ER27-454-000 · 2026-11-09 · PJM

FERC rendition of the electronically filed tariff records

FERC rendition of the electronically filed tariff records in Docket No. ER27-00454-000
Filing Data:
Tariff Record Data:
CID
Filing Title
Company Filing
Identifier
Type of Filing
Code
Associated
Filing Identifier
C000030
Revised Reliability Backstop
Procurement Rules in ER26-
3380-000
11704
10
Tariff Title
Tariff ID
Payment
Confirmation
Suspension
Motion
Intra-PJM Tariffs
23
Record Content Description
O-P-Q
Tariff Record Title
OATT Definitions - O - P - Q
Record Version Number
42.0.0
Option Code
A
Record Narrative Name
OATT Definitions - O - P - Q
Tariff Record ID
10
Tariff Record Collation Value
7435927
Tariff Record Parent Identifier
3
Proposed Date
2027-02-28
Priority Order
700
Record Change Type
CHANGE
Record Content Type
4
Associated Filing Identifier

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.

Tariff Record Data:
Record Content Description
R-S
Tariff Record Title
OATT Definitions – R - S
Record Version Number
50.0.0
Option Code
A
Record Narrative Name
OATT Definitions – R - S
Tariff Record ID
11
Tariff Record Collation Value
8151030
Tariff Record Parent Identifier
3
Proposed Date
2027-02-28
Priority Order
800
Record Change Type
CHANGE
Record Content Type
4
Associated Filing Identifier

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 any one of:(1) a cash deposit, including any interest thereon, (2) a
surety bond with a provider, amount and form determined by and acceptable to PJM or
PJMSettlement, or (3) a letter of credit issued for the benefit of PJM or PJMSettlement, with 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.

Tariff Record Data:
Record Content Description
ATTACHMENT DD.5.5
Tariff Record Title
OATT ATTACHMENT DD.5.5 Eligibility for
Participation in RPM
Record Version Number
9.0.0
Option Code
A
Record Narrative Name
5.5
Eligibility for Participation in
RPM Auctions
Tariff Record ID
1148
Tariff Record Collation Value
661755172
Tariff Record Parent Identifier
1142
Proposed Date
2027-02-28
Priority Order
700
Record Change Type
CHANGE
Record Content Type
4
Associated Filing Identifier

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 Model Auction and is not required to submit a binding notice of
intent to offer into such auction.
However, a Planned Generation Capacity Resource that is
committed in the RBP for the 2030/2031 Delivery Year must still be the subject of a notice of intent
to be offered into the Base Residual Auction associated with the 2030/2031 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.

Tariff Record Data:
Record Content Description
OATT ATT DD.6.6
Tariff Record Title
OATT ATTACHMENT DD.6.6 Offer Requirement
for Capacity Resour
Record Version Number
6.0.0
Option Code
A
Record Narrative Name
OATT ATTACHMENT DD.6.6 Offer Requirement
for Capacity Resour
Tariff Record ID
1771
Tariff Record Collation Value
671051570
Tariff Record Parent Identifier
1161
Proposed Date
2027-02-28
Priority Order
600
Record Change Type
CHANGE
Record Content Type
4
Associated Filing Identifier

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.

Tariff Record Data:
Record Content Description
OATT ATT DD.6.6A
Tariff Record Title
OATT ATTACHMENT DD.6.6A Offer
Requirement for Capacity Perfo
Record Version Number
8.0.0
Option Code
A
Record Narrative Name
OATT ATTACHMENT DD.6.6A Offer
Requirement for Capacity Perfo
Tariff Record ID
1773
Tariff Record Collation Value
671051580
Tariff Record Parent Identifier
1161
Proposed Date
2027-02-28
Priority Order
600
Record Change Type
CHANGE
Record Content Type
4
Associated Filing Identifier

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 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 Capacity Performance 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 an RBP UCAP
MW commitment and is expected to be in-service for those Delivery Years.

