Manual Updates

• 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 BtMG Reporting and Communication Process

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

• Section 1.2.1: Reference to Manual 14D added for BtMG 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.

• Updated Attachment G.11 to reflect changes to Capacity Import Limit test as applicable to Long term Firm Service requests
• Updated hyperlinks throughout document to update for web changes

• Revisions to include restrictions on early replacement of RPM capacity commitments as endorsed by MRC on 12/22/2016 (Section 8.9)

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

• Section 2.5.6. Reference to NERC BAL-005-0 (out of date) changed to BAL-005.
• Section 3.7. Two bullets regarding Tie Lines edited to address concerns with BAL-005 and align with Section 5 edit. 
• Section 3.8. Additional time restrictions on outages including PJM model build days, holidays and other major critical events.
• Section 4.1. Communications expanded to specifically include external entities and non-member internal entities in addition to PJM Members. Delete of text box describing language and communications (redundant with Section 4.5). 
• Section 4.3.3. Removed. Section 4.5 replaces the content. 
• Section 4.5.5, 4.5.6. Now refer to 4.5.2 for operators required to complete training. 
• Section 4.5.2, 4.5.6. Applicable persons expanded to include member company dispatchers (was only operators before). 
• Section 5. Metering Requirements update and restructuring. Clearer breakdown by types of meters. Better separation between operations and billing meters. Clarifications on topics such as accuracy, maintenance, and applicability. Added official detailed definition of Tie Line subtypes. Revised “grandfather clause” for rewritten requirements that can be reasonably construed as new. 

• Revisions needed as a result of a Cover to Cover Periodic Review

• Revisions to remove the restrictions on early replacement of RPM capacity commitments as endorsed by MRC on 11/17/2016 (Section 8.9).

• Cover to cover periodic review. Corrected typos and grammar. Revised terms for consistency. Updated graphics, tables, and exhibits. Updated cited NERC standard(s).
• References: Added NYISO PJM Joint Operating Agreement.
• Section 1.1: Listed ITCI as TOP for its facilities.
• Section 1.4: Clarified language.
• Section 1.7: Revised RAS/SPS review process. Added RAS term throughout.
• Sections 2 and 3: Replaced ‘Load Shed Operating Instruction’ to ‘Load Shed Directive’ to align with terminology in M-13.
• Section 2.1.3: Revised language in table - “PJM Actual Overload Thermal Operating Policy” on limit exceedance.
• Section 3, Exhibit 5: Updated SMECO integration date to Q1 2017 and voltage limits. Corrected PJM baseline voltage limits to one decimal place and the corresponding TO limits.
• Section 3.3.3:Clarified generator voltage exemption basis and updated baseline voltage table notes. 
• Section 3.4: Removed PCLLRW pertaining to NPIR voltages.
• Section 3.5.3: Updated Juniata capacitor bank.
• Section 3.8: Updated the Cleveland Interface definition by adding the new Lake Avenue #1 and #2 345/138 kV transformers and changing the Black River-Lorain 138 kV to Charleston-Lorain 138 kV. Updated CE-East Interface from Olive-University Park to Olive-University Park North 345 kV line. Updated the AP South Interface from Mt. Storm-Doubs to Bismark-Doubs. Updated the BC/PEPCO Interface definition from Pleasant View-Dickerson to Edwards Ferry-Dickerson.
• Section 4: Clarified language and distinguished between transmission outage denial and cancellation.
• Section 4, removed reference to outages submitted after 0800 three days prior to requested start date
• Section 4.2.2: Updated relay work reporting to include 230 kV and other facilities near generating plants and timeline.
• Section 4.2.9: Revised language on rescheduling outages for clarity and added information about modifying equipment list on tickets.
• Section 4.2.11: Updated Nuclear circuit breaker table.
• Section 5: Added table for Cook nuclear voltage limits after regular nuclear voltage limits table (removed cook references from regular table). Added a note to indicate the voltage drop criteria is only applicable for the loss of a unit.
• Section 5 and Attachment A: Updated the PSEG Artificial Island procedure due to the Cross Trip SPS retirement.
• Section 5: Updated the PSEG Bergen procedure.
• Section 5: Updated the AE directional ratings.
• Section 5: Updated the AEP Smith Mountain procedure.
• Section 5: Updated the AEP Gavin – Rolling Hills Stability procedure.
• Section 5: Updated the AEP Rockport procedure.
• Section 5: Updated Voltage Control at Nuclear Stations procedure.
• Section 5: Added action for TO/GO to notify PJM of SPS/RAS unavailability.
• Section 5: Added action for TO to notify PJM of Sectionalizing scheme unavailability or degradation.
• Section 5: Updated the ComEd Kincaid stability procedure.
• Section 5: Updated the ComEd East Frankfort SPS procedure.
• Section 5: Updated the ComEd Byron SPS procedure.
• Section 5 and Attachment A: Removed the ComEd Northbrook/Highland Park Transfer Trip SPS due to retirement.
• Section 5: Added retirement dates for the ComEd Quad Cities/Cordova SPS.
• Section 5: Updated the BC/PEPCO operating procedure.
• Section 5: Updated the FE East Conemaugh/Hunterstown and Homer City procedures.
• Section 5 and Attachment A: Removed Bath County Thermal SPS and all references.
• Section 5: Removed outage timeframe from Bath County - Valley Stability SPS.
• Section 5: Removed references from table to both Cloverdale 500/345kV transformers and updated Mt.Storm-Doubs for Bismark in Bath County Stability Restrictions procedure.
• Section 5: Added temperature set for Carolina 54 SPS.
• Section 5: Updated Clover SPS/RAS Procedure.
• Section 5: Added the PJM Actions to the PPL Steel City – Hosensack 500 kV Reclosing procedure.
• Attachment A: Modified the PECO Planebrook SPS description.
• Attachment A: Modified the PECO Linwood SPS description.
• Attachment A: Rename title of Clover Generator Shed Scheme to Clover RAS/SPS Scheme.
• Attachment B: Added new attachment (to replace ‘deleted’) called Transmission Outage ‘Cut-In’ Ticket Guidelines
• Revision History, V49: Corrected history to add “removal of Load Shed Directive Procedure and placement in M-13”.

