Transmission Interconnection Handbook - PG&E

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Transmission Interconnection Handbooks For NERC Reliability Compliance Program

Pacific Gas and Electric Company Combined Version Effective Date: January 25, 2012

PG&E Transmission Interconnection Handbook

Table of Contents TABLE OF CONTENTS ................................................................................................................................ I UPDATE HISTORY ...................................................................................................................................... 1 INTRODUCTION........................................................................................................................................... 4 I-1. PURPOSE .......................................................................................................................................... 4 I-2. INTRODUCTORY DEFINITIONS ....................................................................................................... 4 I-3. HANDBOOK APPLICABILITY ............................................................................................................ 5 I-3.1. New Load Facilities ..................................................................................................................... 5 I-3.2. New Transmission Facilities ........................................................................................................ 5 I-3.3. New Generation Facilities ........................................................................................................... 5 I-3.4. Existing Load Facilities ................................................................................................................ 5 I-3.5. Existing Transmission Facilities .................................................................................................. 6 I-3.6. Existing Generation Facilities ...................................................................................................... 6 I-4. ELECTRIC INDUSTRY RESTRUCTURING....................................................................................... 7 I-5. PROCEDURES FOR DEVELOPING TRANSMISSION PLANS AND COORDINATED JOINT STUDIES .................................................................................................................................................. 8 I-5.1. Procedures for Developing Transmission Plans ......................................................................... 8 I-5.2. Procedures for Coordinated Joint Studies .................................................................................. 8 I-6. ORGANIZATION OF HANDBOOKS ................................................................................................... 9 I-7. STANDARD AND PROJECT-SPECIFIC INTERCONNECTION REQUIREMENTS .......................... 9 I-8. CUSTOMER-OWNED EQUIPMENT REQUIREMENTS .................................................................. 10 I-9. COMPLIANCE WITH NERC INTERCONNECTION STANDARDS .................................................. 10 GLOSSARY ................................................................................................................................................ 13 SECTION L1-D: REVENUE-METERING REQUIREMENTS FOR DISTRIBUTION LOAD-ONLY ENTITIES .................................................................................................................................................... 30 PURPOSE .............................................................................................................................................. 30 L1-D.1. REVENUE METERING REQUIREMENTS FOR LOAD ENTITIES............................................................. 30 L1-D.1.1. Wholesale Service .............................................................................................................. 30 L1-D.1.2. End Users (Retail Service) ................................................................................................. 30 L1-D.1.2.1. PG&E Direct Access Rule 22 ...................................................................................................... 30 L1-D.1.2.2. PG&E, as an MSP, will provide, install, maintain and test the following meter equipment .......... 31 L1-D.1.2.3. PG&E, as an MDMA, will provide the following meter data services ........................................... 31 L1-D.1.2.4. All PG&E Load Entities will provide, install and maintain ............................................................ 32

L1-D.2. REQUIREMENTS OF REVENUE-METERING POINT ............................................................................ 33 L1-D.3. COMMUNICATION CIRCUITS ........................................................................................................... 33 L1-D.4. GROUND POTENTIAL RISE ............................................................................................................ 34 SECTION L1-T: REVENUE-METERING REQUIREMENTS FOR TRANSMISSION-ONLY AND LOADONLY ENTITIES ......................................................................................................................................... 35 PURPOSE .............................................................................................................................................. 35 L1-T.1. REVENUE-METERING REQUIREMENTS FOR LOAD ENTITIES AND TRANSMISSION ENTITIES CONNECTING LOAD TO THE PG&E TRANSMISSION SYSTEM ....................................... 35 L1-T.1.1. Wholesale Service .............................................................................................................. 35 L1-T.1.2. End User (Retail Service) ................................................................................................... 35 L1-T.1.2.1. Bundled Service .......................................................................................................................... 36 L1-T.1.2.2. Direct Access Service .................................................................................................................. 36 L1-T.1.2.3. Equipment Requirements: ........................................................................................................... 37

L1-T.1.3. Additional Requirements ..................................................................................................... 38 L1-T.2. LOCATION OF REVENUE METERING POINT...................................................................................... 39 L1-T.3. COMMUNICATIONS CIRCUITS ......................................................................................................... 40 FORM L1-1 ................................................................................................................................................. 41

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PG&E Transmission Interconnection Handbook

SECTION L2: PROTECTION AND CONTROL REQUIREMENTS FOR LOAD-ONLY ENTITIES AND TRANSMISSION-ONLY ENTITIES ............................................................................................................ 44 PURPOSE .............................................................................................................................................. 44 APPLICABILITY ...................................................................................................................................... 44 L2.1. PROTECTIVE RELAY REQUIREMENTS ..................................................................................... 44 L2.2. RELIABILITY AND REDUNDANCY ............................................................................................... 46 L2.3. RELAY SPECIFICATIONS RELIABILITY AND REDUNDANCY ................................................... 46 L2.4. LINE PROTECTION....................................................................................................................... 47 L2.4.1. Fault-Interrupting Devices ...................................................................................................... 48 L2.4.1.1. Circuit Breakers .............................................................................................................................. 49 L2.4.1.2. Circuit Switchers ............................................................................................................................. 49 L2.4.1.3. Fuses .............................................................................................................................................. 49

L2.5. STANDBY/BACKUP SOURCE ...................................................................................................... 50 L2.5.1. Standby Source ...................................................................................................................... 50 L2.5.2. Backup Generators ................................................................................................................ 51 SECTION L3: SUBSTATION DESIGN FOR LOAD-ONLY ENTITIES AND TRANSMISSION-ONLY ENTITIES .................................................................................................................................................... 52 PURPOSE .............................................................................................................................................. 52 L3.1. DEAD-END STRUCTURE ............................................................................................................. 52 L3.2. TRANSFORMERS ......................................................................................................................... 52 L3.3. VOLTAGE REGULATION .............................................................................................................. 53 L3.4. POWER FACTOR .......................................................................................................................... 53 L3.5. CIRCUIT BREAKER OR OTHER FAULT INTERRUPTING DEVICES .......................................... 53 L3.6. SWITCHES .................................................................................................................................... 54 L.3.6.1. Manual Disconnects .............................................................................................................. 54 L3.6.2. Tap Switch .............................................................................................................................. 55 L3.6.3. Line Selector Switches ........................................................................................................... 55 L3.7. INTERCONNECTION OF LOAD ENTITY’S OR TRANSMISSION ENTITY’S SUBSTATION WITH PG&E’S SYSTEM ................................................................................................................................... 55 L3.8. LOAD ENTITY OR TRANSMISSION ENTITY INTERFERENCE WITH POWER QUALITY ......... 56 SECTION L4: OPERATING PROCEDURES AND REQUIREMENTS FOR LOAD-ONLY AND TRANSMISSION-ONLY ENTITIES ............................................................................................................ 57 PURPOSE .............................................................................................................................................. 57 APPLICABILITY ...................................................................................................................................... 57 L4.1. JURISDICTION OF THE ISO AND THE DESIGNATED PG&E CONTROL CENTER ................... 57 L4.2. COMMUNICATIONS ..................................................................................................................... 57 L4.3. ATTENDED LOAD FACILITIESOR TRANSMISSION FACILITIES REQUIREMENTS ................. 58 L4.3.1. Voltage Control Device Operation and Special Service Requirements ................................. 58 L4.3.2. Connecting and Separating from the Power System ............................................................. 58 L4.3.3. Clearances and Switching Requests ..................................................................................... 58 L4.3.4. Unusual or Emergency Conditions ......................................................................................... 58 L4.3.5. Other Communications ........................................................................................................... 59 L4.4. UNATTENDED LOAD FACILITIES REQUIREMENTS .................................................................. 60 L4.4.1. Verification of Energized Circuit ............................................................................................. 60 L4.4.2. Separation/Restoration ........................................................................................................... 60 L4.5. SPECIAL SERVICE REQUIREMENTS ......................................................................................... 60 L4.6. LOAD ENTITY OR TRANSMISSION ENTITY INTERFERENCE WITH POWER QUALITY ......... 60 SECTION L5: PRE-ENERGIZATION TEST PROCEDURES FOR LOAD-ONLY ENTITIES AND TRANSMISSION-ONLY ENTITIES ............................................................................................................ 62 PURPOSE .............................................................................................................................................. 62 L5.1. TESTS REQUIRED FOR LOAD ENTITIES PRIOR TO ENERGIZING .......................................... 62 L5.1.1. Proving Insulation ................................................................................................................... 62 L5.1.2. Proving Ratios ........................................................................................................................ 63