Tariff Record Data:
Record Content Description
ATTACHMENT DD.18
Tariff Record Title
OATT ATTACHMENT DD.18 RELIABILITY
BACKSTOP PROCUREMENT
Record Version Number
2.0.0
Option Code
A
Record Narrative Name
OATT ATTACHMENT DD.18 RELIABILITY
BACKSTOP PROCUREMENT
Tariff Record ID
2334
Tariff Record Collation Value
679642700
Tariff Record Parent Identifier
1132
Proposed Date
2027-02-28
Priority Order
600
Record Change Type
CHANGE
Record Content Type
4
Associated Filing Identifier

18.
RELIABILITY BACKSTOP PROCUREMENT
The Reliability Backstop Procurement or “RBP” is a one-time procurement, starting in 2027, 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.

Tariff Record Data:
Record Content Description
ATTACHMENT DD.18.1
Tariff Record Title
ATTACHMENT DD.18.1 Determination of
Final RBP Target
Record Version Number
2.0.0
Option Code
A
Record Narrative Name
ATTACHMENT DD.18.1 Determination of
Final RBP Target
Tariff Record ID
2335
Tariff Record Collation Value
679642800
Tariff Record Parent Identifier
2334
Proposed Date
2027-02-28
Priority Order
700
Record Change Type
CHANGE
Record Content Type
4
Associated Filing Identifier

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 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 Region] 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, 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.

Tariff Record Data:
Record Content Description
ATTACHMENT DD.18.2
Tariff Record Title
ATTACHMENT DD.18.2 Qualifying New UCAP
MW
Record Version Number
2.0.0
Option Code
A
Record Narrative Name
ATTACHMENT DD.18.2 Qualifying New UCAP
MW
Tariff Record ID
2336
Tariff Record Collation Value
679642900
Tariff Record Parent Identifier
2334
Proposed Date
2027-02-28
Priority Order
600
Record Change Type
CHANGE
Record Content Type
4
Associated Filing Identifier

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.
Such report shall be accompanied by evidence of at least one of the
following supporting materials. Likewise, to the extent LSEs, interconnecting customers, large
loads, Transmission Owners, or other entities report Qualifying RBP Offset UCAP MW to the
Office of the Interconnection during such RBP bid submission window, the reported Qualifying
RBP Offset UCAP MW must be accompanied with evidence of at least one of the following
supporting materials:
(i)
Signed bilateral contracts for Qualifying RBP Offset UCAP MW for at least
five Delivery Years with a commercial operation date prior to the start of the 2032/2033

Delivery Year, and matched with Large Load that has an executed electric service
agreement or transmission service agreement, indicating that the load will be coming
online in the 2027/2028 or 2028/2029 Delivery Year;
(ii)
Self-Supply generation that is in a Relevant Electric Retail Regulatory
Authority (“RERRA”)-approved or accepted integrated resource plan with either
associated generation in the PJM interconnection queue or signed bilateral contracts for
Qualifying RBP Offset UCAP MW for at least five Delivery Years with a commercial
operation date prior to the start of the 2032/2033 Delivery Year, and matched with load that
has an executed electric service agreement or transmission service agreement, indicating
that the Large 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 Load(s) will, in a MW quantity equal to
MW quantity of the new load(s), either (a) participate as Annual Demand Resources or
DER Capacity Aggregation Resources starting in the 2028/2029 Delivery Year Second
Incremental Auction and continuing through the 2032/2033 Delivery Year, or (b) purchase
replacement Qualifying RBP Offset UCAP MW that are eligible generation or storage
resources.
(d)
To determine the quantity of any Qualifying RBP Offset UCAP MW that are
verified by the Office of the Interconnection and used to decrement the Initial RBP Target, the
Office of the Interconnection shall use the most up-to-date ELCC Class Ratings 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 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.

