Manual Updates

• Cover to Cover Periodic Review
• Administrative Changes: Clarifications, grammar, punctuation, capitalization and spacing changes throughout this manual

Note: CEII access is required to view this manual.

• FE East: Updated Homer City RAS procedure with additional scheme position.
• PPL: Updated the Wescosville 500/138 T3 Transformer Switching procedure to indicate the Wescosville T5 is normally open for contingency control.
• BGE: Updated the Calvert Cliffs-Chalk Point line number from 5071 to 5072

Note: CEII access is required to view this manual.

• DOM: Removed Marsh Run and Remington CT Stability Procedure due to system topology changes.
• DOM: Removed South Anna and Louisa CT Islanding Scheme procedure due to system topology changes.
• FE-East: Updated circuit breaker names for the Homer City Stability Trip Procedure.
• FE-East: Added new Homer City Runback Procedure (OM-55).

The following changes were identified as part of the manual periodic review:

• Section 1.1 - updated the references to PJM Manuals to align with their current titles
• Section 1.3 - updated New Services Queue Swim Lane diagram to improve readability
• Section 2.1 - updated section title for consistency

The clarifying changes were identified as part of the manual periodic review:

• Section 2.2 - added clarification on the existing requirement for submittal of one-line diagrams stamped by a Professional Engineer in Tariff Attachment Y section 8. One-line diagrams must be stamped by a Professional Engineer licensed in the state where the generating facility is located.
• Section 2.4 - added clarification on site control requirements to indicate that developers are prohibited from submitting evidence of site control of the same land for multiple queue requests unless the total size of such land is adequate to support all facilities contemplated by all the queue positions.

The following administrative changes were identified as part of the periodic manual review:

• Section 1.1: Updated section header and manual titles in Exhibit 1.
• Section 1.3: Updated Exhibit 2: New Services Requests Swim Lane Diagram

The following administrative changes were made as part of the periodic manual review:

• Section 1.1 – updated the references to PJM manuals to align with their current titles
• Section 1.3 - updated New Services Queue Swim Lane diagram
• Section 2.2.1 - added table to clarify queue study timelines
• Section 2.3.1 – added diagram to illustrate New Service Request deficiency review timeline
• Section 4.1 - updated section header
• Section 4.2. 4.3.1, 4.6.1, 4.6.2 - added tables to clarify interconnection study milestone dates
• 4.5.1, 4.5.3, 5.4.4 – renumbered existing exhibits
• Section 5.5.2 - clarified Specific Process Flow and Timeline

• Attachment C: Plant Specific NPIRs Revision History: NPIR revision update

• Periodic review updated as follows:
• Attachment B: Added web links to the restoration forms.
• Attachment G: Updated Table 1 Annual Restoration Plan Review Deadlines to include new TOs and a revision to SMECO.
• Attachment H: Updated Under Frequency Load Shed table with new data.

• Updated Section 2.2 Application and Membership Cost based on FERC approved tariff changes

• Periodic Review
• Corrected typos, removed references to SPS. Updated references to Section 5.
• Moved the contents of Manual-03 Section 5 to a new Manual-03B: Transmission Operating Procedures.
• Section 1.5: Removed Section 2 reference from Manual 3A.
• Section 1.7: Updated RAS procedure for PRC-012 standard.
• Section 3 and Attachment C: Updated baseline voltage tables and voltage exception request due to new eDART function for voltage limit implementation.
• Section 3.9: Removed language concerning TSA Benchmarking.
• Section 3.11: Effective June 1, 2020, eDART Voltage Schedules is the required method for communicating generator voltage schedules.
• Section 4.5: Added Outage Acceleration posting site and contact email.
• Section 5: Updated RTO Perry and Calvert Cliffs NPIR voltage limits.
• Section 5: Updated NY/NJ PAR Coordination and deleted 5018 Hopatcong – Ramapo PAR Coordination in RTO based on updated Joint Operating Memo (OM 022B Market to Market Redispatch Flowgates and NY NJ PAR Coordination, Rev. 10).
• Section 5: Updated AE directional ratings table.
• Section 5: Updated AEP Jacksons Ferry SVC Procedure.
• Section 5: Removed AEP Cook Stability Restriction Procedure.
• Section 5: Updated FE-S Belmont RAS Procedure.
• Section 5: Updated FE-E Seneca Stability Procedure with updated limits.
• Section 5: Added new FE-E Ironwood Stability Procedure.
• Section 5: Updated FE-E Homer City Stability Trip procedure.
• Section 5: Updated BGE Calvert Cliffs Stability Limit Procedure.
• Section 5: Deleted BGE Westport Breaker Limitations and Gould St. Generation Operations procedure.
• Section 5: Removed ComEd Lisle substation from Normally Open Bus Tie procedures.
• Section 5: Updated language to use RAS for the ComEd Electric Junction – North Aurora procedure and modified location of CS 0605 to be at 11106 line
• Section 5: Updated ComEd Camp Grove Islanding (SPOG 2-40) procedure for new configuration.
• Section 5: Updated the ComEd Powerton Stability Trip Scheme procedure due to the new Nevada substation.
• Section 5: Updated the ComEd Islanding Prevention Scheme for TSS 941 Grand Ridge Generation (SPOG 2-41) procedure.
• Section 5: Updated ComEd Prospect Heights SVC procedure.
• Section 5: Added new Lancaster Automatic Trip Scheme to Prevent Islanding of Ecogrove procedure.
• Section 5: Updated powerflow/SA language for the DOM Northern Virginia High Voltage Control procedure.
• Section 5: Added new DOM Mosby/Mt. Storm SVC procedure and Colington STATCOM procedure.
• Section 5: Added new DOM Ladysmith/Doswell Stability Procedure.
• Section 5: Updated DOM Brunswick/Greensville Stability procedure.
• Section 5: Added new PECO Conowingo stability procedure.
• Section 5: Added new PPL Safe Harbor Relay procedure.
• Section 5: Updated PPL Martins Creek stability procedure.
• Section 5: Updated PSEG Artificial Island procedure due to new substation.
• Attachment A: Updated language for Wolfs Crossing RAS.
• Attachment A: Removed two Lisle schemes due to station reconfiguration.
• Attachment B: Added clarifying language to ‘Cut-In’ Criteria for TO associated with project work.

Administrative Change (05/28/2020): 

• Attachment A: Updating “Equipment model exchange” to “EMS model exchange”. Both refer to the EMS network model information exchange. The change is being made since EMS model exchange is a widely used and known term.

Revision 41 (05/28/2020):

• Cover to Cover Periodic Review
• Attachment A: Added external entities PJM shares network model information with Attachment A: To comply with TOP-003, added a new column in the data specification tables that reflects the periodicity of providing the mentioned data where applicable
• Attachment A: Removed Row B.5 Black Start Test Data from Table B since this is not an EMS service
• Attachment A: Removed Row B.16 AVR/PSS Excitation control since this is not an output from PJM
• Attachment A: Changed Row B.3.5 Frequency input from ‘Required’ to ‘Optional’ for PJM Member Generating Entitie
• Attachment A: Changed Row B.3.6 Status of BES Circuit Breakers from ‘Required’ to ‘Mandatory if not Attainable by Existing Telemetry’ for PJM Member Generating Entities
• Attachment B: Removed references to EOP-005-3 R3 and R4, as these are already covered by Manual 36 Attachment G

• Conforming revisions for FERC Order ER20-271-001 issued on February 28, 2020 to clarify that Price Responsive Demand (PRD) registration will not be considered in the calculation of a performance shortfall or bonus performance for a Performance Assessment Interval (PAI) when the PRD Curve associated with registration indicates a price point where no demand reduction is expected at the real-time LMP recorded during the PAI. (Section 3A.6.2A)

• Conforming revisions for FERC Order ER20-217-000 issued on December 30, 2019 to update certain rules and requirements for PRD to conform to rules and requirements for Capacity Performance resources.
  • Added prior to 2022/2023 Delivery Year, PRD Provider is subject to performance compliance during Maximum Emergency Events. Added effective with 2022/202 Delivery Year, PRD Provider is subject to Non-Performance Assessment during the Delivery Year (Sections 3A.1, 3A.3, 3A.6, 3A.6.2, 8.4A, 9.1.9, and 9.4.2)
  • Deleted outdated provisions related to the Transition Period for PRD (Section 3A.2)
  • Added footnote that any PRD Plan submitted and approved for 2022/2023 Delivery Year BRA may be withdrawn or modified no later than 30 days prior to the commencement of the 2022/2023 Delivery Year BRA. (Section 3A.4.1)
  • Added that Zonal Scaling Factors for use in preparation of PRD Plans will be posted by PJM prior to the 2022/2023 Delivery Year. (Section 3A.4.1)
  • Added effective with 2022/203 Delivery Year, the PRD Value for Zone/LDA provided in a PRD Plan is based on a Zonal/LDA Peak Load Contribution (PLC) value minus (the Zonal/LDA Firm Service Level (FSL) quantity times the loss factor). (Section 3A.4.2)
  • Added Expected Peak Load Value of PRD is submitted prior to 2022/2023 Delivery Year and Peak Load Contribution value of PRD is submitted effective with 2022/2023 Delivery Year. (Section 3A.4.2)
  • Added MSEL is submitted prior to 2022/2023 Delivery Year and FSL is submitted effective with 2022/2023 Delivery Year. (Section 3A.4.3)
  • Added effective with 2022/203 Delivery Year, the Nominal PRD Value for a registration is based on registration’s PLC minus (the registration’s FSL times the loss factor). (Section 3A.5)
  • Added new section to describe process used to determine compliance for a PRD Provider during a Performance Assessment Interval (PAI) and the procedure used to calculate the PRD Provider’s Performance Shortfall or Bonus Performance Credit for a PAI. (Section 3A.6.2A)
  • Added new section to describe process used to determine PRD Test Compliance effective with the 2022/2023 Delivery Year. (Section 3A.6.3A)
  • Added PRD Credit Rates that are applicable starting with 2022/2023 Delivery Year. (Section 4.8.4)
  • Deleted an incorrect process for assessing PRD Test Failure Charges (Section 9.4.3)
  • Added that effective with the 2022/2023 Delivery Year, the factor equal to FZWNSP/ FZPLDY is eliminated in the calculation of the LSE PRD Credit (Section 9.4.4)
• Clean-up revisions to Maximum Emergency Event Compliance section (Section 3A.6.2)
  • Clarified that compliance is measured for a PRD registration during a Maximum Emergency Event when a demand reduction is expected based on the PRD Curve in Energy Market.
  • Corrected manual language to conform to language in RAA and OATT regarding the MESL adjustment
    • Corrected the description of the service level adjustment factor to reference load “during the emergency event” as opposed to load “at time of RTO unrestricted peak”

Added the clause “meeting the price conditions specified for compliance” to Zonal Expected Peak Load Value of PRD in the Zone

• Updated hyperlinks, in Appendix B eDART Application Functionality Training including Network Model and TERM Applications, to correct path & added language and hyperlink to available training environment:
  • "The eDART application is available on the web via https://edart.pjm.com/mui/index.htm. There is a training environment available: https://edarttrain.pjm.com/mui/index.htm
  • In addition, eDART Training is online at: https://pjm.com/markets-and-operations/etools/edart.aspx (PJM.com # Markets & Operations # PJM Tools # eDART)"
• Deleted "a Quick Reference Guide, which is a shortened version of the User Guide," in Appendix B, from site user guide paragraph.

• Attachment F: Overview and Requirements for Remote Operations of Market Operations Centers during the COVID-19 Pandemic: added as a temporary change per review at the Operations Committee. Markets and Reliability Committee was not asked to endorse this addition.

• Section 12:
  • Update to reflect suspension of PJM Opportunity Cost Calculator
  • Update Independent Market Monitor Opportunity Cost Calculator methodology

• Added changes to section 6.1 and 6.3 for long-term and BOPP timing and structure per FRMSTF.
• Administrative Change: Updated “FTRCenter” to “FTR Center” throughout this manual.