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L5.1.3. Circuit Breakers and Circuit Switchers ................................................................................... 63 L5.1.4. Current Transformers and Current Circuits ............................................................................ 63 L5.1.5. Relays ..................................................................................................................................... 64 L.5.1.6. Primary Disconnect Switch.................................................................................................... 64 L5.2. ENERGIZING ................................................................................................................................. 64 L5.3. GENERAL NOTES ......................................................................................................................... 65 CONTACT INFORMATION SHEET ................................................................................................................. 66 SECTION G1: METERING REQUIREMENTS FOR TRANSMISSION GENERATION ENTITIES .......... 67 PURPOSE: ............................................................................................................................................. 67 APPLICABILITY ...................................................................................................................................... 67 G1.1. BASIC METERING REQUIREMENTS FOR GENERATORS ....................................................... 67 G1.2. DETAILED METERING REQUIREMENTS FOR GENERATORS ................................................ 69 G1.2.2. Metering Configurations For New Generators....................................................................... 69 G1.2.3. Metering Requirements For New Generators ....................................................................... 69 G1.2.3.1. Wholesale Generators ................................................................................................................... 69 G1.2.3.2. Metering Generator’s Loads ........................................................................................................... 70

G1.3. TELEMETERING REQUIREMENTS FOR GENERATOR MONITORING .............................................. 70 G1.3.1. For New Generation Facilities 1,000 kW or Greater ............................................................. 70 G1.3.2. For New Generation Facilities Less Than 1,000 kW ............................................................. 71 G1.4. METERING CURRENT AND VOLTAGE TRANSFORMERS FOR GENERATORS..................... 71 SECTION G2: PROTECTION AND CONTROL REQUIREMENTS FOR TRANSMISSION GENERATION ENTITIES .................................................................................................................................................... 74 PURPOSE ................................................................................................................................................. 74 APPLICABILITY .......................................................................................................................................... 74 G2.1. PROTECTIVE RELAY REQUIREMENTS ................................................................................................ 74 G2.2. RELIABILITY AND REDUNDANCY ........................................................................................................ 77 G2.3. RELAY GRADES ............................................................................................................................... 77 G2.4. LINE PROTECTION ........................................................................................................................... 78 G2.5. GENERATOR PROTECTION AND CONTROL .......................................................................................... 80 G2.5.1. Phase Overcurrent ................................................................................................................ 82 G2.5.2. Over/Undervoltage Relay ...................................................................................................... 82 G2.5.3. Over/Underfrequency Relay .................................................................................................. 82 G2.5.4. Ground and Phase Fault Sensing Scheme ........................................................................... 82 G2.5.4.1. General: ......................................................................................................................................... 82 G2.5.4.2. Ground Grid Requirements ............................................................................................................ 82

G2.5.5. Overcurrent Relay with Voltage Restraint/Voltage Control or Impedance Relay .................. 83 G2.5.6. Reverse Power Relay ............................................................................................................ 83 G2.6. DEDICATED TRANSFORMER.............................................................................................................. 83 G2.7. MANUAL DISCONNECT SWITCH......................................................................................................... 84 G2.7.1. General .................................................................................................................................. 84 G2.7.2. Specifications ........................................................................................................................ 85 G2.8. FAULT-INTERRUPTING DEVICES........................................................................................................ 85 G2.8.1. Circuit Breakers ..................................................................................................................... 85 G2.8.2. Circuit Switchers .................................................................................................................... 86 G2.9. SYNCHRONOUS GENERATORS .......................................................................................................... 86 G2.9.1. Synchronizing Relays ............................................................................................................ 86 G2.9.1.1. Automatic Synchronizers Approved by PG&E See Table G2-4 for PG&E-approved devices. ....... 86 G2.9.1.2. Automatic Synchronizers (not on PG&E’s approved list) Supervised by a PG&E-Approved Synchronizing Relay ...................................................................................................................................... 87 G2.9.1.3. Manual Synchronization Supervised by a Synchronizing Relay ..................................................... 87 G2.9.1.4. Manual Synchronization With Synch-Check Relay ........................................................................ 87

G2.9.2. Frequency/Speed Control...................................................................................................... 88 G2.9.3. Excitation System Requirements .......................................................................................... 88 G2.9.4. Voltage Regulator .................................................................................................................. 89 G2.9.5. Power Factor Controller ......................................................................................................... 89

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G2.9.6. Event Recorder ...................................................................................................................... 90 G2.10. SPECIAL PROTECTION SYSTEMS ..................................................................................................... 90 G2.11. REMEDIAL ACTION SCHEME (RAS) PARTICIPATION REQUIREMENT FOR GENERATION FACILITIES ............................................................................................................................................. 90 G2.12. INDUCTION GENERATORS .............................................................................................................. 91 G2.13. DC GENERATORS ..................................................................................................................... 91 G2.13.1. Inverters Capable of Stand-Alone Operation ...................................................................... 91 G2.13.2. Inverters Incapable of Stand-Alone Operation .................................................................... 92 G2.14. EMERGENCY GENERATOR REQUIREMENTS ..................................................................................... 93 G2.14.1. “Break Before Make” ........................................................................................................... 93 G2.14.2. “Make Before Break” ........................................................................................................... 93 G2.14.3. Interconnection Requirements ............................................................................................ 93 G.2.14.3.1. Interconnection Protection Study ................................................................................................ 93 G.2.14.3.2. Transfer Switch ........................................................................................................................... 93 G.2.14.3.3. Notification and Documentation .................................................................................................. 93 G2.14.3.4. Operation/Clearance .................................................................................................................... 94 G2.14.3.5. “Break Before Make” Specific Requirements ............................................................................... 94 G2.14.3.5.1. Transfer Switch .................................................................................................................... 94 G2.14.3.6. “Make Before Break” Requirements ............................................................................................. 94 G2.14.3.6.1. Transfer Switch .................................................................................................................... 94 G2.14.3.6.2. Manual Disconnect ............................................................................................................... 95 G2.14.3.6.3. Synchronizing Function ........................................................................................................ 95 G2.14.3.6.4. Protection ............................................................................................................................. 95 G2.14.3.6.5. Dedicated Transformer ......................................................................................................... 96

G2.15. PARALLEL-ONLY (NO SALE) GENERATOR REQUIREMENT ................................................................. 96 G2.16. GENERATION ENTITY-OWNED PRIMARY OR TRANSMISSION VOLTAGE TAP LINES (60 KV AND ABOVE) ..................................................................................................................................................... 96 G2.17. PG&E PROTECTION AND CONTROL SYSTEM CHANGES WHICH MAY BE REQUIRED TO ACCOMMODATE GENERATOR INTERCONNECTION ....................................................................... 97 G2.18. DIRECT TELEPHONE SERVICE ............................................................................................... 97 G2.19. STANDBY STATION SERVICE .................................................................................................. 98 G2.20. STATION BATTERY ................................................................................................................... 98 SECTION G3: OPERATING REQUIREMENTS FOR TRANSMISSION GENERATIN ENTITIES ........ 110 PURPOSE ............................................................................................................................................ 110 APPLICABILITY ........................................................................................................................................ 110 G3.1. REACTIVE AND VOLTAGE COLTROL REQUIREMENTS FOR GENERATORS ..................... 110 G3.1.1. Synchronous Generator Control .......................................................................................... 111 G3.1.1.1. Frequency/Speed Control ............................................................................................................ 111 G3.1.1.2. Voltage Control ............................................................................................................................ 111 G3.1.1.3. Power System Stabilizer Operating Requirements For Generators ............................................. 111 G3.1.1.4. Power Factor Control ................................................................................................................... 111