• Updated Section 3.5 to provide a description of a fully metered EDC.

• Updated Attachment G.11 to reflect changes to Capacity Import Limit test as applicable to Long term Firm Service requests
• Updated hyperlinks throughout document to update for web changes

• Revisions to 10.4.5 Emergency and Pre-Emergency Settlements to use Economic CBL for energy settlements instead of “hour before” CBL method. Corresponding tariff provisions approved by FERC under ER16-2460.

• Section 2 and 3
  • Added clarifying reference to the agreements
• Section 6
  
  • Added new section for DEA Design Standards

• Revision 19 incorporates language changes associated with the Early Queue Submittal Task Force (EQSTF) recommendations.
  • Updated Exhibit 1 and added Exhibit 2.   Process Flow, and Process Flow and Timeline respectively.
  • Attachment A was modified to reflect the changes to the Planning Flow Diagram.  Attachment A-1, and A-2 were included to reflect an interim transition Queue, and final Queue as depicted in the Planning Flow Diagram.  The final Process Flow Diagram A-2 will be effective April 1, 2017.
  • Additional language was added to Section 1 describing the changes to the Queue Process.
  • Major changes were made to sections 2.1.2 and 2.1.3 to reflect the Earlier Queue Submittal Task Force’s (EQSTF) recommendations.
  • Tables 2-1-1, 2-2-1, 3-1-1, 3-1-3 and 3-1-4 were renumbered and changed to reflect the new study deposit requirements per the EQSTF’s recommendations
  • Added Tables 2-2-2 – System Impact Study Expected Costs and 3.1.2 – Feasibility Study Expected Costs for Attachment N submitted Small Generation Interconnection Requests.
  • Section 2.1.4 was updated to reflect the changes to the New Service Request deficiency reviews per the EQSTF’s recommendations
  • Section 4.2.4 was changed to reflect the updated timeline as shown in revised Attachment A, A-1, and A-2.

