, the estimated cost of the requested system upgrades or expansion, or of the cost 
of the system upgrades or expansion, necessary to provide the requested incremental rights. 
 
System Protection Facilities: 
 
“System Protection Facilities” shall refer to the equipment required to protect (i) the Transmission 
System, other delivery systems and/or other generating systems connected to the Transmission 
System from faults or other electrical disturbance occurring at or on the Customer Facility, and (ii) 
the Customer Facility from faults or other electrical system disturbance occurring on the 
Transmission System or on other delivery systems and/or other generating systems to which the 
Transmission System is directly or indirectly connected.  System Protection Facilities shall include 
such protective and regulating devices as are identified in the Applicable Technical Requirements 
and Standards or that are required by Applicable Laws and Regulations or other Applicable 
Standards, or as are otherwise necessary to protect personnel and equipment and to minimize 
deleterious effects to the Transmission System arising from the Customer Facility.

5.5 
Eligibility for Participation in RPM Auctions 
 
(a) 
A Capacity Market Seller may submit a Sell Offer for a Capacity Resource in a Base 
Residual Auction or Incremental Auction only if such seller owns or has the contractual authority 
to control the output or load reduction capability of such resource and has not transferred such 
authority to another entity prior to submitting such Sell Offer. Capacity Resources must satisfy 
the capability and deliverability requirements of RAA, Schedule 9 and RAA, Schedule 10, the 
requirements for Demand Resources or Energy Efficiency Resources in Tariff, Attachment DD-
1 and RAA, Schedule 6, as applicable, and, the criteria in Tariff, Attachment DD, section 5.5A. 
A Planned Generation Capacity Resource may be included in a Sell Offer for an RPM Auction 
only if the Capacity Market Seller of such resource provides a binding notice of intent, as further 
detailed in the PJM Manuals, to submit a Sell Offer in such auction to the Office of the 
Interconnection no later than (a) the immediately preceding December 1 for a Base Residual 
Auction, or (b) ninety (90) days prior to the commencement of the offer period for an Incremental 
Auction.   
 
(b) 
Notwithstanding the foregoing, a committed RBP Resource shall be required to be offered 
into the relevant Reliability Pricing ModelBase Residual Auction and is not required to submit a 
binding notice of intent to offer into such auction.  However, a Planned Generation 
Capacitycommitted RBP Resource that is committed in the RBP for the 2030/2031 Delivery Year 
must still benot the subject of a notice of intent to be offered into the Base Residual Auction 
associated with the 20292030/2030 2031 Delivery Year shall be offered into the Second 
Incremental Auction for the 2029/2030 Delivery Year. In the event a committed RBP Resource is 
not expected to be in-service or deliverable by the relevant Delivery Year, the Capacity Market 
Seller of such committed RBP Resource may notify the Office of the Interconnection, with 
supporting documentation, that the resource is not expected to be in-service or deliverable by the 
relevant Delivery Year. Such notice for a committed RBP Resource shall be submitted no later 
than (i) the immediately preceding December 1 for a Base Residual Auction or (ii) ninety (90) 
days prior to the commencement of the offer period for an Incremental Auction. A committed RBP 
Resource that provides such notice will be assessed any applicable RBP shortfall charge and not 
be allowed to be offered into the applicable RPM Auction.

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

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

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

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

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

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

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

Generation Capacity Resources; and (iii) shall not be permitted to satisfy any LSE’s Unforced 
Capacity Obligation, or any entity’s obligation to obtain the commitment of Capacity Resources, 
for such Delivery Year. 
 
 
Any such Existing Generation Capacity Resources may also be subject to further action 
by the Market Monitoring Unit under the terms of Tariff, Attachment M and Tariff, Attachment 
M – Appendix. 
 
 
(i) 
In addition to the remedies set forth in subsections (g) and (h) above, if the 
Market Monitoring Unit determines that one or more Capacity Market Sellers’ failure to offer 
part or all of one or more existing generation resources, for which the Office of the 
Interconnection has not approved an exception to the RPM must-offer requirement, into an RPM 
Auction as required by this Section 6.6 would result in an increase of greater than five percent in 
any Zonal Capacity Price determined through such auction, and the Office of the Interconnection 
agrees with that determination, the Office of the Interconnection shall apply to FERC for an 
order, on an expedited basis, directing such Capacity Market Seller to participate in the relevant 
RPM Auction, or for other appropriate relief, and PJM will postpone clearing the auction 
pending FERC’s decision on the matter.  If the Office of the Interconnection disagrees with the 
Market Monitoring Unit’s determination and does not apply to FERC for an order directing the 
Capacity Market Seller to participate in the auction or for other appropriate relief, the Market 
Monitoring Unit may exercise its powers to inform Commission staff of its concerns and to seek 
appropriate relief. 
 
 
(j) 
An RBP Resource committed through the Reliability Backstop Procurement must 
offer all available committed RBP UCAP MW as a price-taker (i.e., $0/MW-day) into the 
applicable RPM Auctions pursuant to the capacity must offer requirements and exceptions set 
forth in Tariff, Attachment DD, sections 6.6 and 6.6A.  The applicable RPM Auctions shall be 
the Reliability Pricing Model Auctions beginning with the first Delivery Year in which an RBP 
Resource has been committed through the Reliability Backstop Procurement and is expected to 
be in-service.  Such offer requirement shall continue for each subsequent Delivery Year through 
the end of the fixed 15-year term, except RBP UCAP MW for RBP Resources without a notice 
of intent to offer submitted pursuant to Tariff, Attachment DD, section 5.5 for the 2030/2031 
Base Residual Auction, which shall have a must offer requirement beginning in the next 
applicable RPM Auction, including but not limited to the 2031/2032 Base Residual Auction and 
the 2029/2030 Second Incremental Auction to the extent such resource has RBP UCAP MW 
committed and is expected to be in-service for those Delivery Years.

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

review by no later than (i) one hundred twenty (120) days prior to the commencement of the 
offer period for subsequent Incremental Auctions for the applicable Delivery Years, and (ii) the 
December 1 that last precedes subsequent Base Residual Auctions.  The Capacity Market Seller 
shall also immediately notify the Office of the Interconnection and the Market Monitoring Unit 
of any material changes to the plan that may occur.  Upon request by a Capacity Market Seller, a 
one year extension to the plan timeline shall be permissible only for delays not caused by the 
Capacity Market Seller, and that could not have been remedied through the exercise of due 
diligence by the Capacity Market Seller. In no event may an exception be requested by the 
Capacity Market Seller for more than two Base Residual Auctions. 
 
