Manual Updates

• 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.

• 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.ection 5: Removed BGE/PEPCO/Doubs/Northern Virginia (NOVA) operating procedurection 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 Proces
• 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.
  
  

• Revisions to Sections 4.3 (4.3.1, 4.3.5 & 4.3.10), 4.6 (4.6.6), 4.9, 4.10, 8.4, 8.4A, 8.7A, 8.8, 8.9, 9.1 (9.1.3, 9.1.4, 9.1.5 & 9.1.11), 11.3, and 11.8 (11.8.8 & 11.8.9) to accommodate sub-hourly settlements (FERC Order 825).

• Cover to cover periodic review. Updated references and terminology. Designate SPS to RAS or to scheme where applicable.
• Section 1.2: Added notification language for conditions that will result in the loss of
  multiple generation units.
• Section 1.7: Updated dates for the SPS/RAS review and classification.
• Section 3.5.3: Added Montgomery and Damascus 230 kV capacitors. Removed Black Oak, Meadow Brook, and Doubs #2 capacitors.
• Section 3.9: Added NERC TPL standard references for stability analysis criteria.
• Section 3.9.1: Removed reference to Out of Management Control for stability restrictions.
• Section 3.11: Added notification language for the Generator Voltage Schedules updates.
• Section 3.12: Clarifications and additional information added with respect to the Reactive Reserve Check RRC process.
• Section 5: Updated nuclear voltage (NPIR) limits and reorganized procedure.
• Section 5: Updated the Automatic Remedial Action Scheme (RAS) Operating Criteria
  section.
• Section 5: Updated AEP Rockport Operating guide.
• Section 5: Updated the Dayton Darby Plant procedure.
• Section 5: Updated BGE Mt. Washington RAS procedure.
• Section 5: Updated the AEP Rockport Operating procedure.
• Section 5: Removed PJM/NY-ISO PAR Operation procedure.
• Section 5: Updated Oscillation Mitigation Procedure.
• Section 5: Updated the PECO Peach Bottom Transformer Outage procedure.
• Section 5: Updated the ComEd Kincaid Stability Trip Schemes procedure.
• Section 5: Updated the ComEd Powerton Stability Trip Schemes procedure.
• Section 5: Updated the ComEd Quad Cities and Cordova Limitations procedure.
• Section 5: Updated the ComEd East Frankfort TR83 345/138 kV Transformer Scheme
  procedure.
• Section 5: Updated the ComEd University Park North Energy Center Stability Trip Schemes procedure.
• Section 5: Updated the ComEd Elgin Energy Center Stability Bus Tie Scheme procedure.
• Section 5: Updated the ComEd Wolfs TR 81 Scheme procedure.
• Section 5: Updated the ComEd Dresden Unit 2 Trip Scheme procedure.
• Section 5: Updated the Dominion Clover Gen Shed Scheme procedure.
• Section 5: Updated the Dominion Bath County-Valley Stability RAS procedure.
• Section 5: Updated the Dominion Carolina RAS procedure.
• Section 5: Updated the FE-W Mansfield reclosing procedure.
• Section 5: Added the FE-S West Moreland/Ronco/South Bend stability procedure.
• Section 5: Added the FE-S Squab Hollow SVC procedure.
• Section 5: Updated the FE-S Belmont RAS procedure.
• Section 5: Updated the FE-E Warren-Falconer procedure by removing SPS designation.
• Section 5: Updated the FE-E E.Sayre-N.Waverly procedure by removing SPS designation.
• Section 5: Updated FE-E Seneca’s pumping procedure.
• Section 5: Removed DUQU Crescent #1 or #3 345/138 kV Autotransformer Reliefprocedure.
• Section 5: Removed the FE-E Yards Creek SPS procedure due to retirement. Tentative effective date of December 31, 2017.
• Section 5: Removed FE-S Willow Island Area thermal overload procedure.
• Section 5: Added new procedure for gas-pipeline contingency analysis in RTO section.
• Attachment A: Removed Rockport Fast Valving SPS.
• Attachment A: Removed Aurora SPS.
• Attachment A: Removed Warren-Falconer SPS
•  Attachment A: Removed N. Waverly-E.Sayre SPS.
• Attachment A: Modified RAS/SPS descriptions.
• Attachment A: Remove the Yards Creek SPS.
• Attachment E: Added Jenkins #1 TX scheme with effective date.
• Attachment E: Added Elko #1 transformer scheme with effective date.
• Attachment E: Removed retired schemes and updated effective dates.