• Biennial Review and Administrative Changes
  • Unit Owner changed to Market Seller
  • Capitalization, Abbreviations, Grammar
  • Pumped Storage Hydro
  • Demand Resource

• Section 6 - Added references to new Attachment F
• Attachment F - New attachment for New Equipment Energization Process Checklist

• Updated Section 2.3.13 and Attachment D-3.2 for ratings used in Winter Analysis
• New Appendix J: Checklist for New Equipment Energization Process and associated references in sections: 1.3.1; B.3; H.1; and H.1.3

• References:  Link to PJM Transmission Services added to online reference table. 
• Section 2.2:  Reference added for new Appendix E: Checklist For New Equipment Energization Process.
• Section 4.4:  Reference added to Manual 01 for tie line reference and requirements; text updated for accuracy.
• Appendix E:  New appendix added for Checklist For New Equipment Energization Process.  
• New Exhibit E1:  Checklist For New Equipment Energization Process
• Appendix F: Previously Appendix E, Acronyms & Descriptions, now Appendix F.

• Revisions to clarifying the details of Auction Specific MW bilateral transactions (Section 4.6.6)

• Update to Section 4.4- Regulation to clarify/remove language to align with current operations and removal of information already outlined in Manual 11- Energy & Ancillary Services Market Operations
• Update to Section 3.1.3 PJM Member Control Implementation with conforming changes to current data exchange
• Update to Attachment E- PJM Reporting Of NERC BAL Standard and Section 3.1.1 PJM Area Control Error to align with newly approved NERC balancing standards
• BAL-001-1, BAAL replaces CPS2, reporting requirement removed
• BAL-003-1, Updated Frequency Bias calculation and timeline
• Update black start links and conforming changes in Section 4.6.10 Performance Standards and Attachment C: PJM Black Start Test Report Form

• Cover to Cover Periodic Review

• Cover to Cover Periodic review
• Administrative Change – Section 4.2.1, updated reference to M-01 for outage communication. 
• Section 4.3.4 Data Exchange and Management Requirements – added details and clarifications of PMU and PDC requirements for new generation facilities.
• Section 7.1.2 Voltage and Reactive Control – replaced PJM System Operations Subcommittee Chair with the email address “VoltageScheduleExemption@pjm.com” for the location where requests for voltage schedule exemptions should be directed to. Also included examples of exemption request types and updated the note referencing M-03, Section 3.3.3 related to real-time exemption criteria..
• Section 7.5.1 Generation Resource Operational Exercise – revised to eliminate Capacity Performance resources from being eligible to participate.  Also added link to form used for tracking unit performance 
• Section 7.5.2 Generation Resource Cold Weather Checklist – added date to start the Cold Weather Checklist acknowledgement process.
• Administrative Change – Section 8 Wind Farm Requirements, updated Attachment L references to include new name
• Attachment E: PJM Generator and Synchronous Condenser Reactive Capability Testing, added reference to Compliance Bulletin CB023 in Section E.2.
• Attachment G:  PJM Generator Markets and Operations Process Flow Diagram – Deleted Attachment – information now included in the interconnection process via PJM’s Client Manager.
• Attachment H - corrected name to PJM Generation and Transmission Interconnection Planning Team Role Clarity Diagram
• Attachment N: Cold Weather Preparation Guideline and Checklist – reviewed and updated and added references f. and g. to ReliabilityFirst’s presentation and report on winter preparedness.
• Appendix A – Added reference to Manual 3a for directions to fulfill telemetry requirement.