G3.1.2. Non-Synchronous Generator Control (without Var Control) ................................................ 112 G3.1.2.2. Induction Generators Larger Than 40 kW .................................................................................... 112

G3.1.3. Inverter-Based Generating Facilities ................................................................................... 112 G3.2. GENERATOR STEP-UP TRANSFORMER ................................................................................ 113 G3.3. POWER QUALITY REQUIREMENTS ........................................................................................ 113 G3.3.1. Voltage Fluctuation Limits ................................................................................................... 113 G3.3.2. Harmonic Limits ................................................................................................................... 113 G3.4. VOLTAGE RIDE-TROUGH REQUIREMENTS ........................................................................... 114 SECTION G4: OPERATING PROCEDURES FOR TRANSMISSION GENERATION ENTITIES ......... 115 PURPOSE ............................................................................................................................................ 115 APPLICABILITY ........................................................................................................................................ 115 G4.1. JURISDICTION OF THE CAISO AND THE PG&E GRID CENTER (GCC) ................................. 115 G4.2. COMMUNICATIONS................................................................................................................... 115 G4.2.1. Daily Capacity and Energy Reports .................................................................................... 116

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G4.2.2. Voltage Control Operation and Other Service Requirements ............................................. 116 G4.2.3. Paralleling to and Separating from PG&E (Attended Generating Facilities Only) ............... 117 G4.2.4. Clearances and Switching Requests ................................................................................... 117 G4.2.5. Unusual or System Emergency Conditions ......................................................................... 117 G4.2.6. Emergency/Backup Generators .......................................................................................... 118 G4.2.7. Other Communications ........................................................................................................ 118 G4.3. UNATTENDED GENERATING FACILITIES ............................................................................... 119 G4.3.1. Verification of Energized Circuit .......................................................................................... 119 G4.3.2. Loss of Power/Automatic Re-paralleling ............................................................................. 119 G4.3.3. Event Recorder .................................................................................................................... 120 G4.4. PROCEDURES ON TRANSFER TRIP PROTECTION FOR GENERATION FACILITIES ......... 120 G4.4.1. Purpose and Definition ........................................................................................................ 120 G4.4.2. Separation Following Loss of Transfer-Trip Protection ....................................................... 121 G4.4.3. Procedures .......................................................................................................................... 121 G4.4.4. Separation Orders ............................................................................................................... 122 G4.4.5. Non-Compliance Separation Order ..................................................................................... 122 G4.4.5. Re-parallel of Generating Facility After Restoration of TT Protection ................................. 122 G4.5. GENERATION ENTITY INTERFERENCE WITH POWER QUALITY ......................................... 122 SECTION G5: ENERGIZATION AND SYNCHRONIZATION REQUIREMENTS FOR TRANSMISSION GENERATION ENTITIES ......................................................................................................................... 124 PURPOSE ............................................................................................................................................ 124 G5.1. TEST RESULTS AND/OR INFORMATION REQUIRED PRIOR TO PRE-PARALLEL TESTING .............................................................................................................................................................. 124 G5.1.1. Proving Insulation ................................................................................................................ 124 G5.1.2. Proving Ratios ..................................................................................................................... 125 G5.1.3. Circuit Breakers and Circuit Switchers ................................................................................ 125 G5.1.4. Current Transformers and Current Circuits ......................................................................... 125 G5.1.5. Relays .................................................................................................................................. 126 G5.1.6. Primary Disconnect Switch .................................................................................................. 126 G5.1.7. RTU/RIG/DPU ..................................................................................................................... 126 G5.1.8. Station Battery ..................................................................................................................... 126 G5.2. PRE-PARALLEL TEST ............................................................................................................... 126 G5.2.1. Functional Tests .................................................................................................................. 127 G5.2.2. Impedance and Directional Relay Tests .............................................................................. 127 G5.2.3. Generator Load Tests.......................................................................................................... 128 G.5.2.4. Data Telemetry Tests ......................................................................................................... 128 G5.3. REQUIREMENTS FOR COMMERCIAL (PARALLEL) OPERATION .......................................... 128 G5.3.1. Clearance for Parallel Operation (For Testing Purposes Only) ........................................... 128 G5.3.2. Power System Stabilizer (PSS) ........................................................................................... 129 G5.3.3. Model Testing and Validation Report .................................................................................. 130 G5.3.4 Permission for Parallel Operation ................................................................................... 131 G5.4. GENERAL NOTES ...................................................................................................................... 131 SECTION G6: SITING POLICY AND REQUIREMEENTS FOR TRANSMISSION GENERATION ENTITIES .................................................................................................................................................. 137 PURPOSE ............................................................................................................................................ 137 APPLICABILITY .................................................................................................................................... 137 POLICY ................................................................................................................................................. 137 G6.1. CRITERIA FOR NEW OR PROPOSED RE-POWERING PROJECTS ....................................... 137 G6.1.1. 60/70 kV, 115kV, 230kV & 500kV TRANSMISSION FACILITIES ...................................... 137 G6.1.2. GENERATOR TAP LINES .................................................................................................. 137 APPENDIX A: WHERE TO OBTAIN REFERENCE DOCUMENTS AND INFORMATION ................... 138 APPENDIX B: INSTALLATION REQUIREMENTS FOR TIME METERED INTERRUPTIBLE SERVICE .................................................................................................................................................................. 139

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APPENDIX C: METERING TRANSFORMER UNITS AND TYPICAL PRIMARY METERING INSTALLATIONS ..................................................................................................................................... 139 APPENDIX D: ENGINEERING NUMBERED DOCUMENTS ................................................................. 140 APPENDIX E: SUBSTATION GROUNDING REQUIREMENTS ............................................................ 141 APPENDIX F: TELEMETERING AND TRANSFER TRIP FOR TRANSMISSION GENERATION ENTITIES .................................................................................................................................................. 142 F.1. APPLICATIONS ............................................................................................................................. 142 F.2. GENERAL REQUIREMENTS ........................................................................................................ 142 F2.1. EMS/SCADA Telemetering ..................................................................................................... 142 F2.1.1. Telemetering for New Generation Facilities 1,000 kW or Greater.................................................... 143

F2.2. Protection ................................................................................................................................ 144 F2.3. Business Telephone ................................................................................................................ 146 F2.4. Environmental Considerations. ............................................................................................... 146 F.3. INSTALLATION OF TELEPHONE COMPANY ENTRANCE CABLE IN SUBSTATIONS ............. 147 F.4. CIRCUIT REQUIREMENTS FOR PROTECTIVE RELAYING AND EMS/SCADA CIRCUITS INSTALLED BETWEEN GENERATION FACILITY STATIONS AND PG&E POWER SUBSTATIONS148 APPENDIX G: DISCONNECT DEVICES ................................................................................................ 160 APPENDIX H: POWER SYSTEM STABILIZER ..................................................................................... 161 APPENDIX I: LOAD OPERATING AGREEMENT .................................................................................. 162 PURPOSE ............................................................................................................................................... 162 APPLICABILITY ........................................................................................................................................ 162 APPENDIX J: SPECIAL AGREEMENT FOR ELECTRICAL STANDBY SERVICE .............................. 163 PURPOSE ............................................................................................................................................... 163 APPLICABILITY ........................................................................................................................................ 163 RELEVANT DOCUMENTS .......................................................................................................................... 163 APPENDIX K: LOAD SPECIAL FACILITIES AGREEMENT ................................................................. 165 APPENDIX L: INTERCONNECTION AGREEMENTS FOR GENERATORS CONNECTING TO THE ISO CONTROLLED GRID ............................................................................................................................... 169 PURPOSE AND APPLICABILITY .................................................................................................................. 169 RELEVANT DOCUMENTS .......................................................................................................................... 169 APPENDIX M: GENERATION INTERCONNECTION DATA SHEET .................................................... 170 APPENDIX N: GENERATOR DATA SHEET FOR SYNCHRONOUS GENERATORS CONNECTED TO PG&E ELECTRIC SYSTEM ..................................................................................................................... 174 APPENDIX O: TRANSMISSION LINE SELECTOR SWITCHES ........................................................... 188 APPENDIX P: ELECTRIC PRIMARY SERVICE REQUIREMENTS ...................................................... 188 APPENDIX Q: GENERATOR AUTOMATIC SYNCHRONIZERS FOR GENERATION ENTITIES ....... 189 Q1.1. OPERATION AND PERFORMANCE REQUIREMENTS ............................................................ 189 APPENDIX R: GENERATOR PROTECTIVE RELAY REQUIREMENTS .............................................. 192 R.1. REQUIREMENTS ............................................................................................................................... 192 APPENDIX S: PROTECTION ALTERNATIVES FOR VARIOUS GENERATOR CONFIGURATIONS 195 S1. STANDARD INTERCONNECTION METHODS WITH TYPICAL CIRCUIT CONFIGURATION FOR SINGLE OR MULTIPLE UNITS ..................................................................................................................................... 195 S1.1. Generator “Connected” Into a Ring Bus ................................................................................. 195 S1.2. Generator “Connected” Into a Breaker-and A-Half (BAAH) Bus ............................................ 195