• Periodic Review
• Multiple Locations – administrative changes - replaced Local Control Center with Transmission Owner and replaced LCC with TO
• Exhibit 1 and Section 6 – administrative changes – replaced System Operator Certification with PJM TO Operator and Generation Dispatcher Certification for consistency with Manual 40
• Section 4.1.7 - SCADA—Supervisory Control and Data Acquisition – grammatical correction
• Section 4.3 - Synchrophasor Communication System – clarified network requirements, deleted Exhibit 7, revised link to registration form and updated email address used for
  reporting problems
• Section 5.3.4 eDART – added requirement for non-black start generators to be modeled in eDART consistent with the PJM EMS model. Also, added requirement that all newblack start generators be modeled individually in eDART and EMS.
• Section 5.7 Generation Transfer Process – new section relocated from Manual M10
• Section 7.1.1 Generator Real Power Control - revised over frequency level per NERC Reliability Standard PRC-024-2
• Section 7.1.2 Voltage and Reactive Control
  • added requirement that the Transmission Operator copy PJM via email on the voltage schedules assigned to the Generator Owner/Operator
  • added the requirement for non-synchronous generating facilities which entered the New Service Queue on or after November 1, 2016 to provide dynamic reactive power and follow the assigned voltage schedule. (FERC Order No. 827 - Reactive Power
• Requirements for Non-Synchronous Generation)
  • deleted voltage schedule exemption details and left the reference to the process as described in M3.
  • clarified that AVR & PSS outage notifications must be made verbally and via eDART
  • clarified the wording in the note related to Power System Stabilizers
• Section 7.1.6 Black Start – clarified wording regarding the TO’s capability and authority during system restoration
• Section 7.3 – Critical Information and Reporting Requirements - added requirement for Generation Owners to notify PJM of any operating conditions that could potentially result in a single contingency causing an outage of multiple generation resources
• Section 7.3.5 Fuel and Emissions Reporting – removed references to capacity resources and added reference to specific EOP standard
• Section 10.1.2 – Black Start Selection Process, D. RFP Proposal Evaluation – updated the criteria including preferences for units that are dual fueled or have firm gas transportation contracts and outlined proposal evaluation criteria
• Attachment N: Cold Weather Preparation Guideline and Checklist – minor revisions based on Version 2 of NERC’s Generating Unit Winter Weather Readiness Reliability Guideline.
• Updated the links to the NERC Guideline and the RF presentation.

• Cover to Cover Periodic Review
•  Introduction – changed Market Operations Center (MOC) operations to Generation
  Dispatchers and added reference to Manual 01
• Section 2.1 – Generation Outage Reporting Overview
  • Updated applicable NERC Reliability Standards
  • Added requirement for Generation Owners to notify PJM of any operating conditions
    that could potentially result in a single contingency causing an outage of multiple
    generation resources
• Section 5.1 Markets Database – deleted “by 1030 hours when the PJM day-ahead
  Energy Market closes” due to implementation of intra-day offers
• Section 5.2 – Generation Transfer Process – relocated to Manual 14D, Generator
  Operational Requirements

• Updated Section 2.3.5 for bus breaker contingencies

• Update to Section 4.6.9 to add requirements for new Black Start units entering the service.

• In Section 7, Black Start Service Accounting, added a description of how charges and credits are handled for a new Black Start unit.

• Cover to Cover Periodic Review
• Section 3: Revisions to the methods used to forecast Demand Response and Price
  Responsive Demand
• Attachment A: Conforming changes to clarify when load drop estimates are produced
  and definitions of calculations for load drop estimates in non-summer period, in
  accordance with FERC Order E17-367 approved on March 21, 2017
  
  