• Section 3.1, Renamed ComEd Reactive Transfer Interface to CE – East Reactive Transfer Interface
• Section 3.1, added clarification noting specific M-03 sections used to support PJM’s SOL methodology
• Section 3.2, added controlling actions to the list of actions implemented by PJM for congestion control 
• Attachment A: PJM Reliability Plan updated to note ITC as a new PJM TOP effective June 1, 2016
• Cover to Cover Periodic Review

• Cover to Cover Periodic Review
• Updated URL for Tariff Facilities List throughout document
• Miscellaneous administrative and formatting updates
• Section 1.2:  Submission timelines and detail added for modeling updates specific to Generators.
• Section 1.2.1:  New section outlining Electrical Model Responsibilities for Behind the Meter Generation. 
• Section 2.4: T ext and Exhibit 12 moved from Section 4.9.3 to Section 2.4 (new Exhibit number is 2); link added to Transmission Services Tariff Facilities list.
• Section 3.1:  The word ‘document’ replaced with ‘section’; grammar clarified. 
• Section 3.2:  Submit-on-time functionality and process outlined; (old) Exhibit 3 deleted (redundant/confusing); (new) Exhibit 3 (General Schedule for Submitting Modeling Data) enhanced distinguish between Required and Preferred In Service Date for Project; Exhibit 4 (Network Model Data Submission and Model Validation Timeline) enhanced to display corrected timelines, and new timelines added for ‘Preferred In Model Build’ and ‘PJM Tests New Model’.
• Section 3.2.1:  New section added for EHV Modeling.
• Section 3.3:  Grammar clarified.
• Section 3.4:  Paragraph added to outline non-automated process for submitting fixed tap changes to PJM. 
• Section 4.1:  Paragraph 5 updated to reflect current practices and reference to DMS SharePoint postings added.
• Section 4.8.1:  Sharing of data and one-lines across DMS members outlined.
• Section 4.9:  Reference added for PJM Sub-Transmission Modeling White Paper.  
• Section 4.9.3:  Instructions added for BES notification of BES exceptions; Exhibit 12 and preceding paragraph moved to Section 2.4 (now Exhibit 2).
• Appendix C:  New paragraph added to outline BESNet process with supporting web links.  
• Appendix D:  New Appendix added for new Behind the Meter Generation Submission Form and outlining procedure for form submission.  
• New Exhibit D1:  Blank PJM Behind the Meter Generation Submission Form
• New Exhibit D2:  Sample PJM Behind the Meter Generation Submission Form for Distribution, with supporting one-line diagram
• New Exhibit D3:  Sample PJM Behind the Meter Generation Submission Form for Transmission, with supporting one-line diagram
• Appendix E:  Acronyms & Descriptions moved from Appendix D to Appendix E to accommodate new Appendix D for Behind the Meter Generation

• Manual Ownership changed from Paul McGlynn to Mark Sims.
• Section 7: Line Protection reworded to clarify the terms “Primary” and “Backup” and specified PJM Planning Department to review and approve out-of-step relay and single-phase tripping applications.
• Section 8: Substation Transformer Protection revised to better account for practices of all member TOs.
• Power Line Carrier requirements added to Appendix B: Direct Transfer Trip.
• Power Line Carrier added and Fiber Optic Systems rearranged in Appendix C: Dual Pilot Channels.
• Removed Appendix F: Triggered Current Limiters.
• Cover to Cover Periodic Review.

• Revisions needed as a result of a Cover to Cover Periodic Review
• Revisions needed to clarify the implementation details of Capacity Performance

• 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
• Revisions needed to clarify the implementation of Capacity Performance

• Cover to Cover Periodic Review - updates for overall content clarification and logic

• Manual Ownership changed from Paul McGlynn to Mark Sims
• Added new Section 1A - About Critical Energy Infrastructure Information (CEII)
• Administrative Change: Updated Ramping Limits in winter peak study section
• Added Required In Service Dates for Light Load Reliability Analysis and Winter Peak Reliability Analysis
• Corrected references to TPL-001-4 in the PJM Planning SOL Methodology Section
• Updated Attachment G.9.6 including compliance language

• Revisions to section 11.2.2 regarding the default non-eligibility in Day-Ahead Scheduling Reserve process for certain unit types.

• Cover to Cover Periodic review clarifying changes to better describe existing rules and processes.

• Revisions to section 11.2.2 regarding Day-Ahead Scheduling Reserve eligibility for Dynamic Transfer resources.