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S1.3. Bus Fault Clearing .................................................................................................................. 196 S2. INTERCONNECTION METHODS WITH SPECIAL CIRCUIT CONFIGURATIONS FOR SINGLE UNIT .................. 196 S2.1. Alternative--Generator “Tapping” To Existing Transmission Line between Two Terminals, considered only at voltages below 230kV ........................................................................................ 196 S2.3. Generator “Tapping” closely outside the Substation Between Two Existing Terminals ......... 197 S2.4. Generator “Connected Close” Outside the Substation with a Dedicated Line ....................... 198 S2.5. Requirements for S2.3 and S2.4 Alternatives ......................................................................... 198 S2.6. Additional Items for Consideration .......................................................................................... 199 APPENDIX T: BATTERY REQUIREMENTS FOR INTERCONNECTION TO PG&E SYSTEM ............ 200

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Update History Update Added Figure G5-1 Simplified Flow Chart of PreParallel/Parallel Test Procedure. Addition of F-35 GE device to Table G2-4 Relays for Generator Application Addition of Power Frequency Magnetic Field Immunity (ANSI/IEEE 1308-1994 (R2001) and IEC 61000-4-8), to Generator Protective Relay Requirements.

Section Section G5

Date Aug. 11, 2004

Section G2

Aug. 11, 2004

Appendix R

Aug. 11, 2004

Addition of Power Frequency Magnetic Field Immunity (ANSI/IEEE 1308-1994 (R2001) and IEC 61000-4-8) to requirements for Generator Automatic Synchronizers. Corrected references in section 2.9.4 Moved PSS test requirements to section G5.3.2

Appendix Q

Aug. 11, 2004

Section G2 Section G3, G5 Appendix H

September 21, 2004 September 21, 2004

Sections G – G5 Section G5

September 6, 2005

Section G2.3, G2.20, G5.1.8 and Appendix T Section G22, 2-3, 2-4, 2-5, Tables G201a,b, and Appendix R G2 G2, Intro.

May 10, 2006

Addition of WECC Power System Stabilizer Design and Performance Criteria. References to LGIA for FERC 2003 Compliance Correction to Impedance/Phase Angle spec in G5.1.5 Updated Battery Requirements

Update Protection requirements. Relays and Current Transformers to have nominal secondary current of 5A and 5A nominal AC input current.

Revised Tables G2-4 and G2-5 Updated Rule 21, Rule2 and 22 links in G2 and Intro. Corrected WECC and NERC names. Updated Introduction Section to explicitly include Transmission Facilities and added references to NERC Standard FAC-001-0. Updated Glossary to include definition of “Facility” and “Transmission” and updated various links. Updated Sections L1-T, L2, L3, L4 and L5 to include application to Transmission Entities.

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September 21, 2004

September 6, 2005

November 30, 2006

January 5, 2007 August 6, 2007

Introduction, October 7, 2009 Glossary

Sections L1-T, L2, L3, L4 and L5

October 25, 2009

PG&E Transmission Interconnection Handbook

Update Section G1: Added metering equipment requirements, moved telemetering requirements to Appendix F. Section G2: Added protection clarifications for Photo-Voltaic (PV) generation and inverters capable and incapable of stand-alone operation, and updated PG&E-approved devices. Section G3: reactive and voltage control requirements for PV generation, PG&E to determine automatic voltage regulator (AVR) setpoint for voltage schedules, power system stabilizers (PSS) for synchronous generators larger than 30MVA, removed VAR production requirements, power factor (PF} requirements for PV, voltage ride-through references. Section G4: Added notification requirement for failure of PSS or AVR, removed power quality requirement. Section G5: Updated pre-parallel test requirements and clarified battery discharge testing. Section L1-T: Added metering equipment requirements. Section L2: Added break-and-a-half (BAAH) and ring bus configurations. Section L3: Updated interconnection methods, added power quality clarifications, & removed “hard tap” configuration. Section L5: added test department contact list Appendix A: updated contact list Appendix B: removed and merged into Appendix D Appendix C: removed and merged into Appendix D Appendix D: updated to include everything in the old Appendices B, C, D, E, G, O, and P. Appendix E: removed and merged into Appendix D Appendix F: Added telemetering requirements that used to be Section G1. Appendix G: removed and merged into Appendix D Appendix I: updated Form 79-847 Appendix J: changed to include the Standby Service Agreement Appendix K: added notification to request the most recent Load Special Facilities Agreement Appendix L: updated to include all Generation Interconnection Agreements Appendix O: removed and merged into Appendix D Appendix P: removed and merged into Appendix D Appendix T: updated battery requirements 2

Section Date All Sections, September 2, 2010 except Sections L1-D & L4 and Appendix H, M, N, Q, R, &S

PG&E Transmission Interconnection Handbook

Update Section G4, L3, & L4: Revised/Added Power Quality Requirements Section L1-T: Added clarification for conduit material. Section G2: Revised Manual Disconnect Switch requirements. Removed reference to Figure G2-9 (outdated illustration). Section G3: Added clarification for inverter-based generating facility reactive capability requirement. Added clarification for Section G6: Added to TIH (this is a new section) Minor grammatical updates, revised Introduction language and compliance references, and added hyperlinks to common terms and entities used throughout the handbook.

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Section Sections G4, L1-T, L3, and L4

Date December 29, 2010

Sections G2, G3, & G6

April 12, 2011

Entire Handbook

January 25, 2012

PG&E Transmission Interconnection Handbook

Introduction I-1. PURPOSE The PG&E Interconnection Handbooks explain the technical requirements for interconnection of loads and generators to PG&E’s Power System. These Interconnection Handbooks document, maintain, and publish facility connection requirements to the PG&E system as required in NERC Standard FAC-001-0. They are based on applicable Federal Energy Regulatory Commission (FERC) and California Public Utilities Commission (CPUC) rules and tariffs (e.g. Electric Rules, 2, 21, and 22), as well as accepted industry practices and standards contained within the Applicable Reliability Criteria 1. In addition to providing reliability, these technical requirements are consistent with safety for PG&E workers and the public. Although these handbooks address certain aspects of interconnection cost responsibility, their scope is primarily technical and does not include the commercial requirements for receiving transmission service, distribution service, or any other electric service from PG&E. Tariffs and rules filed with the FERC and the CPUC address the rates, terms and conditions under which PG&E or the California Independent System Operator (California ISO) provides these services. If there are any inconsistencies between these handbooks and the tariffs and rules, the latter shall control.