• Biennial Cover to Cover Review
• Updated name of manual from “Generation and Transmission Interconnection Process” to “New Services Request Process”
• Section 1 - Labeled image as new Exhibit 1
• Section 1.1 - Requirements for Generating Units
  • Provides clarification of Generating Units and participation in the PJM Markets
• Section 1.2 - Interconnections with municipalities, co-operatives, or non-PJM member electric distribution companies (EDC) 
  • Provides clarification of generator requirements for participation in the wholesale market
• Section 1.3 - Interconnection Procedures for FERC Jurisdictional and Non- FERC Jurisdictional Facilities
  • Provides clarification on generators that wish to participate in the Wholesale market, but are connected to an EDC
• Section 1.12 - Consent to Assignments 
  • This is a new section that clarifies transfer of ownership processes before and after commercial operation of a Generator
• Section 1.20 -  Non-Queue Interconnection Service Agreements
  • This is a new section which provides guidance for existing Generators which require an ISA
• Section 1.21 -  Serving Load as a Generator
  • Unless allowed under applicable state or local law, an entity is not permitted to serve another entity’s load. Station Power loads can be served between generators in a single portfolio.    
• Section 2.1.2.1 -  Site Control
  • Provides additional clarification on the requirements for site control
• Section 2.1.2.2 - Generation Interconnection Requests
  • Multiple requests behind the same Point of Interconnection
  • Fuel Change
  • Attachment Y applications
  • Attachment BB applications
• Section 2.1.4 - New Service Request deficiency reviews
  • Requires a reasonable on-service date based on Study(ies) timeline and construction schedule
• Table 2-2-1: System Impact Study costs
  • Corrected tables
• Section 2.3.1 - Queue Priority and final agreement issuance and determination of security requirements for moving out of sequence
  • Added a discussion regarding cost allocation for network upgrades and the prioritization among queue positions with allocations to a shared network upgrade.
• Section 2.4 - Types of Network and Local Upgrades
  • Provides clarification for the various types of Network Upgrades
  • Labeled image as new Exhibit 2
• Section 2.5 - Transfer of Capacity Interconnection Rights
  • Describes the process for transferring existing CIRs
• Section 2.6 - Work Papers\
  • This section defines Work Papers and how they relate to the RTEP base case used for modelling New Services Requests 
• Section 3.1.4 - Expedited and/or Combined Study Analysis\
  • This section provides clarification for the combined study process and how it applies to small Generators
  • Labeled image as new Exhibit 3
• Section 4.1.2 - Interim ISA vs. ISA with Interim Rights
  • This section describes the difference between advancing construction with an Interim ISA, and advancing the in service date of the Generator coming into service ahead of the base case study year.
• Section 4.1.3 - Security Requirements
  • Provides clarification on the security requirements for an ISA, WMPA, or UCSA
• Section 4.1.4 – Agreement Milestones
  • Provide clarification on the required Agreement Milestones
  • Labeled image as new Exhibit 4
• Section 4.2.1 - Option to Build
  • Provides clarification on “Option to Build”
• Section 4.3 - Wholesale Market Participation Agreement (WMPA)Defines what a WMPA is
• Section 5.1- Behind the Meter Generation Projects
  • This section provides additional clarification of Behind the Meter Generation interconnections
•  Removed reference to Alternate Queue in Sections 1.9 and 3.1.2
• Made changes to language to remove separate procedures for Network Upgrades with costs <$5 Million in Attachment B, Sections B.2, B.3.1 and B.3.2

• Revisions throughout to implement hourly differentiated offers and the ability to update offers intraday

• Revised Section 5: Operating Reserve Accounting to reflect Intra-Day Offer changes as
  approved by FERC (ER-16-382-000)
• Revised Section 12: Meter Reconciliation Accounting to include pseudo-tie generator
  and dynamic schedule imports and exports and define the applicable rate as well as the
  impacted market participants.

• Revised Section 7 to include PJM-MISO Coordinated Transaction Scheduling
  • Added Sections 7.2 and 7.3 to support the Coordinated Transaction Scheduling implementation
    
     

• Added conforming changes to section 8.6 to account for FTR Forfeiture rule changes

• Updates for termination of PJM/NYISO Wheel Agreement
• Updates to Attachment J(New Equipment Energization Checklist) for updated PJM Contact Department
• Updated Attachment G.7 for PJM Short Circuit model build contact

• Cover to Cover Periodic Review
• Non-substantive changes to format and references
• References: eDART Training Presentations link updated
• Section 1.3: Link added for online training presentations on model update related processes & procedures
• Section 2.2: Note added to address process to change to Flow CB
• Section 3.2:
  • Content reordering and reformatting for improved readability and flow
  • Reference note added to Appendix E: Checklist for New Equipment Energization Process
  • Referenced Manual 14B and online training for Supplemental Upgrades submission to PJM Planning
  • Updated list of required items needed for Network Model update submissions
  • Note added for Exhibit C1 outlining which facilities require ratings
  • Details added about process to link Network Model Requests to associated Cut-in Transmission Outage Tickets
  • Details outlined for areas needing TO review in line with the model update process
  • Removed EHV Modeling as separate section (formerly 3.2.1) and made as Note in Section 3.2
    • Exhibit 5 moved from Section 3.2.1 to Section 3.2
• New Section 3.2.1 - External Modeling
  • Moved external modeling specific verbiage from Section 3.2 to new Section 3.2.1
  • New Section 3.2.1.1 - Pseudo Tie Modeling used to identify PJM model update need for approved pseudo-ties
    • Points to Manual 12 for Pseudo-Tie consideration requirements
• Section 3.3: Updated to reflect capability to enter ratings for flow breakers.
• Section 3.5: Clarification added to generator unit naming requirements
• Section 4.4:
  • Elaboration added on Tie Line process; reference added to M01, Attachment D: Tie Line Meter Placement and Telemetry
  • New Exhibit 8: Tie Line Update Timeline added
    • Exhibit numbers updated per insertion of new Exhibit 8
• Section 4.8: Updated DMS parent committee & meeting occurrences
• Appendix A: Title changed to ‘TERM Equipment Ratings Update Process’
• Appendix C: Reference to NERC BES process and PJM white paper changed to a Note
• Appendix E: Note added with references to Manual 14B and Manual 14C
•  Appendix F: Acronyms & Descriptions updated

• Removed references to the annual RTEP cycle in order to reflect the new 18-month RTEP cycle.
• Updated Exhibit 1 to also reflect new 18 month cycle.