• Cover to Cover Periodic Review

• Sections 1.2, 2.1, 2.2 & 2.3 - revised to clarify that outage scheduling and approval rules apply to all PJM Generation resources, except where explicitly stated for Generation Capacity Resources.
• Section 2.1, Generation Outage Reporting Overview revisited to include that if a generation resource is made unavailable due to a transmission facility outage, the Generation Owner shall submit an outage request.
• Section 2.4, Unplanned Outages revised to clarify the steps the Member should take with regards to an Unplanned Outage.

• Revisions to section 2.3.4 for ‘Real Time Values’

• Administrative Changes:
  • Updated references eMKT to Markets Gateway
  • Operating Parameter Definition Updates

• Cover to Cover Periodic Review: Updated terms throughout document for consistency
• Introduction – Modified intended audience for this manual
• Section 2.1.3 and 3.2 – Clarify time to correct in table columns and add reference to Load Shed Operating Procedure
• Section 3.2 and 3.5.3 – Clarified Normal and Emergency High voltage limits
• Section 3.2 and 3.3.2 – Remove references to specific voltage levels
• Section 3.3.1 – Changed 34 kV LD baseline voltage limit to n/a instead of 0.0
• Section 3.3.3 – specified email address for generator voltage exemption requests (instead of requests through SOS chair)
• Section 3.5.5 – Clarified language on high voltage limits
• Section 3.5.3: Updated Bulk Electric System Capacitor/SVC Operation, as a result of new SVC’s placed in-service.
• Section 3.7: Updated High Voltage Operation techniques; added STATCOM
• Section 3.7 – Removed opening of Homer City – Stolle Road as an option to control high voltage
• Section 3.8 – Added reference to steady state voltage collapse point and post-contingency low voltage in reactive interface limit determination
• Section 3.8 – Removed prior ComEd interface definition
• Section 3 Exhibit 5 - Added SMECO (effective 7/1/16) and ITCI (effective 6/1/16) companies to table. Section 3 Exhibit 5 - Added ATSI 500 kV voltage limits
• Section 3 Exhibit 5 – Updated ITCI Normal Limit and Normal High Limit (effective 6/1/16)\
• Section 3 Exhibit 5 – Updated EKPC voltage drop limit and emergency low voltage limit.
• Section 3 Exhibit 5 – Updated Dominion and UGI normal high voltage limits.
• Section 4.2.1 – Renamed section to “Outage Submittal Rules” and modified language for ease of understanding. Removed ‘past deadline’ section of table on outages <= five calendar days
• Section 4.2.6 – Condensed language on “Peak Period Outage Scheduling Guidelines” to make Summer Peak Period June 15 – September 15 and recommend all outages scheduled during peak periods have < 72 hour restoration time
• Section 4.2.7 – Modified language on “Outage Scheduling Exceptions” for clarity
• Section 4.2.9 – Added note on Rescheduling Outages for clarity
• Section 4.2.11 – Revised language for “Coordinating Outage Requests With Other RTO’s”
• Section 4.2.13 – Modified language on Coordinating Transmission Outage Requests that will make a generation facility unavailable.
• Section 5: Updated language to include time delay for Carolina 54 SPS and added company reference to SPS
• Section 5 and Attachment A: Removed Carolina 22 SPS due to retirement
• Section 5: Removed Note 2 from Bath County Stability Restriction
• Section 5: Updated wording in Note 5 for Bath County-Valley Stability SPS
• Section 5: Added references to DOM company documents for: Bath County – Valley Thermal Trip Scheme; Bath County – Valley Stability Trip Scheme; Clover Generator Shed Scheme; and Carolina ‘54’ line SPS
• Section 5: Added references to BGE company documents for: Concord Street and Mt. Washington SPS
• Section 5: Modified BGE Concord Street SPS to reflect summer load dump ratings
• Section 5 and Attachment A: Removed Black Oak SPS due to retirement
• Section 5: Updated Homer City #2 and #3 stability trip scheme language.
• Section 5: Added Company references for Homer City #2 and #3 stability trip scheme (STS-1 – language new to manual, STS-2, STS-3)
• Section 5: Added references to FE company documents and default status for: Belmont SPS; Yards Creek Pumping, East Sayre – North Waverly 115 kV Relay; and Warren – Falconer 115 kV RelaySection 5: Added reference to PPL company document for Jenkins SPS
• Section 5: Updated UGI/PL 66kV Tie Line Operation based on new line clearance point
• Section 5: Updated references for C-3403 line termination from Hudson to Marion
• Section 5: Revised PS/ConEd wheel procedure with updated line names and designations
• Section 5 and Attachment A: Updated Linwood SPS procedure based on the new Post substation
• Section 5: Added reference to PECO documentation for the Peach Bottom SPS
• Section 5: Updated PS Normally Open Bus Tie procedure due to Bergen-Linden Corridor system upgrades
• Section 5: Removed Kammer operating procedure due to system upgrade
• Section 5: Removed reference about UPFC at Inez substation due to retirement
• Section 5: Updated Rockport operating guide due to the retirement of Breed substation and added reference to AEP company document Section 5: Updated Twin Branch – Argenta (Conservative Operations) due to system upgrade
• Section 5: Added Washington plant stability restriction
• Section 5: Added projected retirement dates to applicable SPS procedures
• Section 5: Updated the ComEd East Frankfort SPS procedure
• Section 5 and Attachment A: Added SPS designation for the Lisle SPS scheme
• Section 5: Updated the Dresden 345 kV bus operation procedure
• Section 5: Added the ComEd Crawford SVC procedure
• Section 5: Updated the ISO-NE Contingencies procedure
• Attachment A: Modified BGE Concord Street SPS to reflect summer load dump ratings and ‘armed’ period of 6/1-8/31 annually
• Attachment A: Modified BGE Mt. Washington SPS to show ‘armed’ period of 6/1-8/31 annually
• Attachment A: Removed Susquehanna #1 Unit SPS due to retirement
• Attachment A: Updated Planebrook SPS description to clarify stuck breaker triggers
• Attachment C: Updated notes and exhibit numbers
• Attachment D: Removed constrains that are no longer part of the Post Contingency Congestion Management Progam and added note that there are no constraints that are currently part of the program.
• Attachment E: Removed retired sectionalizing schemes at Hosensack and updated description of Jenkins 4 xfmr sectionalizing scheme.