• Periodic Review
• Section 6.1.2 – Replaced “cost cap on project construction costs” with “cost commitment proposal”
• Section 8.1 – Updated Cost Evaluation and Containment
• Section Added 8.4 – Cost Comparative Evaluation Framework

• Periodic review updated to address:
• Section 5.4 – added reference to Manual 12, Attachment B.2

• Periodic Review updated to address in all sections:
• Standard grammar
• Standard punctuation
• Capitalization – all capitalized defined terms checked in OA, Tariff and RAA as well as within Manual 12 and the NERC glossary of terms
• Check links
• Check names of PJM departments/divisions
• Remove extra words/add missing words – queried when not obvious
• Fix spelling errors
• Fix spacing errors
• Put times, numbers, phone numbers and units of measure into consistent format
• Updated manual ownership from Chris Pilong to Rebecca Carroll
• About this Manual – updated Bulk Power Electric Supply system facilities to Bulk Power System
• About this Manual – added a reference to the Regional Transmission and Energy Scheduling Practices document
• Section 3.3 – deleted entire section. Section 2.1 of the Regional Transmission and Energy Scheduling Practices document is the official source of this information
• Section 3.4 – deleted entire section. Section 2.2 of the Regional Transmission and Energy Scheduling Practices document is the official source of this information
• Section 4.1.2 and Attachment D – updated language to be consistent with the NERC definition of a Disturbance Control Standard (DCS) event
• Attachment B Section 3.4 – changed cost-capped to offer-capped
• Attachment D – added the NERC definition for a Reportable Disturbance
• Attachment F Section F3 – updated references to PJM Manual 03A which were recently changed

Periodic Review to include:

• Removed EEI from the acronym list (Section 1)
• Removed the definition of Demand Hours (Section 2.1)
• Refined the definition of f-factor (Section 2.1)
• Removed references to retired PJM committees and subcommittees (Section 3)
• Amended the first note (Section 3)
• Added a second clarifying note (Section 3)

• Periodic Review
• Added new Section 3 Member Roles and Responsibilities
• Added new Section 4 Contact Management
• Added new Section 5 Company Account Manager (CAM) Roles and Responsibilities
• Renumbered existing Section 3 Market Data Postings to Section 6: Market Data Postings
• Renumbered existing Section 4 Dispute Resolutions to Section 7: Dispute Resolution
• Deleted references to Andrew Ott
• Relocated Section 2.4 Name Change Process to Section 3.1.2 and renamed to Member Corporate Name Change
• Relocated Section 2.5 Withdrawal Process to Section 3.1.10 and renamed to Withdrawal Requests

• Periodic cover-to-cover review.
• Throughout: Replaced Regional Reliability Organization (RRO) term with “Regional Entity”
• Section 1.1: Updated links to PJM governing documents
• Section 5.1: Updated titles and names of external agreements and removed reference to Duke Energy Progress JOA
• Section 5.2.2: Changed Solar Magnetic Disturbance term to Geo-Magnetic Disturbance
• Attachment A: In Appendix A, updated links to PJM governing documents.
• Attachment A: In Appendix B, updated titles and names to external agreements and removed old reference to MISO-PJM-TVA JOA.
• Attachment A: In Appendix D, updated PJM TOs and TOPs to include Transource WV as TO, and updated Linden VFT registration.
• Attachment C: Updated language in Voltage/Reactive Priorities table to be consistent with M-03 section 3.2.

Manual 14E changes to incorporate FERC Order 845 and 845-A Tariff changes.

 The following sections were updated: 

• Updated Section 3.5.4.4 Option to Build
• Updated Section 4.4.1.3 Option to Build
• Updated Section 5.4.1.4 Option to Build

Manual 14G updates to incorporate FERC Order 845 and 845-A Tariff changes: 

• Capitalized reference to Generating Facility in Section 2.4 to indicate that the term is a defined term in the Tariff
• Added new section 1.8: Service below Generating Facility Capability 

Manual 14G administrative changes:

• Updated the dynamic model study requirements Attachment A-1 Feasibility Study Data Form and Attachment B-2 System Impact Study Data form to align with current PJM process

The following sections were updated: 

• Section 1.1 PJM Interconnection Process overview
• Section 4.2 Feasibility Study
• Section 4.3.1 System Impact Study
• Section 4.4 Facilities Study
• Section 4.5.1 Direct Connection Local and Direct Connection Network Upgrades
• Section 5.5.1 Option to Build
• Section 5.5.1.1 General Timeline
• Section 5.5.2 Specific Process Flow and Timeline

Manual 14A administrative changes:

• Corrected Exhibit 3: Type of Network and Local Upgrades Diagram
• Updated Section 5.2.1.1 Dynamic Model for stability studies to align with current PJM process

• Removal of FERC 715 Exclusion language
• Section 5.3.1: Removed bullet
• Section 5.3.3: Deleted Paragraph
• Attachment D: Removed exclusion for TO Criteria from decisional process diagram
• Administrative Change:
• Updated manual ownership from Aaron Berner to Mark Sims

• Conforming VOM adder format rules to FERC Dockets ER19-210 and EL19-8

• Updated broken hyperlinks in the Sections F2 and F6

• Periodic Review updated to address:
  • Updated NERC Standard references throughout.
  • Section 1.2: Updated interregional studies relating to NYISO studies.
  • Attachment A: Added sensitivity analysis of 90/10 load forecast to the OATF scope.
  • Attachment B: Updated Reliability Analysis procedure.

• Updated Section 6.1.1 to reflect an annual calculation of the demand charge border rates for Firm Point-to-Point Transmission Service
• Added Section 6.2.4 to describe an adjustment to the monthly demand border charge rate for a transmission customer taking firm point-to-point transmission service at the border with a point of delivery at a Merchant Transmission Facility

• Section 2.2: Updated the DASR requirement to the new 2020 values

• Attachment K: Event Analysis Program – streamlined this section and made updates to more closely align to current practice. Changed “investigation” to “analysis” throughout.
• Section 2.3.1 Advanced Notice Emergency Procedures: Alerts – Minor modification to Voltage Reduction Summary Table for PSEG to include updated load reduction estimate from voltage reduction

• Definitions and Applicability
• Generating Facility defined for use in M-14D – removed reference to OATT
• Section 7.1.1 – Generator Real Power Control
• Added guidance for frequency ride-through for DER
• Applied the term Generating Facility where appropriate

• Section 2.2: Modified to include tendering a WMPA within 90 days of receipt of a non-FERC jurisdictional Attachment Y that has no identified Transmission System Impacts.

• Periodic Review.
• Section 1.1: Updated TOP distinction.
• Section 1.7: Updated PJM Procedure to Review Remedial Action Schemes/Special Protection Systems (RAS/SPS) to remove mention of Special Protection Systems (SPS).
• Section 3.2: Updated voltage drop reference as a percentage of pre kV by removing reference to nominal voltage.
• Section 3.5.3: Updated EHV capacitors in auto mode.
• Section 3.7 – Added additional lines to Dominion area for High Voltage Control.
• Section 4.2.12: Removed Nuclear Generating Station’s Circuit Breaker listing table.
• Section 4.3.2: Updated language in Real-Time Switching notification procedure to better align with dispatch switching practices.
• Section 5: Updated the RTO Recognition of Automatic Sectionalizing Schemes procedure.
• Section 5: Updated Dresden NPIR voltage limits and removed EMS bus node names.
• Section 5: Removed TMI NPIR limits due to unit retirement.
• Section 5: Updated Bi-Directional Ratings for AE.
• Section 5: Updated Bi-Directional Ratings for DPL.
• Section 5: Removed reference to Darwin in the header of the AEP Rockport procedure.
• Section 5: Updated AEP Tidd 138 KV switchyard operating guideline for Overduty Circuit Breakers.
• Section 5: Moved Dayton Darby procedure to AEP.
• Section 5: Updated AEP Cook Plant stability procedure.
• Section 5: Added Jacksons Ferry SVC procedure to AEP.
• Section 5: Added description of conditions for the 2345 circuit for the BGE 230 kV Harbor Crossing Cables procedure.
• Section 5: Updated ComEd Burnham – Taylor 345 kV Line Operation (SPOG 3-6).
• Section 5: Updated ComEd Transformer Operations at 138 kV Line Tie Breaker Substations (SPOG 4-30).
• Section 5: Updated ComEd SPOG 2-2-B Marengo procedure.
• Section 5: Updated ComEd SPOG 2-2-C Damen procedure.
• Section 5: Added ComEd Prospect Heights SVC procedure (SPOG 2-45).
• Section 5: Removed ComEd Itasca 138 kV N.O. Bus Tie 2-3 CB SPOG 2-37.
• Section 5: Removed ComEd Quad Cities/Cordova RAS/SPS procedure due to retirement.
• Section 5: Updated DOM Bath County Stability restriction for Valley-Dooms 500kV.
• Section 5: Updated Circuit Breaker name for Gordonsville Bus Tie under South Anna and Louisa CT Islanding Scheme.
• Section 5: Updated Glebe-VirginiaHills-Ox line reference from 2159A to 248 and added line #294 for parallel Braddock-Annandale in the Northern Virginia High Voltage Control procedure.
• Section 5: Removed Lexington Area Loss-of-Load Contingency Mitigation Procedure due to additional Dooms-Lexington 2168 line.
• Section 5: Removed PPL Martins Creek Overdutied breaker procedure.
• Section 5: Added new PPL Wescosville 500/138 kV T3 Transformer Switching procedure.
• Section 5: Updated the UGI/PPL 66 kV Tie Line Operation procedure.
• Section 5: Updated FE EAST Conemaugh/Hunterstown/Fairview Stability Limits procedure.
• Section 5: Updated FE EAST Homer City #2 & #3 Stability Trip (RAS) unit output arming criteria.
• Section 5: Updated FE EAST Homer City Stability Limits single outage damping restrictions.
• Section 5: Updated FE EAST Seneca Stability procedure.
• Section 5: Updated FE EAST Seneca Pumping Notification Procedure (title only).
• Attachment A: Removed the Quad Cities Unit Stability Trip Scheme.
• Attachment A: Removed the Cordova /Quad Cities Multi-Line-Outage Unit Trip Scheme.
• Attachment A: Updated North Hampton RAS description based on future retirement.
• Attachment B: Replaced cause type from ‘New Construction’ to ‘Construction: New Equipment’ to align with eDART.

• Conforming revisions for FERC Order ER19-2417 issued on September 16, 2019 that (1) enable Capacity Market Sellers to request removal of the Generation Capacity Resource Status and (2) require Capacity Market Sellers seeking an exception to the RPM must offer requirement on the basis that an existing Generation Capacity Resource is physically unable to satisfy the requirements of Capacity Performance (CP) to include a documented plan to become capable of participating in RPM.
• Updated RPM Auction Timeline to include activities associated with removal of a resource from Capacity Resource status (Section 5.2)
• Included the requirement to submit a documented plan showing steps that intend to pursue for a resource to become physically capable of satisfying the requirements of a CP Resource, and provide periodic updates on progress of such plan, effective with must-offer exception requests for the 2023/2024 Delivery Year (Section 5.4.1)
• Added new section “Removal of Generation Capacity Resource Status” to document the process to voluntarily request removal of a Capacity Resource from Generation Capacity Resource status (Section 5.4.7)
• Clarification updates to RPM must-offer exception process:
• Clarified that timing is an acceptable reason for must-offer exception request (Section 5.4.1)
• Clarified that sellers may specify multiple auctions in a written must-offer exception request (Section 5.4.1)
• Added that a pending request to PJM for removal of Generation Capacity Resource status is an acceptable reason for early replacement (Section 8.8)

• Periodic Review updated to address:
  • Section 3: Load forecast model details are being removed from the Manual in favor of an annual whitepaper documenting the details of the load forecast.
  • Section 4: The weather normalization procedure for peak load and energy is revised to be directly tied to the load forecast model.

Periodic Review:

• Overall: Corrected all references to Pseudo-Ties to align with Tariff reference.
• Section 1.2: Formatting changes; generator data descriptions removed; outdated procedure removed.
• Section 1.5: Overall description of PJM’s use of ‘three concentric model’ revised and updated.
• Exhibit 1: Replaced with updated version; layers renamed for clarity.
• Section 1.6: Formatting changes; updates made to text to reflect current procedures. New note added to specify PJM timelines for TOs to provide telemetry and, for members with ICCP connection, a full SCADA file (text moved from 3.5).
• Section 1.7: The words ‘Real-Time’ removed from title (now reads: PJM’s Operations Transient Stability Model); section updated to reflect current procedures.
• Section 2: Opening paragraph revised to reflect updated content. Entire section redesigned to reflect PJM’s overall modeling philosophy. New sections added:
  • 2.2.1 Internal World Modeling Philosophy (BES Facility Modeling, Sub-transmission Modeling)
  • 2.2.2 Sub-transmission Modeling Criterion and Responsibilities
  • 2.2.3 PJM External World Modeling (External World Modeling, Model Exchange and Extraction, Pseudo Tie Modeling, Pseudo Tie Eligibility, Pseudo Tie EMS Modeling)
  • 2.2.4 Naming and Modeling Standards
  • 2.2.5 Unique Device Consideration in the PJM Model.
  • Exhibit 10: Updated screen shot added for Sample TO Facilities List
• Section 2.2.3.1: Removed criteria to the extent of external BES equipment to be considered for modeling.
• Section 3.2: The following content is moved from Section 4.9 to Section 3.2:
  • Prepare Initial BES Data to Denote BES Elements of the System
  • TO and PJM Staff Responsibilities:
    • TO Staff Responsibilities – To Address BES Definitions
    • PJM Staff Responsibilities – To Address Revised BES Definitions
    • PJM Staff Responsibilities – Ongoing Sub-transmission Modeling Considerations
• Section 3.4: Text revised to reflect updated procedures when changing transformers and shunts.
• Section 3.5: Section removed; content moved to new Section 2.2.4 Naming and Modeling Standards
• Section 4.3: Exhibit 6: One-line Diagram Symbols updated with clearer version (no change to content)
• Section 4.8: DMS section updated to remove stipulation of SOS appointment of DMS members (per revised DMS Charter); requirements for access to DMS SharePoint added (active, signed NDA on file in eDART); content streamlined.
• Section 4.9: Section removed; topics relocated to Sections 2.2, Section 3.2, and (new) Appendix G (Examples of EMS Sub-transmission Modeling).
• Section 5: Section updated, reorganized, and consolidated to reflect updated processes and procedures
• Section 5.1: Formatting and updates made to content
• Section 5.2: Text moved, updated, or deleted to reflect current procedures
• Section 5.3:
  • Heading changed from ‘New EMS Models Validation and Benchmarking’ to ‘Realtime Contingency Analysis (RTCA) and Solution Quality’
  • Text addressing PJM’s Security Analysis (SA) Program and RTCA Data Quality moved from Section 5.5
• Section 5.4:
  • Title changed from ‘Real-time Contingency Analysis (RTCA)’ to ‘New EMS Models Validation and Benchmarking’
  • Added text addressing changes to PJM EMS and ‘soak test’ prior to moving changes to production (moved from Section 5.3)
  • Added bullet list of criteria and note addressing readiness for installing new model added (moved from Section 5.3)
• Section 5.5:
  • Text realigned to Section 5.3 (at section addressing PJM’s Security Analysis (SA) Program and RTCA Data Quality)
  • Section removed
• Appendix F: New entry added for DER: Distributed Energy Resources
• Appendix G: New appendix added for Examples of EMS Sub-transmission Modeling

• Conforming revision for FERC Order 841: Electric Storage participation (ER19-462) in Section 7.4 to address Energy Storage Resources not being allocated a Peak Load Contribution.