• Revisions to Section 8.4A to describe that if energy offer does not comply with Manual 11, Section 2.3.7, then no MWs from generation resource will be exempt or considered for bonus performance during the Performance Assessment Hour.

• Section 3.2.3, revised language to clarify EMS data communication methods to PJM during data link or RTU outages.
• Section 4.1, revised language to comply with COM-001-3
• Section 4.1.5, new section regarding member communications with field personnel.
• Section 4.5.1, revised language to comply with TOP-001-3 (R1). 
• Attachment A, B.4, added detail regarding AVR/PSS control. 
• Attachment B, removed TOP-006-2 R6, EOP 003-1 R2 and EOP 003-1 R8 references.

• Section 2.3.7 – describe the items needed in each energy offer that is needed to qualify for exempt or bonus MW during a Performance Assessment Hour

• Cover to Cover 2017 Periodic Review
• Added conforming changes to section 4.2 and 4.3 to account for Qualified Replacement Resources in Stage 1 of the Annual ARR allocation
• Added conforming changes to section 8.4 to account for exclusion of balancing congestion for FTR Target funding
• Added conforming changes to section 4.10 to account for removal of negatively valued Residual ARRs 

• Section 2.3.2 and  2.3.3 – added clarity  to which step in the demand curve is used
• Section 2.5 – removed wording describing the demand curve and penalty factors and reworded within, Section 4.2
• Section 2.9 and 2.9.1 – capitalization and removal of requirement to report false positives to FERC
• Section 4.2.2, 4.2.2.1, 4.2.9 and Section 4b.2.2 – incorporated language from Section 2.5 and clarified how the demand curves, penalties factors and requirements are structured. 
• Section 4.2.2.1 is a new section defining the shape of the demand curve and adding the additional permanent 190 MWs associated with Step 2.

• Section 6.1.3.2
  • Incorporated requirements relevant to the new minimum design standards for Designated Entities which were developed by the Designated Entity Design Standards Task Force

• Revised Section 8 :Transmission Congestion Accounting Overview to reflect Balancing Congestion changes as approved by FERC (ER16-121)

• Revised Section 4.3 to align language with Zonal and Global LDA definitions presented in Attachment C of Manual 14b. 

• Current Revision

• Section 3.1: Clarified language to ensure all changes made to Nuclear Plant Interface Requirements (NPIR) are clearly highlighted with drivers communicated
• Attachment A, Section 5: Added clarification to reinforce that NPGO notifies PJM and associated LCC of conditions at nuclear plant impacted by grid-side event
• Attachment C: Plant Specific NPIRs Revision History: NPIR revision update

• Attachments E updated with 2017/2018 Load Forecast information
• Attachments F updated with 2017/2018 Load Shed capability information

