• Updated Section 3.2.1 to state that both Generation and Demand Resources must be able to provide 0.1 MW of Regulation Capability in order to participate in the Regulation Market.

• Added Attachment H Power System Modeling Data

• Section 4.1 Energy Imbalance Service Accounting Overview: Updated section to comply with current version of Schedule 4 of the Tariff.

• Section 2 Locational Marginal Pricing: Renamed Section 2 Interface Pricing and incorporated settlements interface pricing information. The Locational Marginal Pricing details were moved to Manual 11 in a previously approved revision.
• Section 4.2 Regulation Credits: Added details on the regulation tolerance amounts used in the calculation of regulation lost opportunity cost credits.
• Section 5.2.1 Credits for Pool-Scheduled Generating Resources: Clarified details on credits when PJM declares a Maximum Generation Emergency or a Maximum Generation Emergency Alert.
• Section 5.2.8 Credits for Resource Providing Reactive Services: Description of reactive credits for synchronous condensers corrected for consistency with the Tariff (Attachment K – Appendix Section 3.2.3B(i)).
• Section 7 Transmission Congestion Accounting – Replaced Total PJM Congestion Charges with Total Transmission Congestion Charges for consistency with Tariff terminology (Attachment K – Appendix Section 5.1.7). Clarified negative target allocations are hourly and based on net quantities.
• Section 7.4.4 Monthly Allocation of Excess Congestion Charges – Added details on the end of Planning Period ARR and FTR transmission rights uplift charges for completeness. This information was previously only documented in Manual 6 – Financial Transmission Rights.
  

Attachment A: 24 hour data submission required and additional clarification for use of generation data to substantiate compliance (FERC Docket #: ER11-2898-000, 4/18/11). Also added revisions concerning how add backs are applied to DLC as approved by the MRC.

• Annual review of Manual

• Updated task lists in Appendix 3

• Removed old deadlines in Section 1

• Minor changes to MD training plan in Section 4

• Clarified number of test attempts in Section 4

• Revised the following Acronyms
• FCA - Forecast Applications
• LF - Load Forecast
• LFH - Load Forecast, Hourly (hourly interval for seven days)
• LFM - Load Forecast, Five Minute (five minute interval for six hours)
• NIS - Net Interchange Schedule
• NISF - Net Interchange Schedule Forecast
• NN - Neural Networks
• STLF - Short Term Load Forecast (hourly interval for seven days)
• VSTLF - Very Short Term Load Forecast (five minute interval for six hours)
• WEA - Weather Services
• WPF - Wind Power Forecast
• CDS - Cost Development Subcommittee
• PLS - Parameter Limited Schedules
• DMS - Data Management Subcommittee
• DRS - Demand Response Subcommittee
• DTS - Dispatcher Training Subcommittee
• MSS - Market Settlements Subcommittee
• RAAS - Resource Adequacy Analysis Subcommittee
• RTS - Relay Testing Subcommittee
• BSSTF - Black Start Service Task Force
• FTRTF - FTR Task Force
• IRTF - Intermittent Resources Task Force
• LMTF - Load Management Task Force
• RPPTF - Regional Planning Process Task Force
• Added the following definitions:
• Black Start Service
• Black Start Plant
• Black Start unit to conform to the definitions in the OATT
• Carrying Charges
• Cost Based Offers
• Direct Costs
• Economic Demand Response
• Emergency Demand Response
• Energy Market Opportunity Costs
• Indirect Costs
• Interconnection Queue Close Date
• Interconnection Customer
• Parameter Limited Schedules
• Pnodes
• Queue Date
• Regulation Market Clearing price (RMCP)
• Synchronized Reserve Market
• Updated Cost Development Task Force to Cost Development Subcommittee

• Section 2.6.1, Exhibit 1: Updated Handy Whitman Index Numbers for the year 2011.
• Section 9: Opportunity Cost Guideline is updated per the informational filing submitted by PJM on May 12, 2011, in Docket No. EL08-47-005.