• Section 3.2:
• Updated Small Generation Plant Dispatchers to Small Generation Resource Dispatchers
• Added lower MW threshold for training requirements to accommodate ESR as well as Small Gen Resources
• Updated Energy Storage Device to Energy Storage Resource
• Updated language for training requirements for ESR operators

Updates for compliance with FERC Order 841, Electric Storage Participation in Markets Operated by RTOs and ISOs, Docket No. RM 16-23-000

• Section 13.1 – Note that Direct Charging Energy is not Station Power and end-use charging for an electric vehicle is end-use load.
• Added Section 22 – Energy Storage Resource Charging Energy
• Section 22.1 provides an overview of Energy Storage Resource Charging Energy
• Section 22.2 describes the various charges related to Direct Charging Energy
• Section 22.3 describes charges for Load Serving Charging Energy
• Section 22.4 provides various methods to differentiate Direct Charging Energy from Load Serving Charging Energy for an Energy Storage Resource
• Section 22.5 describes monthly reconciliation for Direct Charging Energy and Load Serving Charging Energy

Updates for compliance with FERC Order 841, Electric Storage Participation in Markets Operated by RTOs and ISOs, Docket No. RM 16-23-000

• Added new Section 8: Energy Storage Resource Charging Energy
• Section 8.1: Describe different categories of Energy Storage Resource charging energy
• Section 8.2: List billing items that apply to Non-Dispatched Charging Energy
• Section 8.3: Description of billing treatment for Load Serving Charging Energy
• Section 8.4: Treatment of Network Service Peak Load and Obligation Peak Load/Peak Load Contribution for Direct Charging Energy

• FERC Order 841 Energy Storage Resources changes:
• Section 11 – Batteries and Flywheels
• Equation clarified in Section 7.3
• Changes were approved by PJM Board on December 4, 2019

• Periodic Review
• Throughout
• Replaced references to Client Manager with Member Relations where applicable
• Corrected typos and capitalized terms where appropriate
• About this Manual
• Added subsection covering “Definitions and Applicability”
• Section 1.2 - Generator Commercial Naming Convention
• Replaced Performance Compliance with Operations Analysis and Compliance
• Section 3.2.4 - Control Center Staffing Requirements
• Remove reference to Section 6 as it relates to training and certification requirements
• Section 4.1.7 – SCADA—Supervisory Control and Data Acquisition
• Corrected typo in heading in Exhibit 6
• Updated Exhibit 6 to include State of Charge for Energy Storage Resources
• Section 4.2.3 – Metering for Individual Generators
• Added metering requirement specific to Energy Storage Resources
• Section 6.2.2 – PJM Transmission Owner (TO) Operator and Generation Dispatcher Certification
• Corrected typo
• Section 7.1.5 – Generator Operations Under Emergency Conditions
• Corrected typo in Exhibit 9
• Section 7.3 – Critical Information and Reporting Requirements
• Added Energy Storage Resource outage reporting requirements
• Section 7.3.5 – Fuel and Emissions Reporting
• Replaced references to Supplementary Status Report (SSR) with references to Resource Limitations page in Markets Gateway.
• Section 10.2.3 – Implications for Terminating Black Start Units
• Updated to cross reference correct section – Section 9
• Attachment D: PJM Generating Unit Reactive Capability Curve Specification and Reporting Procedures
• Updated to include Energy Storage Resources
• Corrected references to Exhibit 15
• Updated stand-alone document containing D-curve examples
• Attachment E: PJM Generator, Energy Storage and Synchronous Condenser Reactive Capability Testing
• Updated to include Energy Storage Resources

• Updates for FERC Order 814 Electric Storage Resource Participation Model
• Added Section 2.3.4B Energy Storage Resource (ESR) Participation Model and updated Sections 2.3, 3.2, 4.2, 4b.2, 9.1, 11.2 where appropriate

• Update for FERC Order 814 Electric Storage Resource Participation Model
• Attachment A: A.1.2 Minimum Critical Black Start Requirements
  • Updated exception to critical cranking power to include non-hydro energy storage resources

• Attachment C: Plant Specific NPIRs Revision History: NPIR revision update

• Section 5: Deleted Gas-Pipeline Contingency Analysis Procedure

• Section 3.9 Assessing Gas Infrastructure Contingency Impacts on the Electric System - Deleted the step for PJM to direct pre-contingency fuel switching from the ‘note’ and replaced with a request for the generation owner to notify PJM if any fuel risk mitigation activities will voluntarily be taken.

• About this Manual Section – corrected review cycle from one to three years to match approved change and chart.
• Section 2 – Pluralized “Definitions”
• Section 6.2.2 – Added requirement to review work plan prior to assigning work
• Section 6.7
• Added new matrix “New Issue Assignment Guidelines”
• Section 8.6
• Added new section 8.6.1 – “Quick Fix”
• Added new section 8.6.4 – Critical Issue Fast Path (CIFP)
• Renumbered to accommodate two new sections
• 8.6.1 now 8.6.2
• 8.6.2 now 8.6.3
• 8.6.3 now 8.6.5
• 8.6.4 now 8.6.6
• Section 10.2 – Added new “page turn” review of business rules
• Section 10.4 – Added new three day posting and notification process for review of draft tariff language for filing
• Section 11.4
• Added language regarding PJM’s continual review of schedules and prioritization
• Added detailed scheduling standards and best practices
• Added language about ending meetings by the posted end time
• Added language empowering the MC Secretary with meeting prioritization decisions
• Added ability for PJM to hold one “high priority/ time critical topic” meeting day per month.
• Section 13.1 – Added new requirement to review the MC Work Plan at least quarterly, and prior to the approval of a new Issue Charge
• Capitalization of lists in sections: 1; 3; 4, 4.1, 4.2, 4.5; 6.1, 6.2, 6.7, 6.8, 6.12; 7.1, 7.2, 7.3, 7.4, 7.5; 8.2, 8.3, 8.4, 8.5; 10.3; 11.2; 13, 13.3, 13.5; 14.3, 14.4; 15.1, 15.4;
• Punctuation edits in sections: 1; 6.2; 7.3, 7.4; 14.4; 15.4, 15.5
• Exhibit Update:
• Communication Between Parent Committee and Assigned Group
• Three Key Issue Initiating Documents
• Decision Making Methodology
• Decision Making Methodology
• Grammatical edits

• Appendix A
  • Clarified the reporting, netting, and operational requirements for Non-Retail Behind the Meter Generation

• Section 2.3.2 – Real-time Emergency Procedures (Warnings and Actions) - Defined triggers to load Non-Retail Behind the Meter Generators
• Section 5.2 – Transmission Security Emergency Procedures – Defined triggers to load Non-Retail Behind the Meter Generators
• Section 5.2 – Transmission Security Emergency Procedures, Step 2 Emergency Load Reduction Action – Added missing PJM Member Actions
• Section 7.01 –TOP EOO-011 Operating Plan Submission Process – Corrected email address to EOP-001forms@pjm.com

Administrative Change (09/26/2019):

• Removed references to SSR in Attachments B and J

• Document ownership updated from Lisa Morelli to Philip D’Antonio
• Section 3.2.9: Inclusion of process for addressing regulation historic performance scores for an operating day that fail to bridge over into the market clearing system
• Section 4.2.2: Clarifying language on reserve requirement determination for market clearing purposes

• Changes to section 2.6.8 Market Efficiency project reevaluation process

• Updated manual ownership from David Egan to Jason Connell
• Removed language in Manual 14A section 2.3.1: New Service Request deficiency reviews

• Section 5: Deleted Gas-Pipeline Contingency Analysis Procedure

• Section 3.9 Assessing Gas Infrastructure Contingency Impacts on the Electric System - Deleted the step for PJM to direct pre-contingency fuel switching from the ‘note’ and replaced with a request for the generation owner to notify PJM if any fuel risk mitigation activities will voluntarily be taken.

• About this Manual Section – corrected review cycle from one to three years to match approved change and chart.
• Section 2 – Pluralized “Definitions”
• Section 6.2.2 – Added requirement to review work plan prior to assigning work
• Section 6.7
• Added new matrix “New Issue Assignment Guidelines”
• Section 8.6
• Added new section 8.6.1 – “Quick Fix”
• Added new section 8.6.4 – Critical Issue Fast Path (CIFP)
• Renumbered to accommodate two new sections
• 8.6.1 now 8.6.2
• 8.6.2 now 8.6.3
• 8.6.3 now 8.6.5
• 8.6.4 now 8.6.6
• Section 10.2 – Added new “page turn” review of business rules
• Section 10.4 – Added new three day posting and notification process for review of draft tariff language for filing
• Section 11.4
• Added language regarding PJM’s continual review of schedules and prioritization
• Added detailed scheduling standards and best practices
• Added language about ending meetings by the posted end time
• Added language empowering the MC Secretary with meeting prioritization decisions
• Added ability for PJM to hold one “high priority/ time critical topic” meeting day per month.
• Section 13.1 – Added new requirement to review the MC Work Plan at least quarterly, and prior to the approval of a new Issue Charge
• Capitalization of lists in sections: 1; 3; 4, 4.1, 4.2, 4.5; 6.1, 6.2, 6.7, 6.8, 6.12; 7.1, 7.2, 7.3, 7.4, 7.5; 8.2, 8.3, 8.4, 8.5; 10.3; 11.2; 13, 13.3, 13.5; 14.3, 14.4; 15.1, 15.4;
• Punctuation edits in sections: 1; 6.2; 7.3, 7.4; 14.4; 15.4, 15.5
• Exhibit Update:
• Communication Between Parent Committee and Assigned Group
• Three Key Issue Initiating Documents
• Decision Making Methodology
• Decision Making Methodology
• Grammatical edits

Periodic Review updated to address:

• Corrections/Clarifications of Existing Provisions
• Clarify Delivery Year applicability of Limited Resource Constraint, Sub-Annual Resource Constraint, Base Capacity Demand Resource Constraint, and Base Capacity Resource Constraint for FRR Alternative in Sections 2.4.3A, 2.4.3B and 5.3
• Clarify treatment of Qualifying Transmission Upgrade once in service in Section 4.5
• Clarify Behind the Meter Generation provisions in Sections 4.3.3 and 7.3.1
• Correct Non-Performance Charge Rate in Sections 8.4A, 9.1.11 and 11.8.8
• Clarify replacement capacity rules when remaining import capability into an LDA in Section 8.9
• Add Aggregate Resource to list of capacity resources in Sections 4.1, 5.7.1 and Glossary
• Clarify charges applicable to Owner in Authorization to Self-Schedule Capacity in Attachment B
• Deletion of Outdated Provisions
• Capacity Performance Transition IAs in Sections 1.5, 4.6.2, 4.6.6, 5.1, 5.8 and 5.9
• Minimum Annual and Extended Summer Requirements in Sections 2.4.3, 2.4.4, 2.4.5, 3.5, 5.3, 5.7.2, 5.8.5, 5.9, 11.1.3, 11.3 and 11.8
• EE adjustments for 2016/17 – 2018/2019 Delivery Years in Section 2.4.5
• Short-term Resource Procurement Target in Sections 3.3, 3.5, 5.1, 5.4.3, 5.8, 6.1, 7.2.2, 11.1.3 and Glossary
• Demand Response Legacy Direct Load Control Transition Provision in Sections 3.5 and 5.9
• Limited Resource Constraint and Sub-Annual Resource Constraint (when it relates to RPM Auctions) in Sections 3.5, 5.7.2, 5.8.5, and 5.9
• Product types (Limited DR, Extended Summer, and Annual) for RPM Auctions in Sections 4.1, 4.5, 4.6.2, 4.6.7, 4.6.8, 4.8.3, 5.5, 8.2.2, and 8.9
• Out-dated qualification requirements for generation resource prior to 2019/2020 Delivery Year in Section 4.2.3
• Legacy Direct Load Control Programs in Section 4.3.1
• Credit-Limited Offers in Section 4.8.4
• Coupled Sell Offers in Section 5.4
• Peak Season Maintenance Compliance in Sections 8.1, 8.6, 9.1.6, 9.1.8 and 11.8.5
• Load Management Event Compliance in Sections 8.1, 8.7, 9.1.9 and 11.8.6
• Non-Performance Assessment provisions for 2016/2017 – 2017/2018 Delivery Years in Sections 8.4A, 9.1.4 and 9.1.11
• Conforming Revisions for FERC Orders
• OVEC Integration (ER18-459, ER18-460) in Section 2.3.1
• Periodic Review of Variable Requirement Curve Shape and Key Parameters (Quadrennial Review) (ER19-105-001,002) in Sections 3.3 and 3.4
• Energy Efficiency Resources Compliance with Authorized Relevant Electric Retail Regulatory Authority (RERRA) Rules to Opt-Out or Restrict Sales of EE Resources (ER18-870) in Sections 3.5, 4.4 and 5.9
• Minimum Offer Price Rule Remand (ER13-535-005, 006) in Sections 5.2 and 5.4.5
• FERC Order 841: Electric Storage Participation (ER19-462) in Section 5.4.1