Failure to submit a documented plan, or lack of good faith effort by a Capacity Market 
Seller to make an Existing Generation Capacity Resource physically capable of meeting the 
requirements of a Capacity Performance Resource in accordance with a documented plan, shall 
result in the removal of the resource’s Capacity Resource status effective with the first future 
Delivery Year for which the resource was granted an exception, no earlier than the 2023/2024 
Delivery Year.   The Office of the Interconnection shall amend the applicable Interconnection 
Service Agreement or wholesale market participation agreement to reflect any such removal of 
the Capacity Interconnection Rights, and shall report the amended agreement to the Commission 
in the same manner as the original (e.g. FERC Filing or Electronic Quarterly Reports).  The 
Office of the Interconnection shall file the amended agreement unexecuted if the Interconnection 
Customer or wholesale market participant does not sign the amended Interconnection Service 
Agreement or wholesale market participation agreement. The required change in Capacity 
Resource status shall only apply to those Generation Capacity Resources that are shown to be 
physically incapable of satisfying the requirements of a Capacity Performance Resource. 
 
 
(d) 
A resource not exempted or excepted under subsection (c) hereof that is capable 
of qualifying as a Capacity Performance Resource and does not offer into an RPM Auction as a 
Capacity Performance Resource shall be subject to the same restrictions on subsequent offers, 
and other possible remedies, as specified in section 6.6. 
 
 
(e) 
An RBP Resource committed through the Reliability Backstop Procurement must 
offer all committed RBP UCAP MW as price-takers (i.e., $0/MW-day) into the applicable RPM 
Auctions pursuant to the capacity must offer requirements and exceptions set forth in Tariff, 
Attachment DD, sections 6.6 and 6.6A.  The applicable RPM Auctions shall be the Base 
ResidualReliability Pricing Model Auctions beginning with the first Delivery Year in which 
conducted after an RBP Resource’s RBP UCAP MW  havse been committed through the 
Reliability Backstop Procurement and is expected to be in-service.  Such offer requirement 
shalland continuinge for each subsequent Delivery Year through the end of the fixed 15-year 
term, except RBP UCAP MW for Capacity Performance Resources without a notice of intent to 
offer submitted pursuant to Tariff, Attachment DD, section 5.5 for the 202930/20301 Base 
Residual Auction, which shall have a must offer requirement beginning in the next applicable 
RPM Auction, including but not limited to the 20301/20312 Base Residual Auction and the 
2029/2030 Second Incremental Auction to the extent such resource has an RBP UCAP MW 
commitment and is expected to be in-service for those Delivery Years.

18.  
RELIABILITY BACKSTOP PROCUREMENT 
 
The Reliability Backstop Procurement or “RBP” is a one-time procurement, starting in 20276, to 
address resource adequacy challenges in the PJM Region arising from insufficient capacity 
committed through Reliability Pricing Model Auctions starting in the 2027/2028 Delivery Year.

18.1 
Determination of Final RBP Target
The Reliability Backstop Procurement is designed to procure sufficient RBP UCAP MW to meet 
the Final RBP Target.  
(a)
Initial RBP Target 
The Initial RBP Target shall be a region-wide value equal to the lesser of the (1) most up 
to date UCAP MW quantity that PJM clears cleared short of the PJM Region Reliability 
Requirement for the 2028/2029 Delivery Year Base Residual Auction or (2) the UCAP equivalent 
of the aggregate region-wide Large Load MW quantity reported by the Electric Distributor in 
accordance with Tariff, Attachment DD, section 18.3A. Specifically, the Initial RBP Target shall 
equal the lesser of ([the latest estimate of the PJM Region Reliability Requirement for the 
2028/2029 Delivery Year, calculated as the RTO Region Peak Load Forecast for the 2028/2029 
Delivery Year from the 2027 Load Forecast times the 2028/2029 Forecast Pool Requirement from 
the updated planning parameters available at the commencement of the RBP, less the sum of all 
updated Unforced Capacity Obligations of FRR Entities in the PJM Regionbased on the latest load 
forecast for the 2028/2029 Delivery Year available at the commencement of the RBP and the most
recent 2028/2029 Forecast Pool Requirement] minus [the UCAP-equivalent of the ICAP quantity 
of Capacity Resources that cleared in the 2028/2029 Base Residual Auction using the latest 
capacity accreditation factors for the 2028/2029 Delivery Year available at the commencement of 
the RBP], the aggregate region-wide Large Load MW reported by the Electric Distributor in 
accordance with Tariff, Attachment DD, section 18.3A times the most recent 2028/2029 Forecast 
Pool Requirement). 
(b)
Final RBP Target 
The Final RBP Target shall be a PJM region-wide value equal to the Initial RBP Target minus the 
total PJM region-wide Qualifying RBP Offset UCAP MW and the unforced capacity obligation 
value of load that have successfully requested and obtained an opt-out pursuant to Tariff, 
Attachment DD, section 18.1(d).   
(c)
Fixed Resource Requirement Entities
Fixed Resource Requirement (“FRR”) Entities as of the 2028/2029 Delivery Year shall be 
excluded from the Reliability Backstop Procurement, including Initial and Final RBP Targets.  
To the extent an Electric Distributor zone/area that has RBP UCAP MW committed through the 
Reliability Backstop Procurement later becomes an FRR Service Area pursuant to RAA, Schedule 
8.1.D, the Electric Distributor zone/area shall continue to be accountable for the RBP UCAP MW 
quantity committed through the Reliability Backstop Procurement.  
(d)
Opt-Out 
When calculating the Final RBP Target, the Initial RBP Target shall also be decremented where 
the Electric Distributor’s zone/area has rates that are not regulated by the states and is unable to 
address cost allocation associated with capacity procured in the backstop. Such request by the 
Electric Distributor shall specify the associated MW quantity of load in the zone/area that will be 
opted-out of the Initial RBP Target and be accompanied by supporting documentation 
demonstrating an inability to address cost allocation associated with capacity procured in the 
backstop, along with written support for such opt-out from the relevant state governor, RERRA,

and interconnection customer(s). The Initial RBP Target shall be further decremented, if requested 
by an Electric Distributor, and accompanied by an officer attestation in accordance with the PJM 
Manuals, by up to the associated MW quantity of load that participates in a peak shaving 
adjustment program for a minimum period of five years where such Electric Distributor’s 
zone/area addresses their capacity needs through peak shaving adjustment programs that are 
codified in state law and that also meet the requirements of Tariff, Attachment DD-2.