This revision improves readability and addresses changes as a result of FERC Order 719 (Docket Nos. ER09-1063-000 and ER09-1063-001) requirements.

• Sections 1 & 2 – Updated references to Manuals
• 2.3.1 – Clarified member TO requirements for security analysis capability
• 2.4 – Clarified 3 part communication
• 2.7 – Clarified back up capability
• 4.2.4 – Clarified 3 part communication
• 5.8.1 – Updated references to Manuals
• Attachment A, H2 – Removed MAAC
• Attachment C5 – Clarified process.

• Added Section 5: DR Reliability Target Analysis Procedures.
• Updated the entire manual to reflect current analysis and modeling methods.

• Changed manager ownership to Generation Department based on reorganization.
• Attachment B: Added Perry and Davis Besse NPIR as part of ATSI Integration into PJM
• Attachment C: Updated Perry and Davis Besse NPIR revision.

• Requirement to provide meter data on a 24-hour basis during the day on which a Load Management event or performance test occurs and for all hours during any other days as required by PJM to calculate load reduction
  
  Avoiding double assessment of a penalty (penalty for both RPM Commitment Compliance and Load Management Event or Test Compliance) for a Demand Resource
  
  Modification to the load management retest rules
  
  Modification and clarification of the rules for use of Demand Resources as replacement capacity
• Confirming Revisions for FERC Order ER11-1909, accepted on 12/20/2010 and effective on 12/27/2010, to include a change to clarify the definition of an EE Resource to reflect that a project qualifying as an EE Resource is one installed at an end-use customer’s retail site.
• Revisions to EFORd used for a generation resource in the initial evaluation of a FRR Entity’s FRR Capacity Plan for a Delivery Year as approved by stakeholders at the MRC on August 5, 2010.

Updated tables in Attachments E and F which had errors in the previous posting of revision 43

• Updated Attachment N – IROL Load Dump table to reflect ATSI integration and new TRAIL line for 6/1/2011.
• Updated Attachment E
• Updated Attachment F

• Attachment A: Updated to reflect June 2010 changes to IRC reporting.

• Updated Attachment B - Initial and Hourly Restoration Reports
• Updated Attachment F - Figure 1 TO Restoration Document References
• Updated Attachment G – TO Coordination Checklist (Table 1)
• Updated Attachment H – UFLS Table
• Updated Table 1- PJM Table of Major Synchronization Devices

• Annual Review
• Revised Attachment A: OATF Scope revised to include Cleveland Public Power (CPP) and the Cleveland reactive interface.
• Revised Attachment B: Transmission Reliability Analysis Procedure Section B.2 to include specific steps to capture the impacts of MISO wind in the study case.

• Updates to reflect the integration of the ATSI zone and creation of PJM Settlement, Inc.

• Updates to reflect integration of ATSI zone and creation of PJM Settlement, Inc.

Revision 38 (04/27/2011):

Throughout – Formatting changes to tables to meet with current PJM style set.

Throughout – Replaced references to “Conectiv” with “PHI – Pepco Holdings, Inc.” or “AE-PHI” where appropriate.

Throughout – Replaced references to “Orange” with “Maliszewski” wherever the reference was to the former “Orange” 765/138kV substation within AEP.

Section 1.3 – Note added regarding TO requirements for real-time network analysis within Transmission Operations Guidelines.

Section 2.1 – Revised wording for Note1 from “may operator” to “may operate” within Thermal Operating Criteria section.

Section 2, end – Revised wording for Exhibit 1 PJM Actual Overload Thermal Operating Policy table from a Guideline to a Policy and revised text within said table to correspond with Load Shed Determination Procedure.

Section 3.2 – Revised section title from Voltage Operating Criteria & Guidelines to Voltage Operating Criteria & Policy and relevant wording within section from “Guideline” to “Policy”.

Section 3.3.3 – Clarified the Voltage Schedule and Bandwidth rows as being ‘kV’ values within the Generator Voltage Schedules table.