I-2. INTRODUCTORY DEFINITIONS PG&E Power System: For the purposes of these handbooks the PG&E Power System is defined as electric transmission and/or distribution facilities owned by PG&E regardless of whether the facilities are operated by PG&E or are under the Operational Control of the California ISO. Load Entity: A person, company or corporation interconnected to PG&E’s Power System owning or operating only power consuming facilities. Transmission Entity: A person, company, or corporation interconnected to PG&E’s Power System owning or operating electrical power transmitting facilities. Generation Entity: A person, company, or corporation interconnected to PG&E’s Power System owning or operating Generation Facilities (including back-up and emergency generation). The applicable voltage levels, MW, MVAR capacity or demand at the point of interconnection are included in the relevant sections of these handbooks. Any connected entity owning or operating power consuming, transmission and power generating facilities shall be considered a Generation Entity for the purposes of these handbooks. The technical requirements for interconnection of generation sources are most comprehensive. Any Load-only entity or Transmission Entity, which is interconnected to a third party electric system having generation capabilities shall also be considered a Generation Entity for the purposes of these handbooks. Technical requirements for multi-interconnected and network systems (systems interconnected to 1

Refer to Glossary for definition of Capitalized terms.

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PG&E Transmission Interconnection Handbook

the PG&E power system in addition to a third party system) will be determined by PG&E on a case-by-case basis.

I-3. HANDBOOK APPLICABILITY These handbooks apply to Retail and Wholesale Entities which own or operate generation, transmission, and end user facilities that are physically connected to, or desire to physically connect to the PG&E Power System. Applicability is further defined by category below.

I-3.1. New Load Facilities All applicable technical requirements described or referred to in these handbooks apply to Load Entities which have not been and are not yet connected with the PG&E Power System. Additional technical requirements may apply to special business arrangements or electrical configurations of the PG&E Power System or the interconnection point(s). Any such technical specifications would be documented through an interconnection agreement.

I-3.2. New Transmission Facilities All applicable technical requirements described or referred to in these handbooks apply to Transmission Facilities which have not been and are not yet connected with the PG&E Power System. Additional technical requirements may apply to special business arrangements or electrical configurations of the PG&E Power System or the interconnection point(s). Any such technical specifications would be documented through an interconnection agreement.

I-3.3. New Generation Facilities All technical requirements described or referred to in these handbooks apply to new or decommissioned Generation Facilities. New Generation Facilities are facilities which have not been and are not yet connected with the PG&E Power System. Decommissioned generation facilities are facilities which were actively connected to the PG&E Power System in the past but are presently neither connected nor actively producing power. Additional technical requirements may apply to special business arrangements or electrical configurations of the PG&E Power System or the interconnection point(s). Any such technical specifications would be documented through an interconnection agreement. Refer to www.pge.com/b2b/newgenerator/ for information regarding procedures for generator interconnection. It is necessary for the decommissioned generator to upgrade existing equipment to adhere to these handbooks if the decommissioned Generating Entity intends on re-powering their facility.

I-3.4. Existing Load Facilities Retail: All applicable technical requirements described or referred to in these handbooks apply to existing Load Facilities which have previously established an interconnection with the PG&E Power System. To the extent these handbooks contain more stringent requirements than were in place at the time the Load Facility initially connected, the Load Entity (owner of the existing Load Facility) shall be responsible for adhering to current requirements. The cost of any 5

PG&E Transmission Interconnection Handbook

upgrading shall be born by either the Load Entity or by PG&E pursuant to applicable Electric Rules and the terms of any executed agreements between the Load Entity and PG&E. Wholesale: Existing contracts govern the technical interconnection requirements for existing wholesale loads. Unless modified through mutual agreement or unless PG&E’s current or future requirements apply pursuant to the terms of existing contract, the technical provisions of these existing agreements concerning physical interconnection remain applicable. For information concerning the interconnection and operation of loads under these agreements please contact PG&E’s Electric Transmission Contract Management Department (municipal utilities, federal power marketing agencies, and investor-owned utility agreements).

I-3.5. Existing Transmission Facilities Retail: All applicable technical requirements described or referred to in these handbooks apply to existing Transmission Facilities which have previously established an interconnection with the PG&E Power System. To the extent these handbooks contain more stringent requirements than were in place at the time the Transmission Facility initially connected, the Entity which owns the existing Transmission Facility shall be responsible for adhering to current requirements. The cost of any upgrading shall be born by either the Entity or by PG&E pursuant to applicable Electric Rules and the terms of any executed agreements between the Entity and PG&E. Wholesale: Existing contracts govern the technical interconnection requirements for existing wholesale transmission facilities. Unless modified through mutual agreement or unless PG&E’s current or future requirements apply pursuant to the terms of existing contract, the technical provisions of these existing agreements concerning physical interconnection remain applicable. For information concerning the interconnection and operation of loads under these agreements please contact PG&E’s Electric Transmission Contract Management Department (municipal utilities, federal power marketing agencies, and investorowned utility agreements).

I-3.6. Existing Generation Facilities All the applicable technical requirements described or referred to in these handbooks may not apply to existing Generation Facilities. Existing Generation Facilities are facilities which have previously established an interconnection with the PG&E Power System. Standing decisions of the CPUC grandfather the application of CPUC Electric Rule 21 2 to certain existing generators which signed certain standard offer power purchase agreements. For information concerning the interconnection and operation of generators under these agreements please contact the Utility Electric Supply Department.

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PG&E Transmission Interconnection Handbook

To the extent these handbooks contains more stringent requirements than were in place at the time the Generation Facility initially connected, the Generation Entity (owner of the existing Generation Facility) shall be responsible for adhering to current requirements only to the extent that the safety and reliability of the power system or the safety of utility employees would be jeopardized by not adhering to the current requirements. The cost of any upgrading shall be born by either the Generation Entity or by PG&E pursuant to applicable Electric Rules and/or the terms of any executed agreements between the Generation Entity and PG&E. In cases where the reliability of the PG&E Power System is jeopardized or where compliance with national, regional, or state reliability standards is mandatory, certain technical standards outlined in these handbooks may apply irrespective of PG&E’s authority to impose the interconnection requirements. Readers should be aware that the information in these handbooks is subject to change. Parties interconnecting to the PG&E Power System should verify with their PG&E representative that they have the latest versions. PG&E will not agree to interconnect new loads, transmission facilities or generators unless all technical and contractual requirements are met. Copies of the current PG&E Transmission Interconnection Handbooks (TIH) and interconnection coordination procedures are available on the PG&E website 3.

I-4. ELECTRIC INDUSTRY RESTRUCTURING Through 1996 legislation by the state of California (Assembly Bill 1890) and by subsequent order of the CPUC and related filings with the FERC, the electric service industry in California was partially deregulated. Soon after, a new non-profit corporation, the California Independent System Operator (California ISO) was created to operate the high voltage transmission facilities owned by the three California investor-owned utilities (IOUs): PG&E; Southern California Edison (SCE), and San Diego Gas & Electric (SDG&E). Since early 1998, the California ISO has assumed operational control of the three IOUs (the “ISO Controlled Grid”) and is responsible for providing transmission service to Wholesale Load, Transmission, and Generation Entities. Each of the IOUs remain responsible for interconnection of transmission and distribution facilities. The California ISO may, from time to time, work with transmission owners to develop new or modify existing technical requirements specified within these handbooks. The California ISO also reviews and comments on specific interconnection proposals to the ISO Controlled Grid and may impose specific requirements to ensure system reliability. However, persons interconnecting with transmission or distribution facilities owned by PG&E should continue to contact a representative of PG&E regarding interconnection. Several new tariffs and contracts apply to the use of transmission and distribution facilities within California: (1) the California ISO Tariff, (2) the Transmission Control Agreement (TCA), (3) the Transmission Owner Tariff of the three initial participating 3

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PG&E Transmission Interconnection Handbook

transmission owners, and (4) other agreements mandated or approved by regulatory agencies. If any provision of these FERC-accepted agreements conflict with a provision of these handbooks, the provision of the applicable FERC-accepted agreement or tariff shall take precedence. Similarly, the CPUC will continue to regulate most retail electric service and interconnections. If any provision of PG&E’s Tariffs or Electric Rules approved by the CPUC conflicts with a provision of these handbooks, the provision of the applicable rule or tariff shall take precedence. Refer to www.pge.com/b2b/newgenerator/ for information regarding procedures for generator interconnection.