18.2 
Qualifying RBP Offset UCAP MW   
 
(a) 
Qualifying RBP Offset UCAP MW is capacity that will be located within the PJM 
Region (i) has not previously supported a capacity commitment or been committed in an FRR Plan 
for the 2028/2029 or earlier Delivery Year as of the commencement of the Reliability Backstop 
Procurement (except for capacity that is first committed in the Third Incremental Auction 
associated with the 2027/2028 Delivery Year); and (ii) is supplied by a resource that satisfies each 
of the criteria set forth in Tariff, Attachment DD, section 18.2(b).   
 
(b) 
Resources Eligible to Supply Qualifying RBP Offset UCAP MW 
 
A resource eligible to supply Qualifying RBP Offset UCAP MW must have an expected 
commercial operation date, or is reasonably expected to be an Annual Demand Resource or DER 
Capacity Aggregation Resource that will be registered with the Office of the Interconnection and 
under a contract to perform based on PJM dispatch instructions, by no later than June 1, 2032 and 
be: (i) a new build generation resource including new resources that obtain Capacity 
Interconnection Rights transferred from deactivated resources or resources that have announced 
deactivation as of April 10, 2026; (ii) the incremental capacity created by an uprate of existing 
Generation Capacity Resources, but only to the extent such incremental capacity is created through 
an increase in such Generation Capacity Resource’s installed capacity and increase in Capacity 
Interconnection Rights associated with that Generation Capacity Resource; (iii) the incremental 
capacity created by the utilization of Surplus Interconnection Service; (iv) repowering of a 
deactivated generation resource that deactivated prior to April 10, 2026; (v) incremental capacity, 
whether due to greater Unforced Capacity or a higher level of Capacity Interconnection Rights, 
created by an existing Generation Capacity Resource’s changing fuel type to a more efficient fuel 
type; or (vi) Planned Demand Resource or Planned DER Capacity Aggregation Resources, as 
described in the RAA, Schedule 6 and Schedule 6.2 , and must meet the requirements of being 
eligible to be an RBP Resource as set forth in Tariff, Attachment DD, section 18.5(c) and 18.5(d), 
except that the associated participation contract(s) are not required to be eligible for the offset. 
. 
 
(c) 
Evidence of Qualifying RBP Offset UCAP MW  
 
During the RBP bid submission window defined in Tariff, Attachment DD, section 18.4, Electric 
Distributors shall report the Qualifying RBP Offset UCAP MW that is the subject of a bilateral 
agreement with a Large Load, up to the capacity obligation of the Large Load, reported to the 
Office of the Interconnection in accordance with Tariff, Attachment DD, section 18.3(a)(2) in their 
respective zones/areas.  to the Office of the Interconnection in accordance with their requirements 
set forth in the Operating Agreement, section 11.3, and sSuch report shall be accompanied by 
evidence of at least one of the following supporting materials.  Likewise, to the extent LSEs, 
interconnecting customers, large loads, Transmission Owners, or other entities report Qualifying 
RBP Offset UCAP MW to the Office of the Interconnection during such RBP bid submission 
window, the reported Qualifying RBP Offset UCAP MW must be accompanied with evidence of 
at least one of the following supporting materials:

(i) 
Signed bilateral contracts for Qualifying RBP Offset UCAP MW for at least 
five Delivery Years with a commercial operation date prior to the start of the 2032/2033 
Delivery Year, and matched with Large Lload that has an executed electric service 
agreement or transmission service agreement, indicating that the load will be coming online 
in the 2027/2028 or 2028/2029 Delivery Year; 
 
(ii) 
Self-Supply generation that is in a Relevant Electric Retail Regulatory 
Authority (“RERRA”)-approved or accepted integrated resource plan with either 
associated generation in the PJM interconnection queue or signed bilateral contracts for 
Qualifying RBP Offset UCAP MW for at least five Delivery Years with a commercial 
operation date prior to the start of the 2032/2033 Delivery Year, and matched with load that 
has an executed electric service agreement or transmission service agreement, indicating 
that the Large load Load will be coming online in the 2027/2028 or 2028/2029 Delivery 
Year; or 
 
(iii) 
Signed commitment between a Curtailment Service Provider or DER 
Aggregator and new load(s) that has an executed electric service agreement or transmission 
service agreement, indicating that the new Large Lload(s) will, in a MW quantity equal to 
MW quantity of the new load(s), either (a) participate as Annual Demand Resources or 
DER Capacity Aggregation Resources starting in the 2028/2029 Delivery Year Second 
Incremental Auction and continuing through the 2032/2033 Delivery Year, or (b) purchase 
replacement Qualifying RBP Offset UCAP MW that are eligible generation or storage 
resources.  
 
(d) 
To determine the quantity of any Qualifying RBP Offset UCAP MW that are 
verified by the Office of the Interconnection and used to decrement the Initial RBP Target, the 
Office of the Interconnection shall use the applicable most up-to-date ELCC Class Ratings from 
the Base Residual Auction associated with the 2028/2029 Delivery Year, or the estimated unit-
specific UCAP value for resources with no ELCC Class Rating available at the commencement of 
the RBP. 
 
(e) 
The total quantity of Qualifying RBP Offset UCAP MW verified by the Office of 
the Interconnection and used to decrement the Initial RBP Target total amount allowed for each 
zone/area will be capped by the aggregate MW quantity of Large Load reported by at the Load 
Adjustment for each Electric Distributor, as reported in accordance with Tariff, Attachment DD, 
section 18.3(a)(2), and the total MW quantity that is subject to the RBP opt-out, as requested in 
accordance with Tariff, Attachment DD, section 18.1(d), for the relevant zone/area amount of 
summer 2028 demand as set forth in the load forecast.