Tariff Record Data:
Record Content Description
ATTACHMENT DD.18.3
Tariff Record Title
ATTACHMENT DD.18.3 Cost Allocation of
RBP Charges, Credits
Record Version Number
2.0.0
Option Code
A
Record Narrative Name
ATTACHMENT DD.18.3 Cost Allocation of
RBP Charges, Credits, and Shortfall
Charges
Tariff Record ID
2337
Tariff Record Collation Value
679643000
Tariff Record Parent Identifier
2334
Proposed Date
2027-02-28
Priority Order
600
Record Change Type
CHANGE
Record Content Type
4
Associated Filing Identifier

18.3
Allocation of RBP Charges, Credits, and Shortfall Charges
(a)
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 Distributor.
(ii) The allocation based on the zone/area’s MW share of the total incremental Large Load MW
shall be reduced for the purpose of this calculation to the extent:
(1)
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
(2)
an Electric Distributor zone/area meets the opt-out provisions set forth in
accordance with Tariff, Attachment DD, section 18.1(d).
The resulting reduced MW, floored at zero, 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)
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
(120) 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 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, section 7.2B.

Tariff Record Data:
Record Content Description
ATTACHMENT DD.18.3A
Tariff Record Title
ATTACHMENT DD.18.3A Electric Distributor
Reporting
Record Version Number
1.0.0
Option Code
A
Record Narrative Name
ATTACHMENT DD.18.3A Electric Distributor
Reporting
Tariff Record ID
2371
Tariff Record Collation Value
679643010
Tariff Record Parent Identifier
2334
Proposed Date
2027-01-29
Priority Order
600
Record Change Type
CHANGE
Record Content Type
4
Associated Filing Identifier

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.

Tariff Record Data:
Record Content Description
ATTACHMENT DD.18.4
Tariff Record Title
ATTACHMENT DD.18.4 Scope of the
Reliability Backstop Procure
Record Version Number
2.0.0
Option Code
A
Record Narrative Name
ATTACHMENT DD.18.4 Scope of the
Reliability Backstop Procurement
Tariff Record ID
2338
Tariff Record Collation Value
679643100
Tariff Record Parent Identifier
2334
Proposed Date
2027-02-28
Priority Order
600
Record Change Type
CHANGE
Record Content Type
4
Associated Filing Identifier

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 four weeks. 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.

Tariff Record Data:
Record Content Description
ATTACHMENT DD.18.5
Tariff Record Title
ATTACHMENT DD.18.5 The Reliability
Backstop Procurement Proc
Record Version Number
2.0.0
Option Code
A
Record Narrative Name
ATTACHMENT DD.18.5 The Reliability
Backstop Procurement Process
Tariff Record ID
2339
Tariff Record Collation Value
679643200
Tariff Record Parent Identifier
2334
Proposed Date
2027-02-28
Priority Order
600
Record Change Type
CHANGE
Record Content Type
4
Associated Filing Identifier

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; and
(v)
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 the 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(a) 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, 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 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.
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, evidence 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 Offer.
Such projects must also be accompanied by 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.
(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.

Tariff Record Data:
Record Content Description
ATTACHMENT DD.18.6
Tariff Record Title
ATTACHMENT DD.18.6 RBP Resource
Obligations
Record Version Number
2.0.0
Option Code
A
Record Narrative Name
ATTACHMENT DD.18.6 RBP Resource
Obligations
Tariff Record ID
2340
Tariff Record Collation Value
679643300
Tariff Record Parent Identifier
2334
Proposed Date
2027-02-28
Priority Order
600
Record Change Type
CHANGE
Record Content Type
4
Associated Filing Identifier

18.6
RBP Resource Obligations
(a)
Capacity Must Offer Obligation
An RBP Resource committed through the Reliability Backstop Procurement must offer all
committed RBP UCAP MW into the RPM Auctions as Capacity Resources pursuant to the
capacity must offer requirements and exceptions set forth in Tariff, Attachment DD, sections 6.6
and 6.6A. The applicable RPM Auctions shall be the Base Residual Auctions and Incremental
Auctions conducted after an RBP Resource’s RBP UCAP MW have been committed through the
Reliability Backstop Procurement beginning with the first Delivery Year in which such resource is
has an RBP commitment and is expected to be in service. Such offer requirement shall continue for
each subsequent Delivery Year through the end of the RBP 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 2030/2031 Base
Residual Auction shall have a must offer requirement in the next RPM Auction, including but not
limited to the 2031/2032 Base Residual Auction and the 2030/2031 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.