• Manual renamed to “Additional Information for Upgrade and Transmission Interconnection Projects”
• Revised Introduction to reflect new changes made to the manual prompted by the changes to the Merchant Network Upgrade process
• Moved the previous Sections 1, 2 & 3 to the Attachments portion of the manual and made updates to reflect the current PJM Tariff structure
• Added a new Section 1 to explain the different Transmission and Upgrade project and customer types
• Added a new Section 2 to provide an overview of Transmission Interconnection Customers that are proposing Merchant Transmission Facilities
• Added a new Section 3 to provide an overview of Transmission Interconnection Customers that are proposing capability increases to specific Transmission Owner Facilities
• Added a new Section 4 to provide an overview of Upgrade projects

• Cover to Cover Periodic Review
• Removed various references to Load Serving Entity (LSE) due to NERC retirement of the term and replaced them with Distribution Provider (DP) references.
• Section 2.3.1
  • Updated the Voltage Reduction Capabilities table with numerous changes based on TO capability changes and load forecast revisions.
• Section 2.3.2 & Section 5.2
  • Added note to issue an EEA1 per EOP-002 if non-firm sales are curtailed due to emergency capacity conditions.
  • Added the term “Action” to Step 4A for consistency
  • Correctly referenced non-critical, not non-essential, station light and power.
  • Added a new Step 7: Deploy All Resources Action and renumbered subsequent “Steps” as well as updated Exhibit 1 accordingly.
• Section 3.3 Cold Weather Alert & Section 3.4 Hot Weather Alert
  • Added bullet to tie back to M-10 regarding updates to the ‘early return time’ for Planned generator outages.
• Section 3.7 GMD Operating Plan
  • Noted that TO GMD plans should be submitted via the process indicated in M-1 Attachment B
• Section 5.4
  • Updated “NOTE” to point to Section 5.7 for the Load Shed Directive process/
• Section 5.4.1
  • Added a NOTE to clarify priority for controlling the contingency overload and then running the Post Contingency Exceedance Analysis if needed.
  • Removed superfluous reference to M-03
• Section 5.5
  • Renamed ComEd interface to CE-East interface
• Section 5.7: Load Shed Procedure
  • This is a new section of the manual that was previously contained within M-03. The language was shorted for ease of use.
• Updated Attachment E with 2016 Load Dump Allocation numbers
• Updated Attachment F with 2016 Load Dump capability numbers
• Attachment G Capacity Emergency Matrix
  • Deleting this attachment. All information is already contained within Section 2.3.2.
• Corrected the revision histories for versions 53 – 58 to reflect the periodic reviews performed in system operations and reviewed through the SOS, OC, and MRC in 2015, 2014 and 2013