18.3
Cost Allocation of RBP Charges, Credits, and Shortfall Charges
(a)
Cost Allocation of RBP Charges to Electric Distributor zone/area
(i)  The Office of the Interconnection shall allocate the Initial RBP Target MW to each Electric 
Distributor’s zone/area using that zone/area’s pro-rata share of the total incremental Large Load 
reported to the Office of the Interconnection in accordance with Tariff, Attachment DD, section 
18.3A.  Such allocation shall be only to Electric Distributors’ zone/area not located in an FRR 
Service Area and based on information provided by each such Electric Distributordifference 
between the forecasted Load Adjustments for the 2026/2027 Delivery Yearand the 2028/2029 
Delivery Year.    
(ii)  The allocation based on the zone/area’s MW share of the total incremental Large Load 
MWdifference between the forecasted Load Adjustments for the 2026/2027 and the 2028/2029 
Delivery Years shall be reduced for the purpose of this calculation to the extent: 
(i1)
an Electric Distributor, LSE, Transmission Owner, or other entity provides 
the Office of Interconnection with evidence of Qualifying RBP Offset UCAP MW, in 
accordance with Tariff, Attachment DD, section 18.2 and as may be further set forth in the 
PJM Manuals; or 
(ii2)
an Electric Distributor zonee/area meets one of the opt-out provisions set 
forth in accordance with Tariff, Attachment DD, section 18.1(d).
The resulting reduced MW, floored at zero, is shall be used to calculate the zone/area’s assigned
pro-rata share of the Final RBP Target MW.  The zone/area’s assigned share of the Final RBP 
Target MW shall remain constant throughout the fixed, 15-year term.
(iii)  The Office of the Interconnection shall allocate the total RBP Charges, assessed daily, to an 
Electric Distributor’s zone/area on a pro-rata basis using the zone/area’s assigned share of the total 
Final RBP Target MW across all zone/areas. 
(b)
Cost Allocation of RBP Charges to Load Serving Entities
LSEs located in an Electric Distributor zone/area with a positive, non-zero allocation of 
RBP Charges pursuant to Tariff, Attachment DD, section 18.3(a)(iii) shall be eligible to be 
allocated responsibility for RBP Charges as follows:
(i)
The daily assessed RBP Charges allocated to each Electric Distributor 
zone/area shall be further allocated to each applicable LSE within that zone/area with an 
RBP Obligation (“RBO”) based on the LSE’s pro-rata share of the total RBP Obligation 
MW for the zone/area.

(ii)
The RBP Charge assessed daily to an LSE in a zone/area shall be the LSE’s 
daily reported RBO MW in the zone/area divided by the total RBO MW in the zone/area 
multiplied by total, daily RBP Charges allocated to the zone/area.  
(iii)
The RBO MW shall be, where available, the state and/or RERRA-
determined allocation of cleared RBP UCAP MW to LSEs within each Electric 
Distributor’s zone/area, as reported by each Electric Distributor to the Office of the 
Interconnection, with the initial allocation reported no later than one hundred and twenty
sixty (60120) days prior to the 2028/2029 Delivery Year.  Electric Distributors may report 
updated RBO MW to the Office of the Interconnection after the initial allocation is reported 
to reflect any changes in Load Serving Entities that should be assigned RBP Charges. If 
no RBO MW are reported to the Office of the Interconnection in for an Electric Distributor 
zone/area, PJM will allocate the RBP Charges for that zone/area to all load in the zone/area 
using each LSE’s ratio share of the Daily Unforced Capacity Obligation for the zone/area 
as determined in RAA, Schedule 8. PJMSettlement shall be the Counterparty to each LSE’s 
obligation to pay, and payments of, RBP Charges. 
(iv)
RBP Shortfall Charges will be allocated to LSEs as credits based on using 
the same pro-rata share of the RBP Charges, pursuant to RAA, Article 7, Ssection 7.2B.

18.3A Electric Distributor Reporting Requirement for Reliability Backstop Procurement 
 
No later than seven days prior to the commencement of the Reliability Backstop Procurement, each 
Electric Distributor outside of an FRR Service Area shall report to the Office of the Interconnection 
the quantity and identity of incremental Large Load that is supported by an electric service 
obligation, construction commitment, or similar agreement.  Such Electric Distributor shall also 
report the amount (in MW) that represents the difference between the aggregate quantity of Large 
Load based on the 2026 actual summer peak and the expected summer peak of Large Load for the 
2028/2029 Delivery Year.  An Electric Distributor shall provide an explanation for any deviation 
between the expected quantity of Large Loads for the 2028/2029 Delivery Year and the values 
provided by the Electric Distributor to the Office of the Interconnection as part of the development 
for the load forecast.

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

18.5  The Reliability Backstop Procurement Process 
 
(a) 
RBP Seller Eligibility to Participate and General Requirements for Resources 
Supporting RBP UCAP MW 
 
To be eligible to participate in the Reliability Backstop Procurement, an RBP Seller must meet the 
RBP credit requirements, set forth in Tariff, Attachment DD, section 18.8, with RBP Sell Offer(s) 
for RBP UCAP MW based on a resource that:  
 
(i) 
Has a commercial operation date, or is reasonably expected to be an Annual 
Demand Resource or DER Capacity Aggregation Resource that will be registered with the 
Office of the Interconnection and under a contract to perform based on PJM dispatch 
instructions, by no later than June 1, 2032, inclusive of any required Network Upgrades;  
 
(ii) 
Has not received a capacity commitment or been committed in an FRR Plan 
for the 2028/2029 or earlier Delivery Year as of the commencement of the Reliability 
Backstop Procurement (except for capacity that is first committed in the Third Incremental 
Auction associated with the 2027/2028 Delivery Year); 
 
(iii) 
Is not supplying Qualifying RBP Offset UCAP MW; 
 
(iv) 
To the extent the subject of a notice of intent for the 2028/2029 Base 
Residual Auction, must have offered and not cleared in the 2028/2029 Base Residual 
Auction;  
 
(v) 
To the extent the subject of a notice of intent for the 2029/2030 Base 
Residual Auction, must be offered into the 2029/2030 Base Residual Auction; and 
 
(vi) 
Meets the requirements in Tariff, Attachment DD, sections 18.5(b), 18.5(c), 
or 18.5(d). 
 