Section 3.8 – Reformatted the Interface line definitions for clarity within the Transfer Limits section. Added the future Mt Storm – Meadowbrook 500kV line to the AP South definition, and added the CLVLND reactive interface both with an effective date of 6/1/2011.

Section 3.9 – Revised UGI’s 69kV voltage limits within Exhibit 5: Bus and Zone Specific Variations to PJM Base Line Voltage Limits to appropriate voltage limits for their 66kV network. Added entries for ATSI and CPP for upcoming integration, effective 6/1/2011.

Section 4.2 – Inserted subsection 4.2.6 Peak Period Outage Scheduling Guidelines. To accommodate, former subsections 4.2.6 through 4.2.12 all advanced by one and are now 4.2.7 through 4.2.13.

Section 4.2.9 – Revised wording from ‘ … may loose its priority … ‘ to ‘may lose its priority’ within the Rescheduling Outages subsection.

Section 4.5 – Updated the Transmission Outage Acceleration Process to provide clarifications, aligning manual with tariff language.

Section 5 – Revised all Single Breaker Derate tables to utilize standardized ‘NL’, ‘EM’, ‘LT’, ‘ST’ and/or ‘LD’ limit titles where appropriate within the Operating Procedures for all Transmission Zones with applicable Single Breaker Derate tables.

Section 5 – Added Load Shed Determination Procedure and Load Shed Directive within the Operating Procedures for the PJM RTO and applicable index tables.

Section 5 – Corrected wording in reference to the “J” and “K” lines in the PSEG/ConEd Wheel within the Operating Procedure for the PJM RTO.

Section 5 – Revised NL & EL voltage limits for the Dresden units 2 & 3 in Voltage Control at Nuclear Stations within the Operating Procedures for the PJM RTO. Added Davis-Besse and Perry in same section effective upon ATSI integration, 6/1/2011.

Section 5 – Added a Directional Ratings procedure within the Operating Procedures for the AE Transmission Zone and applicable index tables.

Section 5 – Added AEP Single Breaker Derates within the Operating Procedures for the AEP Transmission Zone and applicable index tables.

Section 5 – Updated the Smith Mountain 138kV Station Stability procedure within the Operating Procedures for the AEP Transmission Zone.

Section 5 – Updated to classify Fast Valving and Emergency Unit Tripping as part of the overall SPS at Rockport in the Rockport Operating Guide within the Operating Procedures for the AEP Transmission Zone.

Section 5 – Revised the Twin Branch – Argenta (Conservative Operations) procedure to clearly identify the potential IROL limits within the Operating Procedures for the AEP Transmission Zone.

Section 5 – Renamed/Revised the Pleasants and Oak Grove Operating Restrictions to the Belmont SPS within the Operating Procedures for the AP Transmission Zone and applicable index tables to reflect the redundancy added to the preexisting relay scheme.

Section 5 – Added Bus Voltage Exceptions within the Operating Procedures for the AP Transmission Zone and applicable index tables.

Section 5 – Added/Revised rating sets for Bedington, Belmont, Black Oak, Cabot, Doubs, Ft Martin, Harrison, Hatfield, Meadowbrook, Pruntytown, South Bend, Wylie Ridge & Yukon 500kV CBs in the Breaker Derate Table within the Operating Procedures for the AP Transmission Zone.

Section 5 – Revised the ratings with one breaker in service for the Waugh Chapel – Calvert Cliffs ‘5052’ 500kV line in the Breaker Derate Table within the Operating Procedures for the BC Transmission Zone.

Section 5 – Added a DPL Transmission Zone section within the Operating Procedures and applicable index tables.

Section 5 – Added a Directional Ratings procedure within the Operating Procedures for the DPL Transmission Zone and applicable index tables.

Section 5 – Added Note, explaining limitation of one pump per GSU for a duel pump trip, to Bath County SPS procedure within the Operating Procedures for the DOM Transmission Zone.

Section 5 – Added an FE-ATSI Transmission Zone section within the Operating Procedures with an Effective Date of the PJM-ATSI/CPP Integration, 6/1/2011. Added to all applicable index tables.