I-5. PROCEDURES FOR DEVELOPING TRANSMISSION PLANS AND COORDINATED JOINT STUDIES I-5.1. Procedures for Developing Transmission Plans In accordance with the California ISO Corporation’s Tariff, Section 24, as well as the business rules set forth in the California ISO Business Practice Manual, PG&E is required to participate in the annual California ISO Transmission Planning Process (TPP). Additionally, PG&E is to perform NERC’s Transmission Planner functions, including conducting local and bulk transmission planning studies of its service area under the direction of the California ISO for inclusion in the California ISO’s TPP; propose new facilities; prepare meaningful cost estimates for proposed and alternative facilities; conduct interconnection studies, facility studies, participate in regional/sub-regional planning groups, and construct projects when designated under the CAISO Tariff. Development of PG&E’s annual transmission grid expansion plan is coordinated within the California ISO’s TPP, which encourages all interested market participants to participate and provide comments and input on PG&E’s transmission plans. The California ISO’s TPP is structured into three stages: •

Development of Unified Planning Assumptions and California ISO Study Plan



Performing technical studies for assessment of system reliability



Documentation of technical study results and development of transmission plans proposals

I-5.2. Procedures for Coordinated Joint Studies Unless there are conflicts with FERC or state standards (such as Critical Energy Infrastructure Information—CEII—and/or standards or code of conduct issues), PG&E will form ad hoc groups, distribute results, and facilitate any required meetings between the entity requesting interconnection, PG&E, California ISO, any potentially affected electric systems, and any governing authorities in accordance with the FERC Large Generation Interconnection Procedures/Agreements (LGIP/LGIA). This includes requesting potentially affected parties to participate in joint studies and following accepted WECC regional planning practices. If a potential CEII conflict arises, PG&E will require a confidentiality agreement and may require FERC approval.

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PG&E Transmission Interconnection Handbook

Results of coordinated joint studies shall be documented along with any conclusions and recommendations. Such documentation shall be retained by PG&E and shall be made available, as soon as feasible, if requested by WECC, NERC, or any other entities responsible for the reliability of the interconnected transmission system.

I-6. ORGANIZATION OF HANDBOOKS The interconnection standards are organized into three principal parts: •

The Generation Interconnection Handbook (Sections G-1 through G-6), which applies to Generation Entities and Scheduling Coordinators



The Load and Transmission Interconnection Handbook (Sections L-1 through L5), which applies to Load Facilities and Transmission Facilities



Glossary, contacts, appendices, and references

Capitalized terms used throughout these handbooks are defined in the Glossary. Figures, forms, and tables are located at the end of each Section except when otherwise noted.

I-7. STANDARD AND PROJECT-SPECIFIC INTERCONNECTION REQUIREMENTS PG&E has established standard operating, metering and equipment protection requirements for loads and generators. These handbooks cover such requirements for all transmission-level (60 kilovolts and above) Load, Transmission, and Generation Entities wishing to interconnect with the PG&E Power System. Additional, projectspecific requirements may apply. These additional requirements may vary according to the size and nature of the load, transmission facility or generator, or the local configuration of PG&E’s existing power system. These requirements, if any, will be identified through studies performed by PG&E prior to interconnection. When entities wish to connect directly to the ISO Controlled Grid, PG&E provides the California ISO with relevant information concerning the proposed interconnection (e.g. interconnection study results, etc.). PG&E will transmit any California ISO comments or suggested requirements to the entity requesting interconnection. For Generation Facilities, PG&E will also follow the relevant California ISO procedures4. The California ISO may develop its own or additional standards or requirements, in consultation with PG&E and other stakeholders, to assure consistency across the ISO Controlled Grid. PG&E will update this set of interconnection handbooks to reflect California ISO standards adopted through the process described in the California ISO Tariff. Studies will determine whether PG&E will be required to add or modify its transmission and distribution system to interconnect the requesting party. Entities requesting interconnection to the ISO Controlled Grid are responsible for the cost of necessary studies. Interconnecting entities are responsible for the cost of necessary studies and shall pay for any additions or modifications to the PG&E Power System (special 4

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PG&E Transmission Interconnection Handbook

facilities) needed for the interconnection and for those portions of the interconnection facilities owned and maintained by PG&E at the interconnecting entity’s request.. Such facilities may include metering and data processing equipment. CPUC Special Facilities Agreements for Load and Transmission Entities are included as Appendices J and K. FERC jurisdictional Special Facilities Agreements are unique to each project, but follow similar principles. Please contact your PG&E representative for details about the study process and additional data requirements which may apply.

I-8. CUSTOMER-OWNED EQUIPMENT REQUIREMENTS Interconnected Load, Transmission or Generation Entities are responsible for designing, installing, operating, and maintaining interconnection equipment they own. All protective devices necessary to protect the interconnected entity’s facilities are the responsibility of the interconnected entity. PG&E’s requirements specified in these handbooks are designed to protect PG&E facilities and maintain grid reliability pursuant to the Applicable Reliability Criteria; they are not designed to protect the facilities of any other interconnected entity. Interconnected entities must satisfy the requirements in these handbooks, applicable rules and tariffs of the CPUC, FERC, Western Electricity Coordinating Council (WECC), the North American Electric Reliability Corporation (NERC), the California ISO and any project-specific requirements of PG&E. PG&E’s review and written acceptance of the interconnected entity’s equipment specifications and detailed plans shall not be construed as confirming or endorsing the interconnected entity’s design, as warranting the equipment’s safety, durability, or reliability, or in any way relieving the interconnecting entity from its responsibility to meet the above requirements. PG&E shall not, by reason of such review or lack of review, be responsible for strength, details of design, adequacy or capacity of equipment built to such specifications, nor shall PG&E’s acceptance be deemed an endorsement of such equipment.

I-9. COMPLIANCE WITH NERC INTERCONNECTION STANDARDS NERC Standard FAC-001-0, “Facility Connection Requirements,” requirement R2.1 states the Transmission Owner shall "Provide a written summary of its plans to achieve the required system performance...throughout the planning horizon." This document represents such a written summary of PG&E’s plans to achieve the required system performance of requirement R2.1. Additionally, Requirement R2.1.1 states the written summary will address "Procedures for coordinated joint studies of new facilities and their impacts on the interconnected transmission systems." To meet this requirement, studies performed to achieve the required system performance may include, but are not limited to, short circuit, power flow, transient stability, and harmonics. With respect to coordination, the planning of interconnection installations will be coordinated through phone calls and conference calls, meetings, possible site visits, and sharing study results and data with affected transmission owners. WECC policies, procedures, and guidelines governing the coordination of plans are detailed in the WECC Overview of Policies and Procedures for Regional Planning Project Review, Project Rating Review, and Progress Reports. 10

PG&E Transmission Interconnection Handbook

Requirement 2.1.2 further states that the written summary will address “Procedures for notification of new or modified facilities to others (those responsible for the reliability of the interconnected transmission systems) as soon as feasible”. To comply with this requirement, plans for new or modified facilities will be provided to PG&E’s interconnection customer as requested and as governed by PG&E’s tariff. Additionally, plans for new or modified facilities, which can impact WECC Interconnected System operations will be provided to WECC when they can be made publicly available. Documents governing the coordination of plans, and providing models for modification of new or modified facilities include “WECC Progress Report Policies and Procedures”, “WECC Policies and Procedures for Regional Planning Project Review, Project Rating Review, and Progress Reports”, “WECC Data Preparation Procedural Manual for Power Flow and Stability Studies” , “WECC Dynamic Modeling Procedure”, and “WECC Approved Dynamic Model Library”. Requirement R3 states that PG&E “shall maintain and update these facility connection requirements as required”. These facility connection requirements shall be maintained and updated from time to time as required. All updates will be documented in the Update History available on line. Requirement R3 further states that PG&E shall make documentation of these requirements available to the users of the transmission system, WECC, and NERC on request (five business days). Documents of these requirements shall be made available to the users of the transmission system, WECC, and NERC on request (five business days). This document provides for compliance for PG&E with NERC Standard FAC-001. This section provides direction to find compliance with the requirements in FAC-001. The following Table 1.2 gives the location in this document where each requirement of FAC001 R1 and R2 is met. Some requirements are general and are addressed in many locations, but at least some of the locations are listed. Table 1. NERC Standard FAC-001 Facility Connection Requirements NERC Standard FAC-001 Requirement R1. The Transmission Owner shall … ensure compliance with NERC Reliability Standards and applicable Regional Reliability Organization, subregional, Power Pool, and individual Transmission Owner planning criteria and facility connection requirements. … R2.1. Provide a written summary of its plans to achieve the required system performance as described above throughout the planning horizon: R2.1.1. Procedures for coordinated joint studies of new facilities and their impacts on the interconnected transmission systems. R2.1.2. Procedures for notification of new or modified facilities to others (those responsible for the reliability of the interconnected transmission systems) as soon as feasible R2.1.3. Voltage level and MW and MVAR capacity or demand at point of connection. R2.1.4. Breaker duty and surge protection.