• Cover to cover periodic review. Changed formatting, updated references. Updated terminology for Constraint Logger, SmartLog, etc. 
• Section 1.3: Added contingency verification step to the modeling issue investigation process. 
• Section 1.5.6: Added note to indicate PJM EMS has the capability to monitor flow on devices such a circuit breakers (Flow Device). Transmission Owners can submit device/circuit breaker ratings following the same process as other facilities.
• Section 3.3, Exhibit 3, and Exhibit 5: Updated section and combined exhibits with new tables for PJM Baseline Voltage Limits and Transmission Owners’ Voltage Limits.
• Section 3.3.3: Moved Generator Voltage Schedules from Section 3.3.3 to new Section 3.11 and clarified language
• Section 3.5.3: Updated Bulk Electric System Capacitors Operation at Erie South, Four Mile, and West Wharton.
• Section 3.7: Removed TMI-Hosensack as a high voltage control switching option due to system upgrade.
• Section 3.8: Changed one Eastern interface definition line from TMI-Hosensack to Lauschtown-Hosensack. Reformatted interface definition table to “from-to” format.
• Section 3.12: Added new section Reactive Reserve Check (RRC). Previously located in Manual-14D.
• Section 4.1: Added paragraph highlighting need for Transmission Owners to enter outages for transmission equipment owned by Generation Owners
• Section 4.2.2: Updated the relay outage and degradation reporting criteria. Changed note text from “Hotline” to “automatic reclosing”. 
• Section 4.2.6: Revised Peak Period Outage Scheduling Guidelines to add clarity on denial under certain projected conditions.
• Section 4.2.13: Updated title and added Transmission Owner notification to impacted unit owner.
• Section 5: Updated procedure types throughout in various procedure table listings. 
• Section 5: Updated the NPIR voltage limit table.
• Section 5: Replaced PS/ConEd Wheel procedure with NY/NJ PAR Coordination procedure.
• Section 5: Updated reference for MISO Pleasant Prairie – Zion E.C procedure.
• Section 5: Updated the ComEd Quad Cities / Cordova procedure. 
• Section 5 and Attachment A: Removed the ComEd Byron/Lee County operating procedure and SPS due to upgrades.
• Section 5: Updated the ComEd Powerton Stability/SPS procedure.
• Section 5: Updated the ComEd Normally Open Bus Tie CB procedure by removing the Wayne CBs.
• Section 5: Removed Single breaker de-rate section for BC, DOM, DLCO, DEOK, FE-South, PPL, and PS.
• Section 5: Updated AEP Smith Mountain 138 kV Station Stability.
• Section 5: Updated AEP Conesville 345 kV Plant Operating Guidelines.
• Section 5: Updated AEP Cook Unit Isolation on Select Circuits.
• Section 5 and Attachment A: Added new Dominion North Hampton Remedial Action Scheme procedure.
• Section 5: Updated UGI Mountain 23030 Bus Tie Operation procedure.
• Section 5: Updated the PECO Peach Bottom Transformer RAS/SPS procedure.
• Section 5: Updated the BGE Calvert Cliffs procedure.
• Section 5: Updated the DLCO Cresent 345/138 transformer relief procedure by removing a single breaker derate reference.
• Section 5: Added the FE East West Wharton SVC procedure.
• Section 5: Added the FE East Erie South SVC procedure.
• Section 5: Updated the FE East Altoona SVC procedure.
• Section 5: Renamed the ATSI Mansfield procedure.
• Section 5 and Attachment A: Removed the BGE Concord Street RAS/SPS procedure due to retirement on 5/31/17.
• Section 5 and Table of Contents: Renamed the PSEG Bergen Overdutied Breaker procedure (previously Bergen Normally Open Equipment procedure) and edited procedure for clarity.
• Section 5: Reformatted tables in PE Limerick 4A and 4B 500/230 kV Transformer Banks procedure.
• Section 5: Updated and renamed the PE Muddy Run Restrictions procedure.
• Section 5 and Attachment A: Removed the Linwood SPS procedure.
• Section 5: Changed projected retirement date for BGE Mt. Washington RAS/SPS procedure from June 2018 to December 2018.
• Section 5: Updated reference title for Bath County – Valley Stability RAS/SPS.
• Section 5 and Attachment A: Removed the PPL Jenkins SPS procedure due to retirement.
• Section 5: Updated AEP Tidd 138 kV Switchyard Operating Guidelines for overduty circuit breakers.
• Section 5: Deleted AEP Tidd 345 kV Station Voltage Concerns procedure.
• Section 5: Added PPL Susquehanna CB switching procedure.
• Section 5: Added PPL Martins Creek stability procedure.
• Section 5: Updated name to PPL Northeast PA (NEPA) Stability Limit. Updated line names and added stability restriction table for Transmission Outage with impact to Sunbury CC.
• Attachment E: Updated the list of sectionalizing schemes by removing schemes no longer needed due to upgrades. Added new sectionalizing schemes in Dominion with effective dates of 7/27/17.