• Administrative Change - Updated references from eMKT to Markets Gateway
• Administrative Change – Updated references from eFTR to FTR Center
• Attachment L: Jointly Owned Resource Communication Model – Revised to include additional details for Option 2

• Added Attachment F: Dynamic Transfers
• Administrative Change:
  • Updated references from eMkts to Markets Gateway
  • Updated references from eMeter to Power Meter

• Updated to revise Attachment G, Section 9.6.

• Section 3: Corrected formulas in the End-Use/Weather Variables section
• Attachment B: Removed due to expiration of load research guidelines. The former Attachments C and D have been re-lettered.

• Updated references to GMS, Generation Management System, to VBUCC, Virtual Backup Control Center
• Updated references to Test System or Test Environment to Stage System or Stage Environment as appropriate.
• Section 1.2 changed from a description of GMS to a description of VBUCC.
• Standardized all references to “PJMNET” or “PJMNet” to “PJMnet”.
• Section 2.3.1, removed reference to manual failovers.
• Section 2.3.6, removed references to the PJM ICCP Network Interface Control Document, PJM ICCP Communications Workbook and PJM ICCP NICD and Workbook.
• Section 2.5.6, spelling and typo fixes.
• Section 3.2.2, removed mention of PJM support for ICCP block 4 messages, which are not presently supported.
• Section 3.2.2, removed references to the PJM ICCP Network Interface Control Document, PJM ICCP Communications Workbook and PJM ICCP NICD and Workbook.
• Section 3.2.3, removed reference to accumulated energy values as an EMS Data Exchange.
• Section 3.2.4, updated reference to frame relay with MPLS networking technology. Removed dated reference to PVC’s. Replaced requirement to return “Welcome Letter” with kickoff conference.
• Attachment C: Notification of Member Company System Outages deleted – content updated and migrated under Section 3.8.
• Attachment D: PJM EMS Networking Rapid Response Team deleted – content updated and migrated under Section 3.8.
• Attachment C: PJMnet ICCP Failover Tests added.
• Section 3.8, Planning, Coordination and Notification of System Changes and Events added.
• Section 3.8.1, Regular Planned Member Company System Outages added.
• Section 3.8.2, Emergency and Unscheduled System Outages added.
• Section 3.8.3, Communication of Major System Changes and Events added.
• Section 3.8.4, Outage Tracking added.
• Administrative Change – updated references for eFTR to FTR Center.

• Conforming revisions for FERC Order ER16-873-000, accepted on 4/1/2016 and effective 4/1/2016 to eliminate the RRMSE requirement for Load Management registrations that will use a customer baseline to measure capacity compliance in non-summer periods.

• Revision to Section 5.2.4 and 5.3 effective 03/31/16 to provide clarification language and establish consistency with M-11 and M-15 regarding cancellation fees.

• Revisions to various sections regarding effective operating day of 04/01/2016 for Day-Ahead Market timeline changes related to dockets No. ER14-24-000 & ER15-2260-001
• Changed all timings to 24 hour format
• References to eMKT application were updated to Markets Gateway
• Revisions to sections 2.3.3 and 2.3.4 for Parameter Limited Schedule changes related to the implementation of Capacity Performance effective from 06/01/2016 (dockets No.ER15-623 and EL15-29).