(b) 
Generation or Energy Storage Resources as an RBP Resource 
 
To qualify as an RBP Resource, a generation or Energy Storage Resource that supplies RBP UCAP 
MW eligible to be offered into the Reliability Backstop Procurement shall be in the PJM Region 
or meet the requirements to pseudo-tie into the PJM Region in Tariff, Attachment DD, section 
5.5A(b), must meet the requirements of Tariff, Attachment DD, section 18.5(a) and must be: 
 
(i) 
Composed of new Installed Capacity and new Maximum Facility Output; 
 
(ii) 
Supported by new Capacity Interconnection Rights (if located in the PJM 
Region) or Capacity Interconnection Rights transferred from a deactivated resource or a 
resource that announced deactivation as of April 10, 2026; and 
 
(iii) 
Consist of (1) new build; (2) incremental capacity created by an uprate of 
an existing Generation Capacity Resource’s or Energy Storage Resource’s installed

capacity and associated level of Capacity Interconnection Rights; or (3) repowering of a 
generation resource that had deactivated, or announced deactivation, on or before April 10, 
2026. 
 
(c) 
RBP Demand Resources 
 
To qualify as a Demand Resource that supplies RBP UCAP MW eligible to be offered into the 
Reliability Backstop Procurement, a Demand Resource must meet the requirements of Tariff, 
Attachment DD, sections 18.5(a), and:  
 
(i) 
Not be reliant on or composed of registered location(s) that previously 
supported a Demand Resource that provided capacity in a priorthe 2026/2027 Delivery 
Year unless such location represents an incremental increase in capacity resulting from an 
investment in new generation or new storage resources at that location; and    
 
(ii) 
Identify, as part of its RBP Sell Offer, for the full length of the fixed term, 
the location(s) and associated participation contract(s). 
 
(d)  
RBP DER Aggregation Resources 
 
To qualify as a DER Capacity Aggregation Resource that supplies RBP UCAP MW eligible to be 
offered into the Reliability Backstop Procurement, a Planned DER Capacity Aggregation Resource 
must meet the requirements of Tariff, Attachment DD, sections 18.5(ba) and:  
 
(i) 
Identify, as part of its RBP Sell Offer, for the length of the fixed term, the 
location(s) and associated participation contract(s).  
 
(e) 
RBP Sell Offers 
 
RBP Sell Offers for RBP UCAP MW shall specify an offer quantity in UCAP MW and an offer 
price in $/MW-day UCAP for each Delivery Year beginning with the first full Delivery Year in 
which the RBP UCAP MW is expected to provide capacity through the end of the fixed 15-year 
term.   
 
RBP Sellers will be responsible for all actual Network Upgrade costs as determined through the 
interconnection process, without subsequent adjustments to RBP Sell Offers.   
 
Each RBP Sell Offer shall include the following information for the RBP UCAP MW offered: 
 
(i) 
the MW of UCAP to be provided by such resource for each Delivery Year, 
where the maximum UCAP included in an RBP Sell Offer shall be limited to no greater 
than 120% of the resource type’s most recent maximum Preliminary ELCC Class Ratings 
for 2028/2029 through the last posted Delivery Year or based on the resource’s maximum 
estimated unit-specific ELCC ratings across such period for resources with no ELCC Class 
Rating, multiplied by the resource’s ICAP;

(ii) 
the price in $/MW-day UCAP for each Delivery Year beginning with the 
first full Delivery Year in which the RBP UCAP MW is expected to provide capacity 
through the end of the fixed 15-year term;         
 
(iii) 
the first full Delivery Year for which such resource shall be available and 
offering to provide capacity;  
 
(iv) 
all relevant documentation necessary for the Office of the Interconnection 
to evaluate whether the project satisfies the gating criteria, as set forth in Tariff, Attachment 
DD, section 18.5(f)(i). 
 
(f) 
Clearing Structure 
 
Following the closing date of bid solicitation for the Reliability Backstop Procurement in October 
2026, the Office of the Interconnection shall complete the Reliability Backstop Procurement in 
two stages: (1) gating criteria evaluation and (2) selection assessment, with notification of finalized 
commitments posted prior to the Base Residual Auction for the 20292030/2030 2031 Delivery 
Year. The Reliability Backstop Procurement shall be pay-as-bid.  
 
(i) 
Stage 1: Gating Criteria Evaluation 
 
A valid RBP Sell Offer shall include the information and evidence required by this section.  
The Office of the Interconnection shall evaluate all RBP Sell Offers for compliance with 
this requirement.  Such evaluation shall be conducted by the Office of the Interconnection 
on a pass/fail basis.   
 
RBP Sell Offers that do not include the following information shall not proceed to selection 
assessment, provided, however, that the Office of the Interconnection shall provide the 
RBP Seller the opportunity to cure any identified deficiencies within five (5) calendar days 
of being notified by PJM. Notwithstanding, such opportunity to cure shall not extend past 
the close of the bid submission window of the Reliability Backstop Procurement. 
 
RBP Sell Offers for RBP Generation and/or Storage Capacity Resources must be 
accompanied by:   
 
(1) 
A critical path construction schedule and expected commercial 
operation date, with attestation, for the Office of the Interconnection to validate that 
RBP Sell Offers are for RBP UCAP MW with a feasible commercial operation date 
of June 1, 2032 or earlier;   
 
(A) 
With respect to a project in Transition Cycle #2 under Tariff, 
Part VII and earlier, such project must provide study information and 
timeline from its most current PJM study;  
 
(B) 
With respect to a project in Cycle 1 under Tariff Part VIII, 
the Expedited Interconnection Track under Tariff, Part X, or not under study,

the project must provide study information and timeline from (1) an 
independent consultant report or (2) the most current PJM study; 
 
(2) 
For projects that are not the subject of a completed interconnection 
study or are not currently under study as part of an active New Service Request by 
the Office of the Interconnection, eEvidence of 100% Site Control consistent with 
Tariff, Part VIII, Subpart A, section 402 for each of the Generating Facility 
(including the location of the main step-up transformer), the Interconnection 
Facilities, and the Interconnection Switchyard (as defined in the PJM Manuals) for 
a term of at least three years from the date of submission of the RBP Sell 
OfferApplication. 
 