Section 5 – Added Mansfield Unit Stability Restrictions and Richland Substation SPS within the Operating Procedures for the FE-ATSI Transmission Zone and applicable index tables.

Section 5 – Removed TMI Voltage Notification Procedures, as the limits for 1 Auxiliary Transformer and 2 Auxiliary Transformers are now the same, within the Operating Procedures for the FE Transmission Zone[h1] and applicable index tables.

Section 5 – Renamed/Reordered Operating Procedures and associated index tables for FE Transmission Zones.

Section 5 – Added the Homer City Stability Limits within the Operating Procedures for the FE Transmission Zone and applicable index tables.

Section 5 – Revised the table and procedure based upon most recent study results in the Conemaugh/Hunterstown Stability Limits within the Operating Procedures for the FE Transmission Zone.

Section 5 – Revised wording from “500 Conemaugh – Keystone 500kV line” to “5003 Conemaugh – Keystone 500kV line” in the Conemaugh #2 Stability Trip within the Operating Procedures for the FE Transmission Zone.

Section 5 – Clarified control modes for the 138kV Capacitor Banks for the Elmhurst SVC within the Operating Procedures for the ComEd Transmission Zone.

Section 5 – Removed reference to retired SPOGs 1-3-I-1 and 1-8 within the Operating Procedures for the ComEd Transmission Zone.

Section 5 – Removed reference to retired SPOG 1-3-C-1 from Quad Cities and Cordova Stability Limitations [SPS] within the Operating Procedures for the ComEd Transmission Zone.

Section 5 – Removed retired SPOG 3-21 107_Dixon ‘L15621’ 138 kV CB Operation within the Operating Procedures for the ComEd Transmission Zone and applicable index tables.

Section 5 – Added Wolfs TR81 [SPS] within the Operating Procedures for the ComEd Transmission Zone and applicable index tables.

Section 5 – Revised and renamed the former Sandwich 138kV Bus Tie Circuit Breaker [SPS] to Wolfs Crossing-Sandwich 138kV 14302 line [SPS] due to changes associated with the SPS and the applicable ComEd SPOG 3-31 within the Operating Procedures for the ComEd Transmission Zone and applicable index tables.

Section 5 – Added Electric Junction – North Aurora 138kV 11106 line [SPS] due to changes associated with SPOG 3-27 within the Operating Procedures for the ComEd Transmission Zone and applicable index tables.

Section 5 – Added Highland Park Transfer Trip [SPS] within the Operating Procedures for the ComEd Transmission Zone and applicable index tables.

Section 5 – Added Zion Generation Stability Trip [SPS] within the Operating Procedures for the ComEd Transmission Zone and applicable index tables.

Section 5 – Added Camp Grove Islanding within the Operating Procedures for the ComEd Transmission Zone and applicable index tables.

Section 5 – Removed the Elrama 138/69kV Auto Transformer Operation procedure within the Operating Procedures for the DLCO Transmission Zone and applicable index tables due to transformer replacement.

Section 5 – Revised the Common Trench Cable Ratings within the Operating Procedures for the PEPCO Transmission Zone.

Section 5 – Revised status to normally ‘Disabled; And, Enabled as needed’ for the Peach Bottom ‘45’ 500kV CB SPS and the Peach Bottom ‘35’ 500kV CB SPS within the Operating Procedures for the PE Transmission Zone[h2] .

Section 5 – Removed 2 lines pertaining to North & South bus outage restrictions and applicable Note from the Montour Stability Restrictions within the Operating Procedures for the PL Transmission Zone.

Section 5 – Removed the Hosensack – Buxmont 230kV Line Contingency procedure within the Operating Procedures for the PL Transmission Zone and applicable index tables as the scheme is no longer required and has been disabled.

Section 5 – Associated the PSE&G Artificial Island Stability procedure with the A.I. (Salem) Cross Trip Scheme and designated it as an [SPS] within the Operating Procedures for the PS Transmission Zone.