• Periodic Review clarifying changes to better describe existing rules and processes
• Administrative Change – updated references for eFTR to FTR Center

• Revised Section 3.5 to include specific exceptions to the general policy regarding data postings
• Changed ownership for this manual from Lynn Horning and Vince Duane to Adrien Ford, Director, Member Relations
• Administrative Change – Updated references for eData to Data Viewer, EFTR to FTR Center and eMKT to Markets Gateway

• Conforming revisions for FERC Order ER16-333, accepted on 12/22/2015 and effective 01/16/2016 to change (1) instances in which FRR Entities would not be required to meet the Percentage of Internal Resource Requirement, (2) circumstances in which an FRR Entity can terminate its five-year minimum commitment period, and (3) the FRR Alternative election dates for new FRR Entities (Sections 11.1.3 & 11.6).

• Added Section 2.1.5.1 to reflect the inclusion of Phase Angle Regulators in Transmission Interconnection Requests
• Updated Section 2 of Attachment B to include a reference to Multi Driver Approach projects
• Updated Section 3.1 of Attachment B to address changes associated with the study methodologies for Long Term Firm Transmission Service in the New Services Queue

• Updated Attachment B, C and H for Transmission Service Study Procedures

• Periodic review: Corrected typos and grammar, revised terms for consistency, updated web link, and updated PJM reliability study procedures.
• Section 1.2: Updated interregional study.
  
  

• Annual review of PJM Training Plan (Section 4) in accordance with NERC Standard PER-005
• Administrative Change: Updated references from eData to Data Viewer
• Clarifying changes to Section 4.4 describing retesting process for Master Coordinator qualification
• Minor change to Section 4.7 to remove requirement for weekly self-assessment quiz for Reliability Engineer qualification
• Added language in Section 3.3 to indicate that a dispatcher/operator must be removed from shift responsibilities if they fail to meet the applicable requirements listed. Removed duplicate language from Section 3.2.1
• Updated language in Section 3.3 to reflect changes in Compliance Monitoring process and added flow chart
  
  

• Updates to align with NUC-001-3 (effective 01/01/2016) – Grammatical corrections; edits to be consistent with NERC documentation.
• Section 2.6: System Restoration – updated to include safe shutdown loading requirement for plant specific Nuclear Plant Interface Requirements (NPIRs) developed and endorsed by the Nuclear Generation Owners User Group (NGOUG).
• Attachment A; Appendix 1: Regulatory Background – Removed Operating Agreement (OA) and Transmission Owners Agreement (TOA) text; replaced with appropriate references to OA, TOA, and Open Access Transmission Tariff (OATT)
• Periodic Review
  
  

• Section 2.2 updated Day Ahead Scheduling Reserve requirement for RFC effective January 1, 2016
• Section 2.3, 5.2 and Attachment C and G:
  • Renamed Maximum Emergency Generation Alerts to Maximum Generation Emergency Alerts for consistency with the Tariff
  • Renamed Maximum Emergency Generation to Maximum Generation Emergency for consistency with the Tariff
  • Updated steps 8 and 9 to include the word ‘Action’ in the procedure names for clarification
• Section 2.3 Voltage Reduction Action:
  • Based on member feedback, removed indication that generators connected below 230kV participate in the voltage reduction.
• Section 3.7 Geo-Magnetic Disturbances
  • Renamed to Geo-Magnetic Disturbance (GMD) Operating Plan (EOP-010-1)
  • Renamed GIC transfer limits to GMD transfer limits.
  • Created two subsections for GMD Warnings and GMD Actions
  • Renamed “Conservative Operations” to “Geomagnetic Disturbance Action”
  • Added requirement for TOs to coordinate their GMD Operating Plans with PJM.
  • Added language to strengthen compliance with EOP-010-1
• Administrative change to update all references from eMkt (retired 1/1/2016) to Markets Gateway
• Periodic Review