Such projects must also be accompanied byIn addition, a certification, 
executed by an officer or authorized representative of the Generation Project 
Developer, verifying that the Site Control requirements have been met. Further, at 
Transmission Provider’s request, Generation Project Developer shall provide 
copies of landowner attestations or county recordings. The Site Control 
requirements include an acreage requirement for the Project, as set forth in the PJM 
Manuals. 
 
 
Evidence of site control shall be consistent with Tariff, Part VIII, Subpart A, section 
402;  
 
(3) 
Financing plan, i.e., identified financing sources and details (e.g., 
project financing, balance sheets, tax equity, sponsor equity), current status of any 
financing commitments or term sheets, and a general description of the capital 
structure and expected timeline to financial close; 
 
(4) 
Permitting plan, e.g., a list of all applicable permits, current status, 
and timeline to obtain each; 
 
(5) 
Signed memorandum for the acquisition of major equipment, 
invoices or agreements to acquire major equipment, or other documentary evidence 
that major equipment has been procured; 
 
(6) 
Evidence of experience having constructed a previous project of 
similar size and technology or have contracted with an engineering, procurement, 
and construction partner with such experience, or contract with an engineering, 
procurement, and construction partner with such experience; 
 
(7) 
For natural gas-fueled generation resources, evidence of delivery 
infrastructure arrangements in the form of a notice of intent or attestation of pipeline 
capacity expansion to support the new project; and 
 
(8) 
For generation and/or energy storage resources located outside of 
the PJM Region, evidence of (a) a completed facilities study or equivalent under

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

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

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

18.6 
RBP Resource Obligations  
(a) 
Capacity Must Offer Obligation  
 
An RBP Resource committed through the Reliability Backstop Procurement must offer all 
committed RBP UCAP MW into the RPM Auctions as Capacity Resources pursuant to the capacity 
must offer requirements and exceptions set forth in Tariff, Attachment DD, sections 6.6 and 6.6A. 
The applicable RPM Aauctions shall be the Base Residual Auctions and Incremental Auctions 
conducted after an RBP Resource’s RBP UCAP MW have been committed through the Reliability 
Backstop Procurement beginning with the first Delivery Year in which such resource is expected 
to be in servicehas an RBP commitment and is expected to be in service. and Such offer 
requirement shall continuinge for each subsequent Delivery Year through the end of the fixed 15-
yearRBP term, except RBP UCAP MW for RBP Resources that is expected to be in service for the 
2030/2031 Delivery Year without a notice of intent to offer submitted pursuant to Tariff, 
Attachment DD, section 5.5 for the 203029/20310 Base Residual Auction shall have a must offer 
requirement in the next RPM Auction, including but not limited to the 20310/20321 Base Residual 
Auction and the 203029/20310 Second First Incremental Auction.  The RBP Resource’s capacity 
must offer obligation into RPM Auctions for a Delivery Year is satisfied once the entirety of the 
committed RBP UCAP MW have cleared in RPM Auction(s) for such Delivery Year.    
 
RBP Resources with RBP UCAP MW committed through RPM Auctions will be subject to all 
RPM capacity market rules, as set forth in Tariff, Attachments DD and DD-1.  
 
(i) 
Price  
 
RBP UCAP MW committed through the Reliability Backstop Procurement, and not 
qualifying for an exception pursuant to Tariff, Attachment DD, section 6.6(g), must be 
offered into the applicable RPM Auctions as price takers, i.e., $0/MW-day UCAP.  
 
(ii) 
Quantity 
 
RBP Resources committed through the Reliability Backstop Procurement must be offered 
into the applicable RPM Auctions.  The UCAP MW quantity offered in an applicable RPM 
Auction for the Delivery Year must be a quantity equal to the lesser of committed RBP 
UCAP MW minus total RPM committed MW through RPM Auctions for the Delivery Year 
and the available UCAP MW at the time of the RPM Auction.   
 
(b) 
Exceptions to the Must Offer Obligation 
 
An RBP Resource that is granted an exception to the RPM must-offer obligation, as set forth in 
Tariff, Attachment DD, section 6.6(g) or 6.6A(c), shall nevertheless be subject to the RBP shortfall 
charge.   
 
(c) 
RBP Shortfall UCAP MW

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

18.7 
Exiting Transmission OwnerLoad Serving Entity RBP Obligations 
 
 
In the event a Load Serving Entity that is allocated RBP Charges withdraws from PJM (whether 
or not caused by the physical withdrawal of another entity from the PJM Region), such Load 
Serving Entity shall be responsible for the remainder of the RBP Charges allocated to it, subject to 
a rate filing with the Federal Energy Regulatory Commission that details the specific terms and 
amounts owed.  Nothing in this provision shall limit such Load Serving Entity’s ability to seek 
redress from another entity to the extent the Load Serving Entity’s withdrawal is caused by that 
other entity’s physical withdrawal from the PJM Region. 
 
In the event a Transmission Owner exits PJM Interconnection, L.L.C. and the quantity of load with 
the Transmission Owner is commensurate with the RBP Resources that are located in that 
Transmission Owner’s territory, the Transmission Owner shall honor the remaining term of the 
RBP commitment. 
 
(a) 
Exiting Transmission Owner with Committed RBP Resources  
 
Any Transmission Owner seeking to exit PJM Interconnection, L.L.C. may, prior to exiting PJM, 
enter into agreements that maintain appropriate rates, terms, and conditions that preserves the RBP 
commitments with the owners of RBP Resource(s) that have been committed through the 
Reliability Backstop Procurement that are located within the physical boundaries of the 
Transmission Owner’s Zone.  PJM and PJMSettlement shall be relieved of any applicable RBP 
obligations made to RBP Resources that are subject to such agreements. In the event no such 
agreement is made and such RBP Resource(s) can be pseudo-tied into the PJM Region, the exiting 
Transmission Owner must, to the extent the Office of the Interconnection elects to retain such RBP 
Resource throughout the term of its RBP commitment, pay all costs for RBP Resources to pseudo-
tie into the PJM Region so that such resource meets the external Capacity Resource eligibility 
requirements set forth in Tariff, Attachment DD, section 5.5A prior to the Transmission Owner 
exiting PJM Interconnection, L.L.C. 
 