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Location in Relevant Section/Page • Introduction, I-1 • Introduction, I-3 • Introduction, I-5.1 • Introduction, I-5.2 • Introduction, I-5.2 • Introduction, I-2 • Section L2.1 & L2.4 • Section G2

PG&E Transmission Interconnection Handbook

NERC Standard FAC-001 Requirement R2.1.5. System protection and coordination.

R2.1.6. Metering and telecommunications.

R2.1.7. Grounding and safety issues. R2.1.8. Insulation and insulation coordination.

R2.1.9. Voltage, Reactive Power, and power factor control.

R2.1.10. Power quality impacts.

R2.1.11. Equipment ratings. R2.1.12. Synchronizing of facilities.

R2.1.13. Maintenance coordination.

R2.1.14. Operational issues (abnormal frequency and voltages).

R2.1.15. Inspection requirements for existing or new facilities.

R2.1.16. Communications and procedures during normal and emergency operating conditions R3. The Transmission Owner shall maintain and update its facility connection requirements as required. The Transmission Owner shall make documentation of these requirements available to the users of the transmission system, the Regional Reliability Organization, and NERC on request (five business days).

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Location in Relevant Section/Page • Section L2 • Section G2 • Appendix D • Section L1-D • Section L1-T • Section G1 • Section L2 • Section G2 • Appendix D • Section L1-D • Section L1-T • Appendix D • Section L4.3 • Section L3.3-L3.4 • Section G3 • Section L3.2 & L3.8 • Section L4.6 • Section G3.3 • Section G4.5 • Appendix D • Section L4.1 & L4.2 • Section G3 • Section G4.2 • Section L2.4 • Section L3.6 • Section L4.5 • Section L5.3 • Section G2.4, G2.7 & G2.17 • Section G4.2 • Section G5.4 • Appendix F • Appendix S • Appendix T • Section L2.1 • Section L4.3 • Section G2.1 & G2.10 • Section G4.2 • Section L5 • Section G5 • Section G6 • Section L4.2 & L4.3 • Section G4.2 • Introduction, I-7, I-8, and I-9

PG&E Transmission Interconnection Handbook

Glossary ABCDEFGHIJKLMNOPQRSTUVWXYZ ∗ Defined Term. For interpretive purposes, these words are capitalized in the body of this Handbook

A Access Charge: A charge paid by all Utility Distribution Companys (UDCs), MSSs and, in certain cases, Scheduling Coordinators delivering energy to Gross Load, as set forth in Section 7.1 of the CAISO Tariff. The Access Charge includes the High Voltage Access Charge, the Transition Charge, and the Low Voltage Access Charge ADR (Alternative Dispute Resolution): Process described in the CAISO Tariff Section 13 and the TCA Section 15 for settling disputes between parties. AGC (Automatic Generation Control): Generation equipment that automatically responds to signals from the ISO's EMS control in real time to control the power output of electric generators within a prescribed area in response to a change in system frequency, tie line loading, or the relation of these to each other, so as to maintain the target system frequency and/or the established interchange with other areas within the predetermined limits. Alternating Current (AC): That form of electric current that alternates or changes in magnitude and polarity (direction) in what is normally a regular pattern for a given time period called frequency. Ampere: The unit of current flow of electricity. Analogous to quantity per unit of time when referring to the flow of water. One ampere is equal to a flow of one coulomb per second. ∗ Applicable Reliability Criteria: The reliability standards established by NERC, WECC,

and Local Reliability Criteria as amended from time to time, including any requirements of the NERC. PG&E is a member of the WECC and is required to meet WECC Regional Reliability and NERC standards in addition to internal and ISO requirements. Automatic: Self-acting, operated by its own mechanism when actuated by some impersonal influence as, for example, a change in current strength; not manual; without personal intervention. Automatic Control: An arrangement of electrical controls which provide for opening and/or closing in an automatic sequence and under predetermined conditions; the switches which then maintain the required character of service and provide adequate protection against all usual operating emergencies. Automatic Reclosing: A feature of some circuit breakers which allows them to reclose automatically after being tripped under abnormal conditions.

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Automatic Tripping (Automatic Opening): The opening of a circuit breaker under predetermined conditions without the intervention of an operator. [Glossary Index]

B Balanced Load: An equal distribution of load on all phases of an alternating current circuit. Boost: To increase voltage. Bundled Service, or Bundled Utility Service: Traditional PG&E service: transmission and distribution capacity for delivery , energy and ancillary services Breaker: A switch which can open a circuit, usually designed for automatic operation. Business Days: Monday, Tuesday, Wednesday, Thursday, and Friday. [Glossary Index]

C Capacitance: Capacitance is developed when two charged or energized conductors are separated by a dielectric. An excess or deficiency of electrons is maintained on opposite plates of a charged capacitor. It may be said to be the property of an electrical circuit which opposes any change of voltage. Capacity: The number of amperes of electric current a wire will carry without becoming unduly heated; the capacity of a machine, apparatus, or devices is the maximum of which it is capable under existing service conditions; the load for which a generator, turbine, transformer, transmission circuit, apparatus, station, or system is rated. Capacity is also used synonymously with capability. Capacity Factor: The ratio of average load on a generating resource to its capacity rating during a specified period of time, expressed in percentages. Circuit: A conducting part through which an electric current is intended to flow. Circuit Breaker: A device for interrupting a circuit between separable contacts under normal or fault conditions. Circuit Switcher: A device for interrupting a circuit between separable contacts under normal or fault conditions. ∗ Class A Telephone Circuit: Service performance objective classification for a circuit

which is non-interruptible before, during and after a power fault condition. ∗ Class B Telephone Circuit: Service performance objective classification for a circuit

which is non-interruptible before and after a power fault condition exists. ∗ Clearance: Permission to contact or to come in close proximity to, wires, conductors,

switches, or other equipment which normally might be energized at electrical, hydraulic, or pneumatic potential dangerous to human life. Conditions which must prevail before such permission can be granted are, in general, that the equipment or lines be

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PG&E Transmission Interconnection Handbook

completely isolated from all possible power sources and be tagged with properly filled out man-on-line tags. Cogeneration: The sequential production of electricity and heat, steam, or useful work from the same fuel source. Conductor: Material that can be used as a carrier of an electric current. Control, Supervisory: A system for selecting control and automatic indication of remotely located units by electrical means, over a relatively small number of common transmission channels. Control Switch: A switch controlling the circuit through circuit breakers or other switches which are magnetically operated. CPUC: California Public Utilities Commission. Current: The part of a fluid (air, water, etc.) flowing in a certain direction. A flow of electric charge measured in amperes. Current Transformer (CT): A transformer, intended for metering, protective or control purposes, which is designed to have its primary winding connected in series with a circuit carrying the current to be measured or controlled. A current transformer normally steps down current values to safer levels. A CT secondary circuit must never be open circuited while energized. [Glossary Index]