• Several locations – administrative change – references to PJM Manual M-3, Transmission Operations, Section 3.3.3, changed to Manual M-3, Section 3.11 to reflect the transfer of the Generator Voltage Schedules section of M-3 from Section 3.3.3 to Section 3.11.
• Section 2.1 – Generator Owners’ Responsibilities – administrative change - updated references to other documents
• Section 2.1 – Generator Owners’ Responsibilities and Attachment L: Jointly Owned Resource Communication Model – changed references from Generation System Operator to Generation Dispatcher for consistency with PJM Manual, M-40, Training and Certification Requirements
• Section 4.1.5 EMS Data Exchange – revised Exhibit 2 to include requirement for two second generation MW telemetry data for all units participating in the PJM regulation market
• Section 4.2.2 Metering Plan – summarized real-time telemetry requirements in chart format and added requirement for solar farms
• Section 5.4.4 Grid Accounting – administrative change – changed name of PARs from Ramapo to NY-NJ
• Section 5.6.2 Data Requirements – administrative change – corrected end of re-bid period to 1415 hours
• Section 6.3.4 Other Requirements – added requirements to have and follow a voltage schedule
• Section 7.1.1 Generator Real-Power Control – deleted the qualifier “larger than 20 MW” from the requirements to meet the frequency guidelines.  Reference FERC Order # 828, Requirements for Frequency and Voltage Ride Through Capability of Small Generating Facilities issued July 21, 2016.
• Section 7.1.1 Generator Real-Power Control – added clarification that governor outages must be reported for all units via eDART
• Section 7.1.2 Voltage and Reactive Control:
  • Added the requirement that newly connected generator facilities be provided a voltage schedule per PJM Manual M-3, Section 3.11.
  • Clarified Automatic Voltage Regulator required operating modes and included more specific reason for requesting an exemption from following a voltage schedule.
  • Added specifics for notifications of Power System Stabilizer outages. 
• Section 7.3 Critical Information and Reporting Requirements – added clarification for Generation Owners that own transmission equipment to notify the affected Transmission Owner who must then submit outage requests to PJM via eDART for this generation-owned equipment.
• Section 7.3.4 Generating Unit Reactive Capability Reporting
  • Clarified that these requirements are applicable only for units physically located within the PJM RTO Footprint
  • Clarified language for Pre-Summer and Pre-Winter eDART reactive capability review.  
• Sections 8.2.1 Initial Data Requirements & 8.2.3 Real Time Meteorological Tower – Clarified that longitude and latitude are required to be supplied in decimal degrees
• Section 12 – added new section for Solar Park Requirements –Reference FERC Order # 764, Integration of Variable Energy Resources issued June 22, 2012.
• Attachment A:  Added voltage schedule and reactive capability curve requirements to New Generator Checklist.
• Attachment D - PJM Generating Unit Reactive Capability Curve Specification and Reporting Procedures:  
  • Clarified that these requirements are applicable only for units physically located within the PJM RTO Footprint
  • Included guidelines for selecting points on the D-curve to be submitted via eDART
  • PJM Reactive Reserve Check (RRC) – revised description, added reference to Manual 3, Transmission Operations for details and generator owner responsibilities, and deleted Exhibit 19
• Attachment E: PJM Generator and Synchronous Condenser Reactive Capability Testing
  • E2 – General Requirements - Clarified that reactive testing is not required for capacity and energy resources located outside the PJM RTO footprint
  • E3 – Testing Requirements – removed link to Reactive Capability Testing Form
  • E.4.1 – Clarified that maintenance work on the facility that may affect the reactive capability of the units must be completed prior to contacting PJM to initiate the study process.
  • E.4.1 – Note 1 – Added the words “and attempt” in the sentence: “The LCC and PJM will work together and attempt to adjust the transmission system voltage and mitigate the external condition.”
  • E.4.1 - Revised test submittal process to include submitting Reactive Test Results via eDART
  • E.9 Test Tracking – deleted section.  No longer required due to addition of submitting test results via eDART.
  • E.10 – renumbered to E.9 and revised to remove sample test submission forms and included eDART screenshot of Reactive Result Ticket.

• Cover to Cover Period Review
• Change “Generation Owner/MOC dispatcher” to “Generator Operator” throughout manual to match NERC terminology
• Updated “About PJM Manuals” section in the Introduction to reflect revisions on pjm.com.   Added Generator Operator to Intended Audience section of Introduction.
• Section 1.1 – Removed references to EOP-009 and EOP-007-RFC-01 as these standards have been retired
• Section 7.1.2 – Clarifications to Minimum Source Guidelines.   Removal of Exhibit 10, Locations of Synchronization Devices due to this information being in the TO restoration plans
• Section 8.1 – Restoration Plan Guidelines.  Added template for Generation Information (Exhibit 10) for inclusion in TO System Restoration Plans
• Attachment A: Minimum Critical Black Start Requirement – Removed references to System Restoration Strategy Sr. Task Force
• Attachment B: Restoration Forms – Exhibit 14 and 15 – Updated email address to mail forms.  Added OVEC
• Attachment D: Restoration Drill Guide – Changed required participation of Generator Operators to the Spring restoration drill.
• Attachment F: Transmission Owner and Black Start Supporting Documentation References – Updated table in Figure 1
• Attachment G: Coordination of Restoration Plan with PJM Internal and External Neighboring Entities – PJM Approval Process for TO Restoration Plans – Added detail to  section G-4 on process for updating restoration plans based on changes to BES equipment
  • Updated dates for First Energy, RECO, BGE, OVEC and ITCI annual update

• Fuel Cost Policy and Hourly Offers conforming changes:
  • Section 1.8, 2.3, 2.3.1, 2.3.1.1, 2.3.1.2, 2.3.1.3
• Additional changes to require submission to PJM and MMU
• Removed references to Manual 35 as this has been retired

• Sections 2.5; 2.9 and 2.9.1   Edits associated with FERC Order No. 825 to implement the transient shortage rule changes effective May 11, 2017

• Updated baseline thermal analysis section (2.3.6) to reflect correct N-1 analysis process
• Updated SPS to RAS per NERC definition change
• Updated PRC-023-3 to PRC-023 to account for future Standard revisions including PRC-023-4 which goes into effect 4/1/2017
• Updated for removal of EE (Energy Efficiency) References – as they are now included within the load forecast

• Conforming revisions for FERC Order ER17-367 issued on March 21, 2017, to enhance aggregation rules, implement Seasonal Capacity Performance Resources, provide opportunity for Intermittent and Environmentally Limited Resources to request additional Capacity Interconnection Rights in winter, and modify measurement and verification rules for Demand Resources.