Any Transmission Owner seeking to exit PJM Interconnection, L.L.C. with RBP Resource(s) that 
(i) are located within the physical boundaries of the Transmission Owner’s Zone and (ii) cannot 
be pseudo-tied into the PJM Region, and/or which the Office of the Interconnection elects not to 
retain the RBP Resource as a Capacity Resource throughout the term of its RBP commitment, shall 
pay costs associated with the remaining term of the RBP Resource, the amount which shall be 
determined through a filing submitted under the Federal Power Act, prior to exiting PJM 
Interconnection, L.L.C.  Revenues collected in such an event shall be credited to Load Serving 
Entities that are allocated a share of the RBP Charges on a pro rata basis through the remaining 
term of the RBP commitment. 
 
(b) 
Exiting Transmission Owner with Load Allocated RBP Charges 
 
Any Transmission Owner seeking to exit PJM Interconnection, L.L.C. with net load that has been 
allocated RBP Charges for RBP Resources not located within the physical boundaries of the 
Transmission Owner’s Zone may, prior to exiting PJM, enter into agreements that maintain

appropriate rates, terms and conditions that preserves the RBP commitments with the owners of 
such RBP Resource(s). PJM and PJMSettlement shall be relieved of any applicable RBP 
obligations made to RBP Resources that are subject to such agreements. In the event no such 
agreement is made, the exiting Transmission Owner must pay all forward obligations on an 
accelerated basis, the amount which shall be determined through a filing submitted under the 
Federal Power Act, prior to exiting PJM Interconnection, L.L.C.  Any such revenues collected shall 
be distributed to the RBP Resources under the standard daily RBP settlement schedule to such 
resources through the remaining term of the RBP commitment.

18.8 Credit Requirements for RBP Sellers and LSEs Allocated RBP Charges
The provisions of Tariff, Attachment DD, section 18.8(a) shall apply to RBP Sellers seeking to 
submit RBP Sell Offers in the Reliability Backstop Procurement.  The provisions of Tariff, 
Attachment DD, section 18.8(b) shall apply to LSEs allocated costs for RBP UCAP MW procured 
through the Reliability Backstop Procurement, as determined in accordance with Tariff, 
Attachment DD, section 18.3.  Nothing in this Tariff, Attachment DD, section 18 supersedes the 
provisions of Tariff, Attachment Q.  
In addition, sSettlement during any Delivery Year of cleared positions resulting from, or expected 
to result from, the Reliability Backstop Procurement may be included, as appropriate, including 
payments and Locational Reliability Charges associated with the capacity commitments of RBP 
Resources, shall not be considered in Peak Market Activity pursuant to Tariff, Attachment Q, 
Section VII.A.  The forms of acceptable credit support shall be limited to RBP Collateral.
The Reliability Backstop Procurement credit requirements described herein shall be separate from 
and additional to any credit requirements for participation in RPM Auctions and bilateral 
transactions under Tariff, Attachment DD, section 4.6, and other market activity in the PJM 
Markets, as set forth in Tariff, Attachment Q, and shall be applied separately to each RBP Seller 
with RBP Sell Offer and each LSE allocated cost for RBP UCAP MW procured through the 
Reliability Backstop Procurement, as determined in accordance with Tariff, Attachment DD, 
section 18.3.  
(a)
RBP Credit Requirements of RBP Sellers Seeking to Submit RBP Sell Offers 
Prior to or simultaneous with submitting RBP Sell Offers, RBP Sellers seeking to participate in 
the Reliability Backstop Procurement must post the appropriate amount of the Reliability Backstop 
ProcurementRBP credit requirement to each RBP Resource for which RBP Sell Offers are 
submitted.  
(i)
Applicability
An RBP Seller seeking to submit an RBP Sell Offer in the Reliability Backstop 
Procurement must satisfy the credit requirement, i.e., the RBP credit requirement specified 
herein, prior to or simultaneously with submitting such RBP Sell Offer.  
(ii)
RBP Resource Credit Requirement 
The credit requirement applicable to an RBP Seller seeking to submit an RBP Sell Offer in 
the Reliability Backstop Procurement shall be the RBP credit requirement as provided in 
Tariff, Attachment DD, section 18.8(iv). 
The total RBP credit requirement for each RBP Seller shall be, for the sum of the credit 
requirements for all RBP Sell Offers submitted by such RBP Seller in the Reliability 
Backstop Procurement.

(iii)
Reduction in RBP Credit Requirement 
(A)
The RBP credit requirement shall be returned for any RBP 
Resources that do not receive a commitment through the Reliability Backstop 
Procurement, within five (5) business days of the completion of the clearing process 
pursuant to Tariff, Attachment DD, section 18.5(f).    
(B)
Where an RBP Seller’s RBP Sell Offer is committed through the 
Reliability Backstop Procurement and the RBP Resource subsequently achieves 
commercial operation, the Office of the Interconnection may return the RBP 
Reliability Backstop Procurement Ccredit Requirement requirement after a one-
year look-back from the achievement of commercial operation.   
(iv)
Calculation of RBP Credit Requirement for RBP Sellers Seeking to Submit 
submit RBP Sell Offers in the RBP 
RBP Sell Offers submitted by RBP Sellers in the Reliability Backstop Procurement shall 
be accompanied by a Reliability Backstop Procurement credit requirement, which shall be 
equal to: 
• 0.2 × (••• •••• ••••• ••••• ••
$
••−•••) • × (•••• •• ••)• × 365
•
•••
••••• • =
••••
(v)
Credit Responsibility for Traded RBP Resource Commitment
The Office of the Interconnection may require that credit and financial responsibility for a 
committed RBP Resource that is traded remain with the original party (which for these 
purposes, means the party bearing credit responsibility for the committed RBP Resource 
immediately prior to trade) unless the Office of the Interconnection determines that the 
receiving party has independently posted sufficient credit support with the Office of the 
Interconnection and agreed by providing written confirmation to the Office of the 
Interconnection that it will fully assume the credit responsibility associated with the 
committed RBP Resource.  In determining the appropriate level of credit for any receiving 
party, the Office of the Interconnection may rely on Tariff, Attachment Q.
(b)
RBP Credit Requirements Applicable to Load Serving Entities Responsible for 
RBP Charges 
Prior to the first Delivery Year, the assessment of an RBP credit requirement by the Office of the 
Interconnection, LSEs allocated cost responsibility for RBP Charges, pursuant to Tariff, 
Attachment DD, section 18.3, must post RBP Collateral for the RBP credit requirement, calculated 
as set forth herein:
(i)
RBP Credit Requirement for Load Serving Entities