Tariff Record Data:
Record Content Description
ATTACHMENT DD.18.7
Tariff Record Title
ATTACHMENT DD.18.7 Exiting Transmission
Owner RBP Obligation
Record Version Number
2.0.0
Option Code
A
Record Narrative Name
ATTACHMENT DD.18.7 Exiting Transmission
Owner RBP Obligations
Tariff Record ID
2341
Tariff Record Collation Value
679643400
Tariff Record Parent Identifier
2334
Proposed Date
2027-02-28
Priority Order
600
Record Change Type
CHANGE
Record Content Type
4
Associated Filing Identifier

18.7
Exiting Load 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.

Tariff Record Data:
Record Content Description
ATTACHMENT DD.18.8
Tariff Record Title
ATTACHMENT DD.18.8 Credit Requirements
for RBP Sellers
Record Version Number
2.0.0
Option Code
A
Record Narrative Name
ATTACHMENT DD.18.8 Credit Requirements
for RBP Sellers and LSEs Allocated RBP
Charges
Tariff Record ID
2343
Tariff Record Collation Value
679643500
Tariff Record Parent Identifier
2334
Proposed Date
2027-02-28
Priority Order
600
Record Change Type
CHANGE
Record Content Type
4
Associated Filing Identifier

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.
Settlement during any Delivery Year of cleared positions resulting from, or expected to result from,
the Reliability Backstop Procurement, 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 RBP 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 credit
requirement after a one-year look-back from the achievement of commercial
operation.
(iv)
Calculation of RBP Credit Requirement for RBP Sellers Seeking to submit
RBP Sell Offers in the RBP
RBP Sell Offers submitted by RBP Sellers in the Reliability Backstop Procurement shall be
accompanied by a Reliability Backstop Procurement credit requirement, which shall be
equal to:
(v)
Credit Responsibility for Traded RBP Resource Commitment
The Office of the Interconnection may require that credit and financial responsibility for a
committed RBP Resource that is traded remain with the original party (which for these
purposes, means the party bearing credit responsibility for the committed RBP Resource
immediately prior to trade) unless the Office of the Interconnection determines that the
receiving party has independently posted sufficient credit support with the Office of the
Interconnection and agreed by providing written confirmation to the Office of the
Interconnection that it will fully assume the credit responsibility associated with the
committed RBP Resource. In determining the appropriate level of credit for any receiving
party, the Office of the Interconnection may rely on Tariff, Attachment Q.
(b)
RBP Credit Requirements Applicable to Load Serving Entities Responsible for
RBP Charges
Prior to the first Delivery Year, the assessment of an RBP credit requirement by the Office of the
Interconnection, LSEs allocated cost responsibility for RBP Charges, pursuant to Tariff,
Attachment DD, section 18.3, must post RBP Collateral for the RBP credit requirement, calculated
as set forth herein:
(i)
RBP Credit Requirement for Load Serving Entities
(A)
The cumulative RBP credit requirement for Load Serving Entities for a
given Delivery Year shall be equivalent to RBP Credit Rate (as determined in accordance
with Tariff, Attachment DD, section 18.8(b)(i)(B)) multiplied by the committed RBP

UCAP MW amount, where the committed RBP UCAP MW 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 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 given Delivery Year, such Load Serving Entities, must post, or maintain an
existing, RBP Collateral equal to the RBP Credit Rate multiplied by the Allocated
RBP Credit MW, where the zone/area allocated amount committed RBP UCAP

MW is further allocated to each 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. For Load Serving Entities required to post RBP Collateral
by this section 18.8(b)(i)(B)(1), 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 a given Delivery Year, such Load Serving
Entities, may be required to post, or maintain an existing, RBP Collateral
equal to the RBP Credit Rate multiplied by the allocated RBP Credit MW,
where the zone/area committed RBP UCAP MW is allocated using the
relevant Load Serving Entity’s proportional 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), 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.