• Periodic Review – no changes were identified as part of this review
• Section 2.1 - Generation Outage Reporting Overview
  • Added clarification for outage ticket end date as it relates to deactivation date
• Section 2.5 - Outage Reporting for Facilities Providing PJM Black Start Service
  • Clarified requirement for black start test ticket submission

Revisions as a result of Periodic Review:

• Clarified manual focuses on measurement and verification of both Nominated EE Value and Capacity Performance value of EE Resources (Introduction section)
• Clarified EE Resource may be modeled at sub-zonal LDA level (Sections 1.3 & 3.1.2)
• Clarified EE Resource may be used as a replacement resource for another EE Resource in accordance with Section 8.8 of Manual 18. (Section 5.1.3)
• Added conforming revision for FERC Order ER18-870 to ensure EE Resources are subject to rules in Manual 18 that facilitate the implementation of any restrictions that may be imposed on EE Resources by an Authorized RERRA to opt-out or restrict sales of EE Resources (Section 1.1)
• Added conforming revisions for FERC Order ER17-367 to implement Seasonal Capacity Performance Resources (Summer-Period EE Resources) (Section 1.1)
• Deleted outdated Delivery Year information (Section 1.1, 1.2, & 10.1)
• Replaced RAA Schedule 6 (section M) reference with RAA Schedule 6 (section L) (Section 1.1)
• Replaced eRPM system with Capacity Exchange system (Sections 1.3, 5.1.3, & 5.1.4)

• Added conforming changes to section 8.6 to account for FTR Forfeiture Rule calculation change from month to period

• Conform changes for context and alignment of terms (multiple locations)
• Update links for PJM.com
• Section 1.1, 1.3.4:
• Provide additional clarity as to the process of integrating Supplemental Projects in the RTEP
• Section 1.3:
• Define the applicability of modeling requirements associated with the RTEP
• Section 1.4:
• Update outline numbering
• Conform discussions for Customer Funded Upgrades to the definitions and processes from the Tariff
• Section 1.4.2:
• Clarify how overlapping needs are addressed in the RTEP
• Section 1.4.3:
• Provide information as to the process used for the removal of projects from the RTEP under various conditions

• Section 2.7: Added section to address the need for coordination between the Transmission Owner and the Nuclear Plant Generator Operator regarding Remedial Action Schemes and Under Frequency Load Shedding/Under Voltage Load Shedding schemes and their identification in plant interface agreements.
• Section 3.6: Added section to address the process by which the NPIRs will be discontinued after a nuclear plant deactivates and retires.
• Section 3.7: Added section to address the coordination between Reliability Coordinators when a non-PJM member is identified by an Nuclear Plant Generator Operator as a Transmission Entity.
• Attachment B: Attachment title updated and note section updated
• Attachment C: NPIR revision update
• Periodic Review to address:
  • Three-year Nuclear Generators Owners Users Group (NGOUG) review per Section 3.5
  • Language clarification in Section 1.1

• Section 3.4 – Add process to handle condition when state-estimator loss MWh is unavailable
• Section 5.2.5 – Remove entire section as Quick Start Reserve is obsolete
• Section 5.2.8 – Update to describe Reactive Operating Reserve as being credited hourly
• Section 19.3 - Provide consistency on terms used for Day Ahead Scheduling Reserve settlement
• Correct various typos

• Added specific wording, in section 1.1.6, for combined cycle components and other grouped units that report in aggregate pertaining to the CIR evaluation method in section 1.1.5
• Added specific wording for Combined Cycle units with once through cooling in Section 1.3
• Separated run of river hydro units (with pooling/storage/dispatch capability) from the Capacity Storage Resources category to conform to the changes in the OATT

• Replaced section 6.7 with reference to PJM Tariff, Attachment Q and Credit Overview document
• Changes to 6.8 to reflect replacement of FTR liquidation process with settlement process
• Miscellaneous updates to sections 3.2 and 5.3 to align with OASIS refresh

Manual 14G Updates and Corrections to Links/References

• Section 1.7 Demand Response: Updated Content
• Section 2.4 Site Control:
  • Term for Site Control must be 3 years (2 years for 20 MW or less) commencing on the first day of the New Services Queue in which the Interconnection Customer submits its Generation Interconnection Request.
  • Extensions to site control must have been already exercised by the Developer at the time site control evidence is provided to PJM. (If initial term is less than the required 2 or 3 year term)
• Attachment B-2: System Impact Study Data Form: Stability Models
  • Modified Section on Stability Models to be consistent with PJM requirements to meet the following NERC Standards:
    • MOD 26 – Plant Modeling: Volt/VAR Control
    • MOD 27 – Plant Modeling: Power/Frequency Control
    • MOD 32 – Data for Power System Modeling and Analysis
  • References link to NERC’s Acceptable Models List
• Corrections to References/Links:
  • Sections Section 2, Attachments A, A-1, B, B-2 and C6: Corrected Queue Point Link
  • Section 4.5: Removed reference to PJM Manual
  • Section 5.3: Removed incorrect reference banner for System Impact Studies
  • Section 5.5: Removed incorrect Attachment reference.

Administrative Change (6/27/2019):

• Updated effective date of revision 26 from 6/20/2019 to 6/27/2019 to align posting and effective dates.

Revision 26 (06/27/2019):

• Cover to cover annual review. Changed terminologies and corrected grammar throughout.
• Throughout: Updated NERC standard references from EOP-005-2 and EOP-006-2 to EOP-005-3 and EOP-006-3.
• References Section: Removed TO/EOP-005 mapping link and replaced with TO/TOP Matrix site.
• 3.1.7 and 7.2: Added section description and purpose statements.
• Attachment F: Changed title from Transmission Owner and Black Start Supporting Documentation References to Transmission Owner Special Procedures. Removed language in reference to training record, black start database, and Transmission Owner plan reference to EOP-005-2.
• Attachment G: Added coordination review with neighbors in case of conflicts with a particular restoration plan. Modified distribution list for M-36. Added DOE PORTS to Table 1.
• Attachment H: Updated attachment with new UFLS data.
• Attachment I: Deleted attachment which had specified M-36 Sections corresponding to EOP-005 and EOP-006 Requirements.

Administrative Change (06/10/2019):

*Revision 20 was published with current change information in the Revision History that should have appeared in the Current Revision section.*

Moved misplaced Current Revision information, which mistakenly appeared in Revision History during publishing on January 24 2019, back into the Current Revision section for Revision 20:

• [Removed testing requirements from Sections 4.4, 4.5, 4.6, and 4.7 and consolidated all requirements in a separate Section 4.2.6.
• Changed OJT Instructor to OJT Trainer
• Added footnote 1 defining Master Dispatcher
• Added footnote 2 defining OTS versus DTS
• Added clarifying language throughout Section 4
• Updated Exhibit 4 “Threat Error Management” ]

Revision 20 (01/24/2019):

• Cover to Cover Periodic Review
• Updated co-ownership to Richard Brown
• Section 3: Removed references to legacy training requirements
• Removed testing requirements from Sections 4.4, 4.5, 4.6, and 4.7 and consolidated all requirements in a separate Section 4.2.6.
• Changed OJT Instructor to OJT Trainer
• Added footnote 1 defining Master Dispatcher
• Added footnote 2 defining OTS versus DTS
• Added clarifying language throughout Section 4
• Updated Exhibit 4 “Threat Error Management”

Language to address a credible gas contingency(s) in the calculation for increasing the Day-Ahead Scheduling Reserve Requirement:

• Section 11.2.1 Day-Ahead Scheduling Reserve Market Reserve Requirement

Language added to clarify the reserve market eligibility of resources impacted by a credible gas pipeline contingency(s):

• Section 4.2.1 Synchronized Reserve Market Eligibility
• Section 4b.2.1 Non-Synchronized Reserve Resource Eligibility
• Section 11.2.2 Day-Ahead Scheduling Reserve Market Eligibility

• Cover to cover periodic review. Updated links and terminology throughout.
• Section 3.3: Added NextEra to Voltage Limit table.
• Section 3.9: Added language for TSA real-time monitoring and control for dynamic stability.
• Section 4.2.2: Added on-time criteria for hotline work that may have system impact and a clarification note concerning RTU outages not requiring an eDART ticket.
• Section 5: Updated RTO NPIR Voltage limits for North Anna, Surry, and Peach Bottom. Clarified Susquehanna voltage.
• Section 5: Removed the ComEd Dresden Bus Operation procedure.
• Section 5: Updated the ComEd Powerton Stability procedure.
• Section 5: Updated the ComEd Normally Open Bus Tie procedure.
• Section 5: Removed the ComEd/MISO Pleasant Prairie-Zion Conservative Operation procedure.
• Section 5: Removed the FE West Mansfield Unit 2 Reclosing Restriction.
• Section 5: Updated the FE EAST Hunterstown/Conemaugh stability procedure for the interconnection of the Fairview CC.
• Section 5: Updated the FE East Birdsboro Plant Stability Restriction.
• Section 5: Updated the AEP Rockport operating guide limits.
• Section 5: Removed the AEP Conesville 345 kV plant procedure.
• Section 5: Added new FE East Asylum/Liberty Stability procedure.
• Section 5: Updated the PSEG Artificial Island Stability procedure.
• Section 5: Removed the Dominion North Hampton RAS Procedure.
• Section 5: Updated the Peach Bottom Transformer outage procedure for Muddy Run regulation.
• Section 5: Updated NY/NJ PAR Coordination and NYISO Ramapo Par Operating Instruction for Hudson reconfiguration to Marion.
• Section 5: Updated RTO NY/NJ PAR Coordination General Principles tap change language.
• Attachment A: Updated the Lisle RAS description.

• Gas Contingency Impacts on Reserves
• Section 2.2 Reserve Requirements – Language to address a credible gas contingency(s) in the calculation for increasing the Day-Ahead Scheduling Reserve Requirement
• Section 3.9 Assessing Gas Infrastructure Contingency Impacts on the Electric System – Language added to clarify the reserve market eligibility of resources impacted by a credible gas pipeline contingency(s)
• Cover to cover Periodic Review
• Section 2.2 – Removed reference to SERC BAL-002 reserve policy (retired). Updated RF BAL-002 document link and naming from ‘Requirement’ to ‘Regional Criteria’.
• Section 2.4.7 – Updated M-3 section reference section 3.7
• Section 4.1, 4.3, 4.4, 4.5, 5.1 – Removed of mention of Supplementary Status Report (SSR) where not needed
• Section 4.4.3 – updated link and version number to the new NERC Reliability Guideline: Generating Unit Operations During Complete Loss of Communications – Version 3
• Section 7.1: Revised email address from dispsup@pjm.com to EOP011forms@pjm.com
• Attachments E and F updated with 2019 summer peak data

• Cover to Cover Periodic Review.
• Section 1: Renamed eRPM to Capacity Exchange.
• Section 3.2.4: Corrected references to subsections of Section 3.2.4 within the text.
• Section 3.3.2: Section reviewed for clarity. New table added to define the data quality requirements.
• Section 3.8: Renamed PJM Client Managers to PJM Member Relations.
• Attachment A: Added State of Charge as a required data point to be sent to PJM via SCADA/ICCP for Energy Storage Resources.
• Attachment B: References to EOP-005 and EOP-008 NERC Standards are updated with the new version of these standards.
• Attachment E: New Attachment describing reliability guidelines to mitigate the unplanned loss of EMS Real Time Assessment capabilities. These guidelines were developed by the members of System Operating Subcommittee – Transmission (SOS-T).
• Section 2.3.1 and Section 2.7: Added reference to the new Attachment E for the reliability guidelines to mitigate the unplanned loss of EMS Real Time Assessment capabilities.