(A)
The cumulative RBP credit requirement for Load Serving Entities 
for a given Delivery Year shall be equivalent to the product of the RBP Credit Rate 
(as determined in accordance with Tariff, Attachment DD, section 18.8(b)(i)(B)) 
multiplied by the committed RBP UCAP MW committedamount, where 
the RBP Credit Rate shall equal $1.5 million, as may be reduced, for 
reasons including a change in the total committed RBP UCAP MW, when 
total posted RBP Collateral is greater than the total remaining RBP Charges 
obligations, over time by the Office of the Interconnection to an amount 
sufficient to cover the total existing RBP Charges obligations; and  
the RBP UCAP MW committed amount shall equal the total amount of RBP UCAP 
MW that receives a commitment through the Reliability Backstop Procurement and is 
supported by an RBP Resource that has reached commercial operation by the start of the 
applicable Delivery Year.  The foregoing determination of the committed RBP UCAP MW 
amount shall exclude minus each commitment of RBP UCAP MW that is rescinded 
pursuant to Tariff, Attachment DD, section 18.6(e).  
Following the commencement of commercial operation of all Capacity Resources 
with RBP commitments, PJM shall review the RBP Credit Rate and present any 
recommendations to stakeholders through the Members Committee. 
When total posted RBP Collateral is greater than the total remaining RBP payment 
obligations, the Office of the Interconnection will make available excess collateral, upon 
request by an applicable Load Serving Entity.  
The cumulative RBP credit requirement for Load Serving Entities shall be met 
through RBP Collateral posted by those Load Serving Entities allocated cost pursuant to 
Tariff, Attachment DD, section 18.3.
(B)
The Office of the Interconnection shall apply the following credit 
requirements to each Load Serving Entity allocated responsibility for RBP 
Obligations, pursuant to Tariff, Attachment DD, section 18.3, and each such LSE 
shall maintain credit support in an amount equal to its RBP LSE Credit 
Requirement, calculated as follows:
RBP LSE Credit Requirement = RBP Credit Rate x Allocated RBP Credit 
MW
For purposes of this calculation:
RBP Credit Rate shall mean an amount per MW equal to 40% of the 
discounted total RBP payment obligation per MW over the applicable RBP 
commitment term, calculated using the weighted-average RBP clearing price of all 
RBP UCAP MW committed through the RBP.

Allocated RBP Credit MW shall mean the amount of RBP UCAP MW, 
expressed in MW, for which the LSE has been allocated responsibility for RBP 
Charges in accordance with Tariff, Attachment DD, section 18.3 and as determined 
in accordance with this Tariff, Attachment DD, section 18.8(b)(i)(B)(1) or (2), as 
appropriate.
(1)
For Load Serving Entities with an RBP Obligation in accordance 
Tariff, Attachment DD, section 18.3, prior to forty-five (45) days before the start of 
a giventhe Delivery Year, such Load Serving Entities, must post, or maintain an 
existing, RBP Collateral equal to the RBP Credit Rate multiplied by the 
Allocated$1.5 million x the allocated RBP Obligation Credit MW, where the 
zone/area allocated amount committed RBP UCAPRBP Obligation MW is further 
allocated to eachequals Load Serving Entity based on the relevant Load Serving 
Entity’s percent share of the zone/area’s RBP Obligation MW assigned by the 
Electric Distributor and scaled, as necessary, in the event that the RBP Obligation 
MW values uploaded by the Electric Distributor do not sum to the fixed, Final RBP 
Target MW for the zone/area. For Load Serving Entities required to post RBP 
Collateral by this section 18.8(b)(i)(B)(1)the foregoing sentence, the Office of the 
Interconnection may evaluate such Load Serving Entity for unreasonable credit risk 
under the Unreasonable Credit Risk provisions of Tariff, Attachment Q, Section II, 
and require additional RBP Collateral as appropriate.  
(2)
To the extent such Load Serving Entity is allocated cost 
pursuant to Tariff, Attachment DD, section 18.3 and no RBP Obligations are 
reported to the Office of the Interconnection in an Electric Distributor 
zone/area in which the Load Serving Entity serves load, prior to forty-five 
(45) days before the start of the a given Delivery Year, such Load Serving 
Entities, may be required to post, or maintain an existing, RBP Collateral 
equal to the product of the RBP Credit Rate multiplied by the allocated
allocated RBP UCAP Credit MW, where the allocated zone/area committed
RBP UCAP MW is allocated usingshall equal the relevant Load Serving 
Entity’s proportionalpro-rata share of the Daily Unforced Capacity 
Obligation for the zone/area as determined in accordance with RAA, 
Schedule 8. For Load Serving Entities required to post RBP Collateral by 
this section 18.8(b)(i)(B)(2),by the foregoing sentence, the Office of the 
Interconnection may evaluate whether such Load Serving Entity for 
unreasonable credit risk under the Unreasonable Credit Risk provisions of 
Tariff, Attachment Q, Section II, and require additional RBP Collateral as 
appropriate.
(C)
Credit Requirements Associated With Intra-Delivery Year Transfer 
of Load and Allocated RBP UCAP MW Cost Responsibility 
(1)
To the extent a Load Serving Entity transfers its load serving 
obligations that are associated with committed RBP UCAP MW, as

determined pursuant to Tariff, Attachment DD, section 18.3, then the 
transferee LSE must fully satisfy all applicable credit and collateral 
requirements required herein associated with such transferred committed 
RBP UCAP MW obligation and, as applicable, the credit requirements in 
Tariff, Attachment Q.  Transferee shall independently post sufficient RBP 
Collateral directly with the Office of the Interconnection to satisfy the 
incremental committed RBP UCAP MW associated with the acquired load.
(2)
Transferor shall be released from its financial obligations for 
amount of RBP Collateral associated with the committed RBP UCAP MW 
associated with the transferred load.  Any RBP Collateral posted by 
transferor shall be returned once Transferee has posted the RBP Collateral 
determined in accordance with Tariff, Attachment DD, section 18.8(c) and 
any unpaid invoice amounts associated with such transfer have been paid 
by the transferor.