• Section 4.2.2; 4b.1 and 6.2 – Providing one location on where to find the Primary Reserve and Synchronized Requirements (Manual 13, Section 2.2)
• Section 4.2.2 – provided updated explanation of what resources and the associated MWs are used for “double spin”; removed on peak / off peak requirement differentiation during “double spin”
• Section 4b.2.3 – added clarity that the NSRMW should not go negative

• Section 2.2, updated Data Requirements section noting that PJM’s data specifications for external Reliability Coordinators can be found in M-01, Attachment A and existing JOAs.
• Section 2.4.2, added clarification to the Change Management Process indicating authority of the PJM Shift Supervisor for Planned maintenance involving PJM telecommunication, monitoring and analysis tools.
• Updated NERC Standard/Requirement references in Sections 2.3, 4.1, 5.1 and within Attachment A: PJM Reliability Plan.
• Section 3.1, spelled out MMWG and OATF acronyms.
• Section 5.1, corrected MISO’s name.
• Attachment A, PJM Reliability Plan: 
• Deleted reference to ITC Integration.
• Added Attachment D.
• Section A: changes reference for PJM Directives to PJM Operating Instructions.
• Section C: noted that PJM Day-Ahead Reliability Analysis reports are posted to the secure PJM site.
• Section D: updated timing of SDX download to every 15 minutes.
• Section E:
  • Updated to note PJM controls to the BAAL Standard (removed field trial reference
  • Updated SPS reference to RASAdded clarification to the automated eDART process for unplanned transmission outages
• Section H: updates ISN reference to EIDSN
• Section I: added to PJM System Operators tools list to include DIMA and IEP
• Section J: updated PJM control room staffing requirements
• Cover to Cover Periodic Review

• Introduction - Specified that M-13 is the PJM Emergency Operating Plan, as required by EOP-011
• Various updates to Sections 2 and 5 for EOP-011 compliance
  • Of note, EEA3 to be issued for Manual Load Dump Warning and Voltage Reduction Action due to new thresholds
• Creation of Section 7 TOP Operating Plan Submission and Review for EOP-011 compliance
• Modified all references to manual load shedding throughout the manual to clarify this should be implemented while minimizing overlap with automatic load shedding (EOP-011 update)
• Updated EOP-002 references to EOP-011
• Deleted Appendices 4 and 5 from Attachment K. Updated link to the NERC Event Analysis documentation.
• Updated all Load Dump references to Load Shed

• Section 5.2.1.6, Internal Tie Lines, Special Cases and Transformer Tie Lines, the minimum required scan rate was changed from 4 seconds or less to 10 seconds or less.
• Attachment A, Information Access Matrix, redressed as Data Specification and Collection to meet IRO-010-2 and TOP-003-3.
• Attachment A, references to eData replaced with Data Viewer.
• Attachment A, Part A, added A.2.1, to create a separate row for Neighboring Control Areas who submit outages via SDX, not eDART.
• Attachment A, Part B, B.14, AVR/PSS Excitation Control via eDART, Required Service moved from Transmission Owner to Generating Entity to correct error.
• Attachment A, Part D, updated with references to SDX for D.2, D.3 and D.5.
• Attachment A, Part E, updated E.1 per latest OASIS work flows and deleted E.2 which is now covered in E.1.
• Attachment A, Part E, deleted E.6 – PJM does not offer ancillary services via OASIS.
• Attachment A, Part E, deleted E.8 – PJM does not offer a billing summary via OASIS.
• Attachment A, Part G: Long-term Planning Services removed. See Manual 3A, Section 2.2 for equivalent information.
• Updates and corrections to PJM email addresses in Section 3

• Cover-to-Cover Periodic Review
• Changed terms of partial outage hours to derated hours for forced, maintenance and planned events.

• Section 2.3.1, Voltage Reduction Summary Table updates:
  • Updated FE East – PENLC and FE East – METED to reflect new consolidated MAIT TO entity as approved by 1/26/2017 FERC Order (ER17-214-001).

• Section 5.3 Network Integration Transmission Service Credits:
  • Removed MetEd and Penelec from TO list and added MAIT to reflect new consolidated MAIT TO entity as approved by 1/26/2017 FERC Order (ER17-214-001). 

• Update to Section 4.4.3 to update regulation requirement definition.

• Cover to Cover Periodic Review
• Added language in Section 5.2 to allow for Network Service Peak Load values submitted by Electric Distribution Companies to be scaled if the values do not sum to the Annual Network Service Peak Load for the zone.
• Updated Sections 2 and 9 to include language on funding and charges for Consumer Advocates of PJM (CAPS)
• Updated the web link in Section 7 for the Black Start Revenue Requirements posting on pjm.com.
• Removed references to Manual 35 as this manual was retired on November 17, 2016.