• Revised language in Section 1 reflecting the applicable effective date of Manual revisions
• Revised reference in Appendix D to M-14G Attachment C and D, which were previously incorporated in M-14A
• Added technical reference in Appendix D reflecting industry standard updates, including IEEE 1547-2018

• Cover to Cover Periodic Review
• Revise Revision History to update with the correct Revision 7 information
• Removed welcome language at the start of each section for brevity
  • Section 2
  • Section 3
  • Section 4
  • Section 5
  • Section 6
  • Section 7
  • Section 8
  • Section 9
  • Section 10
  • Section 11
  • Section 12
  • Section 13
  • Section 14
  • Section 15
• Section 1: Grammatical edits
• Section 2:
  • removed bullet points from text
  • corrected bullet formatting
  • clarified definition of Standing Committees
  • added definition of Consensus Based Issue Resolution
  • added new definition of Consensus Based Issue Resolution Process
• Section 4.5: Replaced language on identification of speakers at PJM meetings
• Section 5.1:
  • Added content from deleted Section 5.2.
  • Added content from retired Manual 33 regarding five sectors and one primary and three alternate representatives.
  • Added clarifying language on which committees apply
  • Added clarifying language on which committees require a first read
  • Deleted sentence regarding required number of MC-MRC meetings per year.
• Section 5.2:
  • Deleted section: moved content to Section 5.1
  • corrected “table and graphic” to “exhibits” for correct terminology
• Section 5.4.1:
  • Deleted reference to “senior representatives” as irrelevant
• Section 5.5:
  • User Groups content moved into new section 8.6.3
  • Added new section describing “Special Sessions” designation
  • Added new section describing “Special Meetings” designation
• Section 5.6: Renumbered as Section 5.5 to accommodate move
• Section 6: Updated and expanded topic list
• Section 6.1:
  • Added clarifying grammatical edits
  • Updated language to reflect current process.
• Section 6.2:
  • Moved text from Sections 6.2. Issue Identification, Section 6.4 - Charging a New Issue, and Section 6.4.2 here.
  • Updated topic lists for inclusion in Problem/Opportunity Statement, Issue Charge, and Charter.
  • Added clarifying language and updated language to reflect current processes around Problem/Opportunity Statement, Issue Charge, and Charters, and new process
    for requiring a vote to approve only the Issue Charge, rather than the Problem Statement and Issue Charge.
  • Added language regarding updated procedure for review of Charter.
  • Added section heading “Work Plan” including language moved from 6.4.2.
  • Deleted duplicative last bullet on list
  • 6.2.3: Added clarifying language to align with new Charter creation and approval process
  • 6.2.3: Corrected grammar for clarity
  • Deleted Exhibit 4: Issue Creation and Assignment (redundant information)
• Section 6.3:
  • Moved text from Section 6.2 Issue Identification, and old Section 6.3.
  • Deleted Exhibit 4: Issue Creation and Assignment as redundant with other graphics and descriptive text
• Section 6.4:
  • Created new section heading
  • Clarified intent of Problem Statement
  • Moved text from Section 6.2 Issue Identification
• Section 6.5:
  • Created new section heading
  • Deleted sentence covered in more detail elsewhere
  • Moved text from Section 6.2 Issue Identification
• Section 6.6:
  • Created new section heading.
  • Moved text from Section 6.2 Issue Identification.
  • Corrected Problem Statement / Issue Charge reference to reflect new process.
  • Corrected lower to upper case for titles of Chair and Secretary as defined terms
• Section 6.7:
  • Created a new section heading.
  • Added new language clarifying process.
  • Moved text from sections 6.2, 6.4, 6.4.1.
  • Changed note into a regular bullet
  • Deleted OA 8.6.3 language as redundant
  • Deleted “in consultation with members” as inaccurate
• Section 6.8:
  • Created new section heading
  • Moved text from Sections 6.3, 6.4
  • Deleted redundant text
  • Corrected grammar
  • Corrected bullet alignment
• Section 6.9:
  • Created new section heading.
  • Added text from section 6.3
• Section 6.10:
  
  • Created new section heading.
  • Added text from section 6.4.3
  • Edited language around complexity
  • Corrected language to reflect new charging and charter processes
• Section 6.11:
  • Created new section heading.
  • Corrected “member” to “Stakeholder” for accuracy
  • Added text from section 6.4.1
  • Deleted language about reviewing Charge that does not match new process
  • Added fourth item on list regarding inviting technical specialists
• Section 6.12:
  • Created new section heading.
  • Added text from section 6.5. Rewording for clarity.
• Section 7.1:
  • Corrected “chapter” to “section”.
  • Capitalized defined terms.
  • Corrected “chart” to “exhibit”.
• Section 7.1.1: Moved to new section 8.6.1
• Section 7.3:
  • Corrected typo and added clarifying language.
  • Added introduction to exhibits.
• Section 7.4:
  • Clarified practice of recording member participation in final report.
  • Added subject matter expert and Facilitator as eligible representatives to present a stakeholder’s option to the Parent Committee.
• Section 8.2: Deleted extraneous language and added specific section reference.
• Section 8.3: Added clarifying language regarding status quo
• Section 8.4: Clarified voting rule application and a grammatical edit.
• Section 8.5: Deleted footnote definition of 3/2 rule and moved to Section 2: Definitions.
• Section 8.6: New section including content moved from 5.5, 7.1.1, and 15.2.2 along with new content.
• Section 8.6.6: New section on “Final Attempt at a Resolution”
• Section 9.2:
  
  • Changed sentence structure to help readability
  • Added MRC for clarity
  • Added note on proper treatment of a consent agenda item
• Section 9.4: Changed text to bullets for ease of reading
• Section 10.6: Edited date formatting
• Section 11.2:
  • Removed duplicate secretary reference.
  • Added clarifying “business days” to deadline.
• Section 11.5:
  • Added new “Proxy Voting Protocol” section
  • Renumbered “Decision Making” section to 11.6
• Section 11.6: Renamed to “Decision Making” (old section 11.5)
• Section 11.7:
  • Renamed to “Allowing Sufficient Opportunity for Review” (old section 11.6)
  • Clarified wording
• Section 11.8:
  • Renamed to “Antitrust Guidelines” (old section 11.7)
  • Added “or his/her designee” to The President of PJM for duty to assign Chairs to stakeholder groups.
  • Removed duplicate language.
  • Changed text to bullets for ease of reading.
• Section 11.9: Renamed to “Stakeholder Group Chairmanship” (old section 11.8)
• Section 11.10:
  • Renamed to “Committees” (old section 11.9)
  • Moved Vice Chair sector schedule up for more logical flow.
  • Indented order of election bullets.
  • Added language regarding voting by acclamation
• Section 11.11: Renamed to “Elections” (old section 11.10)
• Section 11.12: Renamed to “Speakers” (old section 11.11)
• Section 11.13: Renamed to “Sector Designation Announcement” (old section 11.12)
• Section 11.14:
  • Renamed to “Consultation with Transmission Owners and Members” (old section 11.13)
  • Reworded for clarity
• Section 11.15:
  • Renamed to “Manual Revisions” (old section 11.14)
  • Added clarifying words
• Section 11.16: Renamed to “Chairs Prerogative” (old section 11.15)
• Section 11.17: Renamed to “Consensus Based Issue Resolution Process” (CBIR) Implementation Forum (old section 11.16)
• Section 12.2:
  • Added reference to Voter Designation Form for proxy voting.
  • Added section number for User Group reference
  • Updated language from “ex parte letter” to “Board Communication letter” and adjusted grammar accordingly.
  • Added Liaison Committee to list of communication opportunities
  • Added hyperlink to Board Communication page of PJM website
• Section 13.1: Changed text to bullets for ease of reading.
• Section 13.3:
  • Added Exhibit numbers for ease of reference.
  • Corrected grammatical edits.
  • Deleted text referring to a previous version of the chart.
• Section 13.4: Corrected typo
• Section 15.1:
  • Removed duplicative bullet
  • Updated reference from “Ex Parte Communication” to “Board Communication”
• Section 15.2:
  • Added and re-organized bullets for clarity.
  • Reworded sentences for clarity.
  • Corrected typo and added reference to Appendix.
  • Shifted bullets for better formatting.
• Section 15.2.2:
  • Moved into new section 8.6
  • Updated references from “Ex parte letter” to “Board Communication”
• Section 15.4:
  
  • Changed language from “Ex Parte” Communication to “Board Communication” for clarity and to address negative connotations of “ex parte”.
  • Added hyperlink to Board Communications page on pjm.com
  • Added clarity on communication methodology
  • Edited to update all references of “Ex Parte” to “Board Communication” with proper grammatical context.
• Section 15.5: Updated reference from “ex parte communication” to “board communication”
• Appendix I: Added introductory paragraph. Corrected typo.
• Appendix II:
  • Update hyperlinks for Charter and Work Plan
  • Remove reference to Issue Tracking as this is an internal form
• Appendix III:
  • Removed chart references to “RR” (Robert’s Rules)
  • Standardized formatting of M34 references
  • Added clarifying language on motion to reconsider
• Appendix IV:
  • Changed “electronic whiteboard” to more generic “shared document” to allow for tool choice by facilitator.
  • Changed “surfacing” to “capturing” for better understanding.
  • Removed “Key Pad” term to account for different technology solutions
  • Added options as polling option.
  • Grammatical edit.
• Appendix V:
  • Clarified approval process for Problem Statement and Issue Charge
  • Clarified timing of steps in CBIR process.
  • Deleted language clarifying that this is an example for brevity.
  • Replaced “facilitator’s assistant” with “secretary”.
  • Deleted “electronic whiteboard” and replaced with “interests tab of the matrix” for accuracy.
  • Corrected “cooking” to “baking” for accuracy.
  • Corrected placement of bullets in Sub-Step 2D.
  • Swapped exhibits for Winnowing Options Matrix and Final Options Matrix for correct order.
  • Grammatical edits.
• Appendix VI:
  • Per stakeholder approval votes, revised M14B review schedule from 1 to 2 years.
  • Revised M34 review schedule from 2 to 3 years per Stakeholder Process Forum recommendation
  • Revised M39 review schedule from 1 to 3 years to comply with manual.
  • Added new manuals 14F (2 years) and 14G (3 years)

• FERC VOM Order Docket No. ER19-210-001 conforming changes:
  • Sections 2.3, 2.6, 3.6, 4.6, 5.6, 6.6, 7.6, 9.6
• Revised Exhibit 1: Handy Whitman Index to reflect figures for the year 2019

• Section 1.1 – Proposal Window Type and Duration
• Long-term proposal window start time modified to open in January of odd years

• Cover to cover periodic review
• Added a specific reference in the introduction that this manual augments the RAA Schedule 9
• Addition of Capacity Interconnection Rights and Testing section
• Required testing within defined temperature limits
• Commencing with Delivery Year 2022/2023, simultaneous testing requirements for all Manual 18 defined Capacity Storage and Intermittent Resources (excluding wind and solar)
• Commencing with Delivery Year 2022/2023, PJM required simultaneous multiple generator and full plant testing

• Cover to cover periodic review
  • Updated grammar throughout
  • Updated “About this Manual” section to account for Additional Manual References
  • Reorganized Sections 2.3.2, 2.3.3, 2.3.4, 2.3.6 and 10.2.2 for readability
  • Removed irrelevant data in:
    • Section 1 (Figure 1)
    • Section 1.2.2: Reference to Member Administrative Committee
  • Clarified commitment requirements for Capacity Resource Energy Market Offer rules to align with Tariff (Sections 1, 2.3)
  • Section 2.3.4: Removed CP Transition Year language
  • Section 2.3.4A: Relocated UTC business rules to Section 2.3.2 Market Buyers
  • Section 2.3.10: Clarified process for addressing data input/system failures when calculating LMPs under 5-minute Settlements
  • Section 2.14: Clarified cap to resource offers includes the lesser of a 10% adder or $100. Added missing Delmarva and OVEC zones to Region lists.
  • Section 3.2.7: Clarified use of LOC in Regulation clearing and pricing
  • Section 6: Removed most of section, relocated language to existing sections as appropriate
  • Section 11.2.1: Incorporated previously approved language that was lost due to versioning issue
  • Attachment A: Removed detailed language and provided a reference to OASIS Business Practices Section 2.6

• Attachment J: Updated language for consistency with the new version of NERC EOP-004-4 effective 4/1/2019.