Section 5 – Removed the 500kV ‘3-4’ & ‘4-4A’ CBs @ Branchburg, the New Freedom 500kV ‘2-6’, ‘2-8’ & ‘9-10’ CB, the 138kV ‘4-5’ & ‘5-6’ CB @ Trenton and the 230kV ‘1-5’ & ‘5-6’ CBs @ Linden; Added the 500kV ‘2-6’ & ‘5-6’ CBs @ Deans; Revised the 500kV ‘1-3’ CB @ Hope Creek; All within the Breaker Derate Table for the PS Transmission Zone.

Section 5 – Revised to reflect area upgrades the Operation of 23030 Tie at Mountain and UGI/PL 66kV Tie Line Operation procedures within the Operating Procedures for the UGI Transmission Zone. Removed the Hunlock Outlet Overloads procedure from same.

Section 5 – Properly identified the Clover Generation Shed Scheme as an “[SPS]” within the Operating Procedures for the VP Transmission Zone.

Attachment B – Open Circuit Terminal Voltage Control table updated to reflect present PJM EHV lines.

Attachment E – Added Automatic Sectionalizing Schemes for the PPL & UGI Transmission Zone which are effective as of March 1, 2011. Removed three Automatic Sectionalizing Schemes related to the Matt Funk 345kV for the AEP Transmission Zone due to upgrades.

Exhibits – Added wording to indicate the Juniata PLC trip for high voltage is currently off within Exhibit 4: Capacitor Installations with PLCs.

• Revisions made to reflect integration of the ATSI zone into the PJM footprint.

• Correct adjusted obligation formulae in Sections 4 (Regulation) and 19 (Day-ahead Scheduling Reserve).

• Annual Review
• Removed OVEC from PJM RC footprint.
• Added the CLVLND Reactive Transfer Interface within table in Section 3.1 SOL and IROL Limit Determination.
• Updated Attachment A: PJM RTO Reliability Plan.
• Updated the IROL definition in section 3.1 to match the NERC Glossary of Terms

• Revisions for ATSI integration (Sections 2.3.1, 2.3.4, 3.3.1, and Attachment B)

Revision 09 incorporates: (1) increased detail regarding Generator Power Factor Requirements, (2) a new Attachment H: Generator Reactive Deficiency Mitigation Process, and (3) a clarification to the interconnection cost allocation process.

• Added references where appropriate to reflect the inclusion of the American Transmission Systems, Inc. (ATSI) and Cleveland Public Power (CPP).
• Clarified the methodology to establish an IROL in the Planning Horizon.
• Updated the short circuit methodology to include the existing process to study all BES breakers.

• Section 3: Integrated the description of the net energy forecast model into the general model description.
• Revised Exhibits 2 and 3 to reflect updated economic and weather station mappings.
• Attachment A: Revised load drop estimate guidelines based on Load Management Task Force proposal approved at November 2010 Markets and Reliability Committee and January 2011 Members Committee. Corresponding tariff language changes were filed with FERC under Docket ER11-2898-000.

• Section 1: Updated for changes required by NERC MOD standard changes. Remove duplication of OASIS information already contained in the Regional Practices. Added PJM ATC Methodology Contact.
• Section 2: Updated for changes required by NERC MOD standard changes.
• Section 3: Updated for changes in Long term Firm Evaluation Process and Deliverability process is described in detail in Manual 14B.
• Updated various hyperlinks to PJM and OASIS website due to changes in domain.

• Section 2.2 was expanded to include the physical location of substation equipment, including state and GPS coordinates.
• The Electrical Models section of Appendix C ‗Bulk Electric System (BES) Implementation at PJM‘ was modified to discuss modeling and monitoring very low impedance equipment.
• Appendix A, TERM processing ratings data information concerning processing of temporary ratings changes was expanded.

• Section 2.2 – updated 2011 DASR % to 7.11%

• Added reference to Manual 40 in section 2.6
• Revision to 2.7 – changed 2 hours to 1 hour (EOP-008)
• Revisions to 4.2.4 for 3 part communications