• Revision to sections 3.2.4 and 6.1.1: updated the regulation requirement period and the regulation requirement effective MW to defer to Manual 12 Section 4.4.3 – Determining Regulation Assignment.
• Removed references to Manual 35 as this manual was retired on November 17, 2016.

• Cover to Cover Periodic review: Corrected typos and grammar, updated references, updated cited NERC standards.
• Section 2.1 and 2.2: Updated sections to provide more clarity on generation and transmission outage coordination. 
• Section 2.3: Added new section “Neighbor Outage Coordination and Resolution” to help clarify roles and responsibilities around neighboring outages, and internal outages with neighboring impact.
• Attachment A: Updated the OATF Scope. 
• Attachment B: Updated Reliability Analysis Procedure.

• Cover to Cover Periodic Review
• Annual review of PJM Training Plan (Section 4) in accordance with NERC Standard PER-005-2
• Removed references to Daily Review Team in Section 4.9
• Updated PJM Human Performance program skills in Section 4.12.2
• Added Grid Security Drills as another component of the continuing education offerings – Section 1.6
• Added language to reflect how initial training requirements may be completed – Section 3.2
• Added language to include open/required JIT training to Initial Training Requirements - Section 3.2
• Changed the grace period for completing Initial Requirements and Certification Requirements from 12 months to 6 months for MOC Generation Dispatchers and Small Generation Plant Dispatchers – Section 3.2.2 and 3.2.4
• Added clarification to items which are monitored during monthly and annual compliance checks – Section 3.3
• Removed references to Manual 35 as this manual was retired on November 17, 2016.

• Cover to Cover Periodic Review
• Added more detail to testing requirements, acceptance testing for newly constructed units and re-wording of Net Capability terms
• Added references to capacity interconnect rights and added testing rules for non-hydro storage
• Removed reference to wind and solar as intermittent units (per Manual 18) include units other an just wind and solar capacity resources

• 7.3.5 Fuel Limitation Reporting – Updated title, updated Seasonal Reporting section, added a section on Periodic Reporting, and removed details on Real Time Reporting. Deleted Exhibit 11, Sample Data (Fuel Baseline)
• Deleted references to Manual 35, Definitions and Acronyms which has been retired.

• Cover to Cover Periodic Review
• General clean up and streamlining of language in the Capacity and Transmission Emergency Procedures
• Introduction: Added references to manual M-01, M-02, M-03, M-10, & M-28.
• Section 1.1: Included specific reference to PJM recalling/cancelling transmission and generation outages in the Policy
• Section 2.2: Reserve Requirements updated to reflect proper MAD reserve requirements, as well as information regarding the use of non-MAD resources to satisfy the MAD requirements if they are deliverable.
• Section 2.2: Day Ahead Schedule Reserve requirements updated for 2017
• Section 2.3.2 and 5.2: Clarified the Voltage Reduction Action definition and Manual Load Dump Action definition.
• Section 3.2: Conservative Operations expanded to cover additional scenarios as well as additional PJM dispatch actions
• Section 3.3 and 3.4: Updated Hot and Cold Weather Alerts sections with a PJM action to recall transmission and generation outages. Included reference to M-10 for 72-hour generation maintenance outage recall language
• Section 3.4: Included reference to the Memorandum of Understanding on Natural Gas & Electric Interdependency.
• Section 5.4: Added reference to the PCLLRW tool.
• Section 5.6: Replaced NERC Policy 9 reference with IRO-006-EAST reference for TLR.
• Section 6.4: Seasonal and Periodic Fuel reporting section moved to M-14 with a clarifying note added.
• Struck references to manual M-35 (Definitions & Acronyms).
• Consistent reference to PJM ALL-CALL system throughout.
• Added bookmarks wherever “Attachment A” was referenced.
• Adjusted data retention period to align with PJM policy.
• Revisions to Attachment E for incorporating Dynamic Transfers.
• Deletion of Exhibits 5, 11, 12, 13 and 14. Renumbering of remaining exhibits

• Periodic Review
• Exhibit 1 and Section 5.1 – administrative changes - updated market deadlines
• Section 2.3 – Maintenance Outages – administrative change - deleted last sentence which is obsolete
• Section 2.3.2.1 – added sub-bullets to clarify steps taken during recall of maintenance outages
• Section 2.6, Ending Outages in eDART – new section listing rules regarding ending outages in eDART
• Section 5.1 – Markets Database – added new bulleted item to reflect the proper status of units in Markets Gateway when reduced or on an outage.
• Section 5.2 – Changed section title from “Change of Generation Ownership Process” to “Generation Transfer Process”. Added new rules for implementation of the Generation Transfer Process.