• Periodic cover-to-cover review
• Minor grammatical / formatting changes throughout
• Attachment A “PJM Reliability Plan”: Updated Appendix D: PJM TOs and TOPs to include AMP Transmission, LLC as TO

• Revisions proposed as result of a Cover to Cover Periodic Review
  • Revisions needed to clean-up outdated language and ensure language follows to current processes
  • Minor revisions needed to correct grammar, spelling, punctuation, consistency of terms and document references
• Removed references to Demand Resource Factor due to implementation of Capacity Performance
• Deleted Section 5: DR Reliability Target Analysis Procedures and Section 6: Limited-Availability Resource Constraints Procedures due to implementation of Capacity Performance
• Updated references of ReliabilityFirst’s Standard BAL-502-RFC-02 to ReliabilityFirst’s Standard BAL-502-RFC-03 to reflect new version

• Cover to Cover Periodic Review
• Revision to Section 1A on CEII
• Updated Attachment C
  • Various updates for clarity and alignment with current processes
  • Section C.2
    • Added language that non-radial facilities 345 kV and up will only automatically be considered as CETL limits for an LDA if they have greater than a 2% OTDF
    • Clarified that PJM may choose to include specific non-PJM transmission facilities in the load deliverability test in order to account for significant loop flows
    • Removed sentence that states that Load Deliverability Facility List will be locked down prior to each baseline
    • New procedure added to require both thermal and voltage analysis on both Discrete Outage Case and Mean Dispatch Case
    • Procedure modified to examine mean thermal loadings instead of median thermal loadings

• Section 7.1.1
  •  Added requirements associated with FERC Order 824 – Primary Frequency Response for new ISAs effective 10/1/18.
• Section 7.1.2
  •  Corrected typos
• Section 7.3.1
  • Deleted reference to three working day notification to TO and PJM

• Incorporate Independent Market Monitor Opportunity Cost Calculator methodology

• Updated NSR Eligibility Requirements to require real-time telemetry

• Cover to Cover Periodic Review
• Attachment A: Updated OATF Scope.

• Added Section 2.17 to describe the use of transmission constraint penalty factors in the Day-ahead and Real-time Market Clearing Engines per FERC Order (Docket: ER19-323-000)

• Revise Section 1 and 2 to incorporate references to the Open Access Transmission Tariff, Attachment M-3 process
• Revise Sections 1 and 2 to include improved discussion of workflow and alignment to current processes

• Updated manual owner from Dave Egan to Jason Connell
• Updated Attachment A-1 and B-2 to include latest User Defined Model List for Wind Turbines and Inverter Based Resources

• Cover to Cover Periodic Review
• Updated co-ownership to Richard Brown
• Section 3: Removed references to legacy training requirements

• Conforming change in Section 3.2.7 to specify only resources with a benefits factor of 0.1 or greater may clear in the Regulation Market per FERC Order (Docket: ER19-383-000)

• Updates to Sections 2.7, 2.8, and 2.9.1 to clarify the use of approved RT SCED solution in determination of Shortage Pricing in Locational Pricing Calculator (LPC).

• Section 2.2: Updated the DASR requirement to the new 2019 values.

Administrative Change (06/05/2019):

• Updated ‘About this Manual’ section to reflect PJM Member Relations as the point of contact involved in the transmission service process
• Updated PJM Member Relations contact information within Section 1.1
• Updated PJM Member Relations contact information within Section 1.2
• Updated PJM Member Relations contact information within Section 1.5.1

Revision 14 (04/01/2018):

• Cover to Cover Periodic Review
• Various administrative changes to fix hyperlinks, clarify wording and update point of contact references
• Updates to Section 1.3.2 and throughout Section 3 to reflect replacement of Initial Study with Firm Transmission Feasibility Study within the Long Term Firm Transmission Service evaluation process

• Updated manual ownership from David Egan to Jason Connell
• Cover to Cover Periodic Review
• Manual renamed to “Upgrade and Transmission Interconnection Requests”.
• Updated Section 1 for the overview to be consistent with other manuals in the 14 Series regarding New Services Requests.
• Added a new Exhibit in Section 1.1 describing all manuals in the 14 Series including the new Manual 14G for Generator Interconnection Requests.
• Added new Exhibits in Section 1.3 identifying Customer Classifications including customer types, request type, required attachments for queue entry, and applicable studies and agreements for each request type.
• Added new Section 2 “Queue Point Application Process” to describe the Queue Point tool and to assist the New Services Customer in determining the proper Tariff
  Attachment required depending on the type of request.
• With the addition of new Section 2 for “Queue Point Application Process” moved the previous Sections 2, 3, and 4 to Sections 3, 4, and 5, respectively.
• Corrections to Attachment S references made in old Section 2.1.2 (new Section 3.1.2).
• References to “developer” changed to “New Services Customer”, “Transmission Interconnection Customer”, or “Upgrade Customer” depending on context.

• Distributed Energy Resources (DERS)
  • Section 10.2 – clarified requirements for On-Site Generator used as demand response resource to reduce load and to inject power with appropriate interconnection agreement

• Conforming changes throughout to reflect Day-Ahead Market Closing change from 1030 to 1100
  
  

• Resource Tracker Changes
  • Section 5.3.7, created a new section to provide the Resource Tracker reporting requirements.
  • Section 5.7.2.12, moved the wording of the requirements to 5.3.7 and allowed this section to reference 5.3.7
• Distributed Energy Resources
  • Section 4.2, clarified metering requirements for generator used as demand response resource to reduce load and to inject power with appropriate interconnection agreement

• Biennial Review

• Cover to Cover Periodic Review
• Section 1.1 – Scope & Purpose of Pre-Scheduling
  • Updated Exhibit 1 to correct typos; no change in content
• Replaced reference to Markets Database Dictionary with reference to Manual 11,
  Revision:

• Cover to Cover Periodic Review
• Replaced the term Generator Owner and Generator Operator with Generation Owner throughout to make distinction between PJM and NERC-defined terms
• Grammatical corrections throughout
• Introduction
  • Added reference to PJM Reliability Assurance Agreement (RAA)
• Section 1.1
  • Remove outdated reference to Attachment G
  • Change reference to Resource Adequacy Planning group to Capacity Market
    Operations
• Section 2.1
  • Renamed section to Generation Owner Responsibilities
  • Revised language in entire section for clarity of roles and responsibilities
  • Removed reference to PJM West RAA
  • Removed itemized listing of tasks
• Section 4.1.5 EMS Data Exchange
  • Added data point for Performance Assessment Interval (PAI) Trigger via SCADA, ICCP
    • Section 5.3 Marketing Tools
  • Changed “PJM Marketing Tools” to “PJM Markets and Operations Tools”
• Section 5.7.2.10 PJM Tools
  • Clarified the requirement to update the eDART Contact Survey for all new and transferred units.
• Section 7.1.2
  • New process for voltage schedule issuance and acknowledgement
• Section 7.1.5
  • Added Deploy All Resources to Exhibit 8, for consistency with Manual 13
• Section 7.3 Critical Information and Reporting Requirements
  • Added clarification for situations requiring verbal notification to PJM Dispatch.
• Attachment “B”: New PJMnet Customer Implementation Voice/Data Communications Template
• Replaced references to PJM primary/backup control centers with Jefferson/Milford control centers
• Attachment “E” PJM Generator and Synchronous Condenser Reactive Capability Testing
  • Added reference to Manual 1 regarding telemetry requirements
  • Added clarification on test evaluation for units testing above or below stated limits
• Attachment “M” Wind Unit Dispatchability Check List
  • Added clarification on frequency for updating Eco Max limits
  • Attachment “N” Cold Weather Preparation Guideline and Checklist
  • Updated reference and link to ReliabilityFirst Plant Winterization - Lessons Learned & Best Practices
  • Updated link to NERC Extreme Winter Weather Events - Training Presentation

• Attachment C: Plant Specific NPIRs Revision History: NPIR revision update

• Cover to Cover Periodic Review
• Updated Manual owner to Brian Chmielewski

• Cover to cover periodic review. Corrected typos, updated equipment names, and updated terminology throughout
• Section 1.7: Added external RAS evaluation process.
• Section 2.1.3: Updated note for PCLLRW issuance.
• Section 3.2: Updated language to refer to existing charts for time to control for limit exceedances and added note for PCLLRW issuance.
• Section 3.5.5: Added clarification that PJM will use the Normal High limits for line open-ended condition if the Emergency High voltage limits are not defined by the Transmission Owner
• Section 3.8: Updated Western reactive interface definition.
• Section 3.11: Updated Generator Voltage Schedules procedure to reflect new eDART functionality for defining, communicating, and acknowledging voltage schedules.
• Section 4.2.12 and Section 5: Removed references to Oyster Creek nuclear plant due to retirement.
• Section 4.5: Updated the Outage Acceleration process.
• Section 5: Removed RTO procedure listing/table
• Section 5: Removed BGE/PEPCO/Doubs/Northern Virginia (NOVA) operating procedure
• Section 5: Added AE Cardiff/Cedar/Dennis SVC procedure.
• Section 5: Removed ComEd Mazon-Crescent Ridge 7713 line directional ratings procedure.
• Section 5: Added new AEP Cook Stability Restriction procedure.
• Section 5: Updated AEP Rockport Operating Guide.
• Section 5 and Attachment A: Removed DOM Carolina 54 RAS procedure due to retirement.
• Section 5: Updated DOM Bath County Stability Restrictions procedure.
• Section 5: Updated Dom Brunswick/Greensville Stability Restrictions procedure.
• Section 5: Added new DEOK switching procedure.
• Section 5: Added new FE East Birdsboro Stability Restriction procedure.
• Section 5: Updated FE East Conemaugh/Hunterstown stability procedure.
• Section 5: Updated FE East Keystone-Conemaugh re-closing procedure.
• Section 5: Updated CB names for PPL Martins Creek Overdutied Breakers procedure.
• Section 5: Updated ComEd Wolfs Crossing procedure.
• Section 5: Updated ComEd Transformer Operations at 138 kV Line Tie Breaker Substation procedure.
• Section 5: Updated DLCO Arsenal-Brunot Island 345 kV common trench cable ratings.
• Section 5 and Attachment A: Removed ComEd Davis Creek SPS/RAS procedure.
• Section 5 and Attachment A: Removed ComEd University Park SPS/RAS procedure.
• Section 5 and Attachment A: Removed BGE Mt. Washington RAS procedure.
• Attachment E: Moved table to OASIS.

• Biennial Cover to Cover Review 
  • Section 2.2
    • Replace “eRPM” with “Capacity Exchange
  • Section 5.2
    • Remove specific TOs as being network customers
    • Remove ComEd from RTO Startup Recovery Charges
  • Section 5.3
    •  Remove specific TOs as being network customers
  • Section 6.3
    • Provided clarification on AEP and Dominion point-to-point transmission service credits
  • Section 8
    • Marked Expansion Cost Recovery Accounting Overview as deleted since these charges and credits are no longer applicable

• Cover to Cover Periodic Review
• Section 3.2 added “Production System Freeze Change” to Conservative Ops
• Section 3.3 corrected formatting for Day-Ahead commitment instructions
• Section 3.4 Added reference to M-11 regarding PLS schedules
• New Section 3.5 added for “Long Duration Extreme Weather”
  • Old Sections 3.5, 3.6, 3.7, and 3.8 renumbered accordingly
  • Section 3.6 added language for disabling auto-reclose
• Section 4.1 deleted Exhibit 4 table
  • Former Exhibits 5 through 14 re-numbered accordingly
  • Former Exhibit 4 content regarding “Elevated Threat Alert” reformatted in section 4.1 as a list of “PJM Actions” and “PJM Member Actions”
  • Former Exhibit 4 content regarding “Imminent Threat Alerts”, “Intelligence of an impending attack on a PJM facility”, “physical attack at multiple sites”, or “Significant terrorist activity beyond the East Coast” moved to section 4.3 as a list of “PJM Actions” and “PJM Member Actions”
  • Former Exhibit 4 content regarding “Cyber event has shut down control center EMS capability” moved to section 4.4 as a list of “PJM Actions” and “PJM Member Actions”
• Section 4.2: Added language to outline communication between PJM, its members, and the E-ISAC with regards to potential cyber or physical attacks
• New section 4.3 for PJM operational procedure for physical threats
  • Created from former Exhibit 4 content regarding “Imminent Threat Alerts”, “Intelligence of an impending attack on a PJM facility”, “physical attack at multiple sites”, or “Significant terrorist activity beyond the East Coast” as a list of “PJM Actions” and “PJM Member Actions”
  • Updated “Operating Reserves” language to “30-Minute Reserves”
  • Added requirement for PJM to alert PJM’s Operations Emergency Response Team
    (OERT)
• New section 4.4 for PJM operational procedure for cyber threats against PJM
  • New section 4.4.1 for loss or degradation of ICCP or EMS capabilities
    • Created from former Exhibit 4 content regarding “Imminent Threat Alerts”, “Intelligence of an impending attack on a PJM facility”, “physical attack at multiple sites”, or “Significant terrorist activity beyond the East Coast” as a list of “PJM Actions” and “PJM Member Actions”
    • Updated “Operating Reserves” language to “30-Minute Reserves”
    • Added language to initiate “Manual Dispatch
  • New section 4.4.2 for loss of internet operational procedures
  • New section 4.4.3 for loss of all telecommunications operational procedure
• New section 4.5 for PJM operational procedure for cyber threats against member company
• New section 4.6 for PJM operational procedure for High-Altitude Electromagnetic Pulse
• Section 5.4 General language clarifications and modifications for consistent use and spelling of terms
• Section 5.4.1 language clarifications based on internal Root Cause Analysis recommendations
• Section 6.4 added language to adjust “Resource Limited Unit” reporting time-frame and minimum run time requirements to place additional Fuel Limited Resources into the Maximum Emergency Category during long duration extreme weather events. Aligns with new section 3.5 requirements.
• Annual updates to Attachments E, F, and N

• The following changes were made to implement the solution package of the Summer- Only Demand Response Senior Task Force:
  • Section 3: Revisions to the load forecast development process to explicitly recognize approved summer-only peak shaving programs.
  • Attachment D (new): Creates the rules and timelines related to Peak Shaving Adjustment Plans.
  • Attachment E (new): A template for the Peak Shaving Officer Certification Form

• Section 3.1: Added Transmission Constraint Penalty Factor

• Modified Section 5.2.1 for consistency with PJM OATT
• Added Section 21 to describe settlements related to Pseudo Tie Overlapping Congestion
• Modified Section 8.4.5 to include the Real-time Pseudo Tie Balancing Congestion refund as a component of the Total Balancing Congestion Charges

• Section 2.3.3: define business rules to allow Price-based offers to exceed $1,000/MWh
• Section 2.3.4A: define business rules for Day-ahead Pseudo-Tie Transactions
  
  

• Section 3.2.1: Clarity added concerning extent of external BES facilities considered for
  modeling.
• Section 3.2.1.1: Removed non-official standard
  Revision:

• Section 1.6: Revised language to explain what Markets Gateway tool is used for instead of a detailed overview of PJM Markets which is covered in Manual 11
• Section 2.3.1: Changes related to TOP-001 R13 and TO/TOP Matrix regarding Real-time Assessment capability requirements
• Section 2.7: NERC Standard references to TOP-001 R1, R12, R14 and TOP-003 R1, R3, R5 updated
• Section 3.2:
  • Added missing information about DNP3 communication protocol and Jetstream system, and revised the section for clarity
  • Added new requirement regarding ICCP data definition files
• Section 3.3: Revised language for clarity and alignment with PJM Manual M14D
• Section 4.1: Per COM-001, added Distribution Providers to the list of entities PJM has voice communications with
• Section 4.2: Per COM-001, added Alternate Interpersonal Communication requirement for Transmission Owners
• Section 4.5.3: New language to define what qualifies as Emergency in accordance with COM-002
• Section 4.5.4: Added language covering the verification steps taken by PJM and TO operators prior to taking actions to control thermal and voltage constraints
• Attachment A:
  • Table A: Removed the references to the data submission timeline requirements for Generation scheduling
  • Table B: Added PAI Trigger via SCADA/ICCP as an optional service for generating entities
  • Table B and D: Updated communication requirements for Protection System outages in accordance with NERC Standard PRC-001 and TOP-003
• Attachment B: Reworded EOP-008-1 R5 to ensure TOs are submitting the right evidence
• Changed references to Local Control Center (LCC) to Transmission Owner Control Center
• Updated Manual owner to Jeff Schmitt

• Section 2.1 – Pre-Qualification Process
  • Process updated to include a three year data confirmation
• Section 5.3 – Proposal Window Violation Inclusion Review Process
  • FERC acceptance of the substation equipment and Transmission Owner Form 715 exemptions
• Section 6.1 – Proposal Requirements
  • Updated to include the new project proposal template
  •  Includes cost containment information
• Section 6.2 – Proposal Timelines
  • Removed with relevant information now captured under section 6.1
• Section 6.3 – Redaction Requirements
  • Updated to include the new project proposal template
• Section 6.6 - Proposal Window Communications
  • Changed to incorporate Planning Community
• Section 6.7 – Market Efficiency Proposal Requirements
  • Removed with relevant information now captured under section 6.1
• Section 8.1 – Reliability Criteria Project Evaluation
  • Added the end-of-RTEP comparative summary
  • Includes cost containment evaluation information
• General clean-up of numbering issues and spelling errors

• Appendix A: Added new sub-section for Transmission Owner Behind the Meter Generation Reporting and Communication Process

• Section 2.3: Updated to clarify that TO may coordinate with Behind the Meter Generation to help on a voluntary basis with grid emergency.
• Section 5.4: Updated to clarify that TO may coordinate with Behind the Meter Generation to help on a voluntary basis with grid emergency. Also, PJM will include TO verified Behind the Meter Generation in PCLLRW tool or other as applicable
• Section 5.7: Updated to clarify that TO may coordinate with Behind the Meter Generation to help on a voluntary basis with grid emergency.
  
  

• Section 1.2.1: Reference to Manual 14D added for Behind the Meter Generation reporting and communication
  
  

• Updated Section 2.6.5 to include RTEP+15 b/c cap and for benefits adjustments due to in-service year later than RTEP. Also added language to note fixed generation and transmission topology for each simulation year.

• Updated manual ownership from Mark Sims to Aaron Berner
• Section 8.2.1 - Added clarifying language
  • Proposals must address a PJM Identified congestion driver
• Added new section 8.2.1.1 – Eligible Congestion Drivers
• Moved to new section 8.2.1.2 – Congestion Mitigation
• Section 8.2.1.3 – Clarified language regarding Benefit/Cost (B/C)

This document is the thirteenth revision of the PJM Manual for Generation and Transmission
Interconnection Facility Construction (M-14C). There are many editorial changes throughout
this revision that reflect the current PJM organizational structure and OATT agreement naming
conventions. The following is a summary of other significant content revisions in the document
that reflect current PJM OATT provisions and PJM procedures:

• Approval
  • Updated ownership from Suzanne Glatz to Mark Sims
• Section 1
  • Revised the Security section to clarify when Security can be called upon
  • Removed reference to ICSA from the WMPA section
• Section 2
  • Removed reference of an ICSA executed with a WMPA
  • Updated the key responsibilities of the project team to clarify what group has the task to setup eDART accounts
• Section 3
  • Removed cost tracking responsibilities from the Interconnection Customer
  • Clarified the process of making a cost change in Quarter Billing section
  • Clarified that there are not cases where the scope change process can be used to change fuel type
  • Added that the Transmission Owner’s refusal to acknowledge a scope change will not preclude implementation of a change PJM finds appropriate
  • Modified the timing when the Interconnection Customer is required to provide a test energy schedule
  • Removed sections 3.8.6 and 3.8.7
  • Revised the generator as-built data requirement
• Section 4
  • Revised the Application of Interconnection Requirement per changes to the PJM OATT
• Cover to Cover Periodic Review

New Manual 14G is a division out of Manual 14A. Manual 14A, Revision 23 was separated into two manuals:

• Updated Manual 14A: New Services Requests Study Process
  • Maintained general application procedures, study process and agreements tendered for any New Services Customer type in the updated Manual 14A.
  • Added new Section 1 Overview
• New Manual 14G: Generation Interconnection Requests
  • Moved requirements specific to generator interconnection requests to this new manual
  • Added new Section 1 Overview
  • Added new Section 3 for Reports and Agreements
  • Added new Section 6 for Large Generation Interconnection RequestsMoved generator-specific Attachments from M14A to new M14G
    Revision:

• Cover-to-Cover Periodic Review
• References to Exhibit numbers updated throughout document.
• Section 1.6: Sentence added to note applicability of technical requirements to PJM TOP facilities and facilities outside the PJM TOP area.
• Section 1.6: Reference to Manual 1, Section 3.8.1 added for specifics on coordination efforts and allowable timeframes for ICCP planned outages.
• Section 2.2: New section added for Flow Circuit Breakers outlining description and change instructions.
• Section 2.2: Note modified to reference Manual 1, Control Center and Data Exchange Requirements.
• Section 2.4: Updated steps added to access Transmission Facilities page on pjm.com.
• Section 2.4: Exhibit 2: Updated screenshot from new location of Transmission Facilities pages on pjm.com.
• Section 2.4.3: Section updated to reflect current process steps.
• Section 3.2: New section for Phased Projects added, with accompanying Note providing an example.
• Section 5: Reference to Contingency Analysis (CA) changed to Real-Time Contingency Analysis (RTCA) to identify function by NERC naming convention and Security Analysis (SA) to represent PJM tool used to run contingency analysis.
• Appendix C: Outlined outage reporting requirements on a per priority basis and referenced Manual 03 for latest details.

• Divided Manual 14A Version 23 into two manuals:
  • Updated Manual 14A: New Services Requests Study Process
    • Maintained general application procedures, study process and agreement tendered for any New Services Customer type in the updated Manual 14A.
    • Added new Section 1 Overview
  • New Manual 14G: Generation Interconnection Requests
    • Moved requirements specific to generator interconnection requests from M14A to this new manual.
    • Added new Section 1 Overview
    • Added new Section 3 for Reports and Agreements
    • Added new Section 6 for Large Generation Interconnection Requests
    • Moved generator-specific Attachments from M14A to new M14G
• Corrected System Impact Study Cost Table: (Located in new M14A, Section 4.3
• Updated queue window periods considering the completion of the “transitional queue” (Located in new M14A, Section 2.2)
• Updated language to more specifically define the conditions under which an accelerated analysis is not possible (Located in new M14G, Section 5.4)

• Updates to Section 2.3.3 and Attachment D to align price-based offer cap with Tariff/OA language

• Attachment C: Plant Specific NPIRs Revision History: NPIR revision update

• Modified Section 8.4.4 to account for shift in excess congestion credits from FTR Holders to ARR Holders

• Updates to Section 4.2.1 to add language to address the synchronized reserve maximum in order to increase the accuracy of Tier 1 estimation

• Revised Section 3.3 to reflect new methodology for developing the winter peak week’s capacity model.

• Added Section 2.2: Transfers of a Generation Facility and Name Changes of Generation Owners and Interconnection Customers
  • Section 2.2.1 – describes guidance, expectations and required information associated with a generation transfer from the generator owner
  • Section 2.2.2 – describes the process that must occur to disclose that a generator or Interconnection Customer has changed its name
  • Section 2.2.3 – links Section 2.2 with the actual generation transfer process described in Section 5.7
• Added Section 5.7.1 to describe the overall method that a Member must initiate a request for a generation transfer
• Added Section 5.7.2 to provide a general overview of the various type of information needed to effectuate a generation transfer
• Added Section 5.7.3 to provide guidance surrounding various timeframes and deadlines that may occur during a generation transfer

• Conforming change in Section 2.3.2 and Section 2.3.3 regarding Virtual Bidding Locations as per FERC order (Docket Nos. ER18-88-000, ER18-88-001).
• Updates to sections 2.3.7, 9.1, 9.1.1, 10.3 to increase flexibility for resource offer submission to PJM systems.
• Renamed Section 9.1 – Hourly Scheduling Adjustments to Section 9.2 – Self-Schedule Adjustments

• Administrative Change: Section 5: The changes to the NPIR voltage limits for North Anna and Surry plants were reverted back to their prior limits due to further review.
• Cover to cover periodic review. Corrected grammar and formatting throughout.
• Section 1.7: Updated the RAS Committee review procedure.
• Section 2.1: Updated Note 3 for Thermal Limit corrective action.
• Section 3.3: Added OVEC voltage limits.
• Section 3.8: Updated the Eastern Interface and Cleveland Interface definitions.
• Section 3.12: Updated Note concerning RRC submittal via ICCP.
• Section 5: Updated North Anna, Surry, and Limerick NPIR voltage limits.
• Section 5: Updated ComEd SPOG 2-22 procedure.
• Section 5: Added retirement dates for the ComEd Davis Creek and University Park North schemes.
• Section 5: Updated the ComEd Dresden Bus tie procedure.
• Section 5: Added new section for OVEC without any special operating procedures.
• Section 5: Updated the FE-East West Wharton SVC procedure.
• Section 5: Updated FE-East Homer City procedure.
• Section 5: Updated FE-East Seneca stability procedure.
• Section 5: Updated the FE-East Conemaugh/Hunterstown stability procedure.
• Section 5: Updated FE-South Belmont RAS procedure.
• Section 5: Updated the AEP Cook Unit Isolation procedure.
• Section 5: Updated the AEP Gavin-Rolling Hills procedure.
• Section 5: Updated the AEP Rockport procedure.
• Section 5: Updated the AEP Additional Regional procedure.
• Section 5: Added DLCO new common trench rating for 302, 307, and Z-45 circuits.
•  Section 5: Updated AE Directional Rating.
• Section 5: Removed the PSEG Bergen Overdutied Breakers procedure.
• Section 5: Updated the PECO Peach Bottom #1 Transformer RAS procedure.
• Section 5: Added new PPL Martins Creek Overdutied Breakers procedure.
• Section 5: Updated PPL NEPA Stability procedure for new plants in the area.
• Section 5: Added new Dominion Brunswick/Greensville stability procedure.
• Section 5: Added new Dominion Chesapeake, Fentress, Landstown and Lynnhaven STATCOM’s procedure.
• Attachment A: Updated RAS descriptions.
• Attachment C: Added note to indicate PJM will notify TO of NPIR voltage changes.
• Attachment E: Added the AEP Huntington-Sorenson 138 kV sectionalizing scheme.
• Attachment E: Added the PPL Frackville #1, #2 and #3 230/69 kV transformer sectionalizing schemes.
• Attachment E: Removed retired schemes and updated other schemes.

• Added conforming changes to section 6.1, 6.3, 9.1 to account for long term FTR modeling changes and monthly BOPP biddable period changes.

• Cover to Cover Annual Periodic Review
• Updated Manual Owner to Rich Brown
• Section 6.1.7 – Added clarifying language for “equivalent frequency control systems”
• Section 7.2.1 Synchronizing Process Phases – added clarification around use of synchro-check relay as recommended by the PJM Relay Subcommittee
• Section 8.1 – System Restoration Plan Guidelines
  • Updated Exhibit 10 Generation Information Template
  • Clarifying this table is required in TO restoration plan as an appendix
  • Clarification around use of synchro-check relay for synchronizing
• Attachment A – Minimum Critical Black Start Requirement
  • Clarification around Note for Critical load units
  • Clarification on dates for Blackstart RFP process
  • Updated fuel storage requirement to 16 hours to match what is in Schedule 6A of OATT
  • Clarifying language around preference for dual fuel capability in Black Start RFP process
• Attachment F – Transmission Owner and Black Start Supporting Documentation References
  • Annual Update
• Attachment G – Coordination of Restoration Plan with PJM Internal and External Neighboring Entities – PJM Approval Process for TO Restoration Plans
  • Clarifying language around updates to Restoration Plans based on “Cut-In” outage tickets
  • Updated OVEC Annual Update date to June 1
• Attachment H – Under Frequency Load Shed (UFLS) Tables
  • Annual Update

• Revised to add additional clarity concerning analyses performed during various stages of project studies
  • Section 2.1 of heading modified
  • Section 2.1.6 revised
  • Section 2.2 of heading modified
  • Section 2.2.2 revised
  • Section 2.3 of heading modified
  • Section 2.3.2 of heading modified
  • Section 2.3.3 of heading modified 
  • Section 2.3.4 revised
  • Section B.3 of Attachment B revised to add clarity

• Section F.2, previously section F.4, completely revised to reflect new eligibility criteria approved by FERC in the External Capacity Filing as well as updated language for Estimates, PJM Deliverables and Withdrawals.
• Section F.3 contains minor changes including removal of feasibility language which was moved to section F.2
• Section F.4, previously section F.2, includes updated PowerMeter submission language.
• Section F.5 contains minor changes to reflect updates made in the previous sections.

• Updated Sections 1A.1 and 11.2 for five minute settlements changes per FERC Compliance Order issued on February 21, 2018
  
  
• Removed the reference to Manual 33 from the Introduction section

• Cover to Cover Periodic Review
• Changed ownership for this manual to Anita Patel, Manager, Knowledge Management Center
• Updated Headers to reflect correct manual name and section names
• Changed references from “PJM Interconnection, L.L.C.” to “PJM”
• Changed references from “Interconnection Agreement” to “Operating Agreement”
• Changed references from “Interconnection Operating Agreement” to “Operating Agreement”
• Changed references from “PJM Participant” to “PJM Member”
• Introduction: added clarity between the dispute resolution procedures covered in the Tariff and this manual and those covered in the Operating Agreement
• Section 1.4: Removed section and introduction and moved language to M34
• Section 2.1: Removed Requirements for Application section and added Membership Types and Requirements
• Section 2.1.1: Removed Data to Be Supplied section and added Types of Membership
• Section 2.1.2: Removed Associate Membership section and added PJM Member/Applicant Requirements
• Section 2.2: Removed Analysis of Submitted Data and added Application and Membership Cost
• Section 2.3: Removed Effective Date, Termination & Withdrawal Process section and added Credit Policy and Credit Requirements with updates
• Section 2.4: Removed Integration of New Applicant and added Name Change Process
• Section 2.5: Removed Application Cost and Membership Cost and added Withdrawal Process
• Section 2.6: Credit Policy and Credit Requirements This section was updated and moved to Section 2.3
• Section 2.6.1: Background This section was removed
• Section 3.1: This section was removed because the information contained is redundant information that is explicitly provided in the Operating Agreement, Reliability Assurance Agreement, or Tariff.
• Section 3.2: This section was removed because the information contained is redundant information that is explicitly provided in the Operating Agreement, Reliability Assurance Agreement, or Tariff.
• Section 3.3: This section was removed because the information contained is redundant information that is explicitly provided in the Operating Agreement, Reliability Assurance Agreement, or Tariff.
• Section 3.4: This section was removed because this information is wholly contained in the PJM Manual for Control Center & Data Exchange Requirements
• Section 3.5: Renumbered to Section 3.1
• Section 4.1: Removed; covered in OA 8.2.1
• Section 4.2: Removed; covered in OA section 1 – Definitions
• Section 4.3: Removed; irrelevant to this document
• Section 4.4: Removed; first two paragraphs moving to M34. Sector challenge covered in OA 8.1.3
• Section 4.5: Removed; covered in OA sections 8.6, 8.6.1, and 8.6.3
• Section 4.6: Removed; covered in OA sections 7.1 and 7.2
• Renumbered Section 5 Dispute Resolution to Section 4

• Section 1.18: Updated to incorporate recent changes to the Tariff to requiring a Feasibility Study for Long Firm Transmission Service Requests
• Administrative Change: Updated Dave Egan’s department from Generation Interconnection to Interconnection Projects Revision:

• Updated Upgrade Customer process for customers making an application under Attachment EE of the Tariff to obtain Incremental Auction Revenue Rights to add the additional study processes require to complete an Upgrade Feasibility Study prior to completing a System Impact Study

This revision includes changes to Section 2.3.3 that were approved at the October 2017 MRC. After further review, this revision contains language that restricts market-based offers to $1,000 and contradicts Operating Agreement Section 1.10.1A (d) that allows market-based offers to be submitted above $1,000 as long as such offer is less than or equal to a verified cost-based offer. Version 95 will be brought for endorsement to the April 2018 MRC meeting to align the language with the OA.

• Updates to sections 2.3.2, 2.3.3, 2.3.6.2, and Attachment D associated with FERC Order No. 831 to implement Offer Verification for Offers > $1,000 effective April 12, 2018.

• Section 2.3.1: New language related to the TO responsibilities per TO/TOP Matrix for TOP-010-1(i) R1, R4
• Section 3.2.3: Added language regarding communication of data quality issues
• Section 5.2: Clarified the definition of Tie Line to include Dynamic Transfers
• Section 5.2.1: Clarified language about telemetry requirements for Tie Lines

• Throughout: Minor grammatical / syntax updates, NERC Standard references shorted to master document
• Section 2.4.1, “the Model Management Department in System Operations” changed to “PJM Operations Engineering Support”, “the Operations Support Division” changed to “PJM Operations Planning”
• Section 2.4.2, “(PJM document ID Cera 534023)” removed in reference to “The Enterprise Change Management Standard”
• Section 3.2, “issuing a Post-Contingency Local Load Relief Procedure (for facilities 230 kV and below) or Manual Load Dump Warning (for facilities 230 kV and above)” changed to “issuing a Post-Contingency Local Load Relief Procedure or Manual Load Dump Warning consistent with PJM Manual M-13: Emergency Operations - Section 5: Transmission Security Emergencies”
• Section 4.1, “with MISO” removed to not implicitly exclude NYISO from market-to-market (M2M) re-dispatch
• Section 4.2, “Native Load curtailment changed to “Native Network Load (NNL)
  curtailment”
• Section 5.2.2, “provide a notification as in 2 above that the situation has been concluded and that no further action is required” changed to “a notification should be provided to the impacted Reliability Coordinators in the same method as the original notification”
• Section 5.3, “PJM Engineering Support” changed to “PJM Operations Engineering Support”
• Attachment A, Updated table of contents format
• Attachment A, Section A, “insuring” changed to “ensuring”
• Attachment A, Section E, “Special Protection Systems (SPS)” changed to “Remedial Action Schemes (RAS)”
• Attachment A, Appendix D, Ohio Valley Electric Corporation added with NERC Registration Number and TO registration and U.S. Department of Energy added with NERC Registration Number and TO/TOP registration

• Added New Section 1.A.1 – Description of Revenue Data for five minute settlements
• Updated Sections 3, 4, 5, 6, 7, 8, 9, 10, 11, 12 and 13 for implementation of five minute settlements

• Conforming revisions throughout to reflect change in Real-time Settlement Interval (5 minute settlements)

• Updated Section 4 for Five Minute Settlements (FERC Order 825) to replace references to “hourly” with “five minute”.

• Updated Sections 2.1.1, 2.1.2 and 2.1.3 for 5-minute settlements to replace “hourly” with “applicable settlement interval”. Also, updated Section 2.1.2 to remove ComEd from the RTO Start-up Cost Recovery credits billing line item and to remove the Expansion Cost Recovery credits billing line item, as both are not applicable.

• New Section 5.6: Quality of Analysis Used in Real-time Assessments

• Conforming revisions for FERC Order ER17-1138, accepted on November 17, 2017 and effective May 9, 2017 to implement enhancements to the rules for external capacity resources

• Cover to Cover Periodic Review
• Various administrative changes to fix hyperlinks, clarify wording and update point of contact references
• Updates to Section 1.3.2 and throughout Section 3 to reflect replacement of Initial Study with Firm Transmission Feasibility Study within the Long Term Firm Transmission Service evaluation process

• Attachment A: revised to add restoration planning data as a type data to be shared with Transmission Owners for generators that are in the TO restoration plan. This change was previously endorsed on 12/22/2017 by Markets and Reliability Committee. Change is now effective following the FERC Order dated February 16, 2018 accepting PJM filing for corresponding Operating Agreement revisions.

• Revised Section 11 Generator Data Confidentiality Procedures to clarify wording and included parameter data to be provided to a Transmission Owner for system restoration planning purposes
  • Revised Exhibit 11 therein
• Revised Attachment J: Generator Data Release Matrix to reflect changes in Section 11
  • Added column for generator parameters
• Revised Sections 10.2, 10.3.2 and 11.1: References to Manual 33 updated

• Cover to cover periodic review
• Attachment A: Updated OATF Scope
• Attachment B: Updated Reliability Analysis Procedure
  
  

• Cover to Cover Periodic Review
• Added clarifying language to the role of the Dispatcher Training Subcommittee (DTS) in the Task List Review and Program Evaluation – Section 1
• Reorganized Section 2 to accommodate the Markets certification exam
• Added section on disciplinary actions for certification exam – Section 2.2.
• Removed references to the timeframes associated with certification requirements from
• Section 2.3. Added reference to Section 3 where these are covered in detail.
• Added clarifying language to EOP requirement in Section 3.2.1
• Added clarifying language to the DTS role in determining the annual tasks that are included in the continuing training program in Section 3.2
• Changed MOC and Small Plant Generation Dispatcher continuing training requirement from rolling 3-year requirement to annual requirement in Section 3.2
• Added language to include Load Management Resources in Section 3.2.
• Removed “beginning in 2012” Section 4.3.1
• Changed requirement for PJM Generation Certification timeline from 1 year to 6 months.
• Section 4.4
• Removed ExSchedules from list of Master Coordinator related tools. Section 4.4
• Added clarifying language to Simulator Retest process. Section 4.5
• Added clarifying language to Simulator Retest process. Replaced the word “Understand” in Skills and Knowledge section with “Ability to demonstrate knowledge of” Section 4.6
• Replaced the word “quiz” with “assessment. Section 4.9

• Attachment C: Plant Specific NPIRs Revision History: NPIR revision update

• Periodic review
• Section 1.3 Additional language added to the communications section to include references to communications with neighbors
• Deleted Sections 1.3.1, 1.3.2 and 1.3.3 due to redundant information being included in Manual 1.
• Section 2.2:
  • Updated the DASR requirement to the new 2018 values.
  • Added BAL-002-2 related language to note that both generation and transmission configuration is monitored when determining the largest single contingency
• Section 2 and Section 5 updated to provide clarity regarding the emergency procedures that trigger a Performance Assessment Interval (PAI)
• Sections 2.3.2, 5.2 and 5.7 included notes to indicate which emergency procedures would trigger a Performance Assessment Interval (PAI).
• Section 3.4: Hot Weather Alert. Added language e to indicate an Alert can be issued at temps below 90-degrees during the spring and fall months depending upon impacts of
  generation and transmission outages that lower available capacity.
• Section 3.8: Added new section on the process for assessing and monitoring of gas infrastructure conditions. The process describes the triggers, assessment of impact to
  the electric system, and controlling actions.
• Revised all references to the FERC pager system to the FERC email address to be utilized for capacity deficiency notices.
• Revised all references from eLRS to DR Hub.
  
  

• Section 2.3.1: updated references to TOP-004 and TOP 007.
• Section 2.7: updated references to TOP-004, TOP-006 and TOP-008.
• Section 3.2: revised language to clarify EMS data communication methods to PJM during data link or RTU/telemetry devices outages.
• Section 3.8: revised language to absorb Section 1.3 of Manual 13 regarding requirements during ICCP/DNP outages.
• Attachment A: revised to add a new generation scheduling service for system restoration planning.