D Data Proessing Gateway (DPG): ISO specified interface between generator plant systems and ISO and PG&E EMS. Dead-End Structure: The structure on which the last span of PG&E-owned conductors terminates. Also called a landing structure. From the interconnection requester’s point of view, it is sometimes called the take-off structure. Delta Connected Circuit: A three-phase circuit with three source windings connected in a closed delta (triangle). A closed delta is a connection in which each winding terminal is connected to the end (terminal) of another winding. Demand: The rate at which electric energy is delivered to or by a system; normally expressed in kilowatts, megawatts or kilovolt amperes. Designated PG&E Electric Control Center: The Electric Control Center that has been assigned operational jurisdiction over a Load or Generation Entity’s substation. Designated PG&E Switching Center: The PG&E Electric Control Center. Direct Access: Service election allows customers to purchase electric power and, at the customer’s election, additional related services from non-utility entities known as Energy Service Providers (ESPs). Direct Current (DC): A uni-directional current in which the changes in value are either zero or so small that they may be neglected. (As ordinarily used, the term designates a practically non-pulsating current, such as the output of an electric battery.) 15

PG&E Transmission Interconnection Handbook

Disconnect: (noun) A device used to isolate a piece of equipment. A disconnect may be gang operated (three operated together) or individually operated. Dispatchability: Ability and availability of a generating facility to operate so that a utility can call upon it to increase or decrease deliveries of capacity to any level up to contract capacity. Distribution System: The portion of PG&E’s Power System that is at a voltage less than 60 kV. The Distribution System continues to be controlled by PG&E. ∗ Distribution Switching Center: Now termed an Electric Control Center - Distribution ∗ Disturbance: Trouble (e.g. fault, sudden loss of load or generation, breaker

operations, etc.) on the PG&E Power System resulting in abnormal performance of the system. See also System Emergency Droop: The slope of the prime mover’s speed-power characteristic curve. The speed droop, typically 5 percent, enables interconnected generators to operate in parallel with stable load division. [Glossary Index]

E Electric Circuit: A path or group of interconnected paths capable of carrying electric current. Electric Control Center - Distribution: (Formerly Distribution Switching Center or DO): This center directs, coordinates, and implements routine and emergency switching activities on the PG&E distribution system within its geographical jurisdiction in a safe and efficient manner. Electric Control Center – Transmission (Formerly Transmission Switching Center): This center implements switching operations on the PG&E transmission system within a specific geographical area. The core function of each Transmission Switching Center is to implement switching orders from the ISO and to coordinate routine and emergency switching activities within its geographic jurisdiction in a safe and efficient manner. Electric Generator: See Generator. Electric Substation: An assemblage of equipment for purposes other than generation or utilization, through which bulk electric energy is passed for the purpose of switching or modifying its characteristics. Service equipment, distribution transformer installations and transmission equipment are not classified as substations. EMS: Energy Management System. A computer-based system that manages the realtime dispatch of electric resources to meet realtime. ∗ End-Use Customer or End-User: A purchaser of electric power who purchases such

power to satisfy a Load directly connected to the ISO Controlled Grid or to a Distribution System and who does not resell the power. ∗ Energize: To apply voltage to a circuit or piece of equipment; to connect a de-

energized circuit or piece of equipment to a source of electric energy. 16

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∗ ESP (Energy Service Provider): Non-utility entities providing services as defined under

CPUC Rule 1. [Glossary Index]

F Facility: A set of electrical equipment that operates as a single Bulk Electric System Element (e.g., a line, a generator, a shunt compensator, transformer, etc.) Fault Indicator: A device attached to lines that targets when the current through the line exceeds the device setting. Feeder: A circuit having as its primary purpose the distribution of electric energy. ∗ FERC: Federal Energy Regulatory Commission or its successor.

Firm Capacity: Power committed to be available at all times during the period covered, except for forced outages and scheduled maintenance. Forced Outage: Any unplanned outage resulting from a design defect, inadequate construction, operator error or a breakdown of the mechanical or electrical equipment that fully or partially curtails the delivery of electricity between a Load or Generation Entity’s facility and PG&E’s Power System. Frequency: The number of cycles occurring in a given interval of time (usually one second) in an electric current. Frequency is commonly expressed in Hertz (Hz); one Hz equals one cycle per second. Fuse: A short piece of conducting material of low melting point which is inserted in a circuit and will melt and open the circuit when the current reaches a certain value. [Glossary Index]

G Generation Entity: An entity interconnected to PG&E’s Power System who has generation facilities (including back-up generation in parallel) on its side of the point of interconnection with PG&E’s Power System. Generation Facility: A plant in which electric energy is produced from some other form of energy by means of suitable converting apparatus. The term “generation facility” includes the generation apparatus and all associated equipment owned, maintained and operated by the Generation Entity. Generator: The physical electrical equipment that produces electric power. Sometimes used as a brief reference to a Generation Entity. Generator Interconnection Agreement: An interconnection agreement between PG&E and wholesale Generators connected to the PG&E Power System. Generator Operating Agreement: An agreement that establishes operating responsibilities and associated procedures for communications between a Generator and PG&E system operators

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∗ Green Book: The Electric and Gas Service Requirements Book (“The Green Book”) is

a guide to PG&E requirements and policies for establishing electric and gas service to new or remodeled retail customer installations. ∗ Grid Critical Protective Systems: Protective relay systems and Remedial Action

Schemes that the ISO determines may have a direct impact on the ability of the ISO to maintain system security. Ground: A term used to refer to the earth as a conductor or as the zero of potential. For safety purposes, circuits are grounded while any work is being done on or near a circuit or piece of equipment in the circuit; this is usually called protective grounding. Ground Bank: A secondary transformer bank installed on delta connected winding to provide a path to ground for relaying purposes. Ground Fault: An unintentional electric current flow between one or more energized conductors and the ground. Ground Potential Rise: A calculated value of the highest expected voltage due to a line-to-ground fault at or near the station (power switchyard). The value is calculated as follows: GPR = 1.2 (DC Transient Factor) x 1.4 x Ground Fault Return Current (rms) x Ground Resistance [Glossary Index]

H Hertz (Hz): The term denoting cycles per second or frequency. [Glossary Index]

I IEEE (The Institute of Electrical and Electronics Engineers): Among other things, the IEEE develops technical standards applicable to the electric industry including relays, transformers, and metering. Inductance: The property of an electric circuit which produces a voltage by electromagnetic induction when the current in the circuit changes or varies. It opposes any change of circuit current. Induction Generator: Typically, an induction motor that is being driven by a prime mover at a speed which is faster than the synchronous mechanical speed to generate electric power. It typically depends on the host system for its excitation and speed regulation. Interconnection Facilities: All means required and apparatus installed to interconnect and deliver power from a Load or Generation Entity facility to the PG&E Power System including, but not limited to, connection, transformation, switching, metering, communications, and safety equipment, such as equipment required to protect (1) the PG&E Power System and Load or Generation Entities from faults occurring at the Load or Generation and (2) the Load or Generation facility from faults occurring on the PG&E 18

PG&E Transmission Interconnection Handbook

Power System or on the systems of others to which the PG&E Power System is directly or indirectly connected. Interconnected facilities also include any necessary additions and reinforcements by PG&E to its system required as a result of the interconnection of a facility to the PG&E Power System. Interconnection Study: Those studies performed in conjunction with an interconnection request to determine the facilities needed to interconnect the Load or Generation Entity in accordance with Applicable Reliability Requirements. Interrupting Capacity: The amount of current a switch or circuit breaker can safely interrupt. Interruption: A temporary discontinuance of the supply of electrical power. IOU: Investor-owned utility. In California the three IOUs are PG&E, SCE, and SDG&E. ∗ ISO: The California Independent System Operator (CAISO) Corporation, a state

chartered, nonprofit corporation that controls the transmission facilities of all Participating TOs and dispatches certain Generating Units and Loads. ∗ ISO Controlled Grid: The system of transmission lines and associated facilities of the

Participating TOs that have been placed under the ISO’s Operational Control. ∗ ISO Metered Entity: Entities directly connected to the ISO Grid, including, i) certain

Generators, ii) Eligible Customers, or iii) certain End Users. ISO Metered Entity also includes any Participating Generator and any Participating TO having Tie Point Meters with other TOs or Control Areas. Refer to complete definition in the Meter Service Agreement. ∗ ISO Protocols: The rules, protocols, procedures and standards promulgated by the

ISO (as amended from time to time) to be complied with by the ISO Scheduling Coordinators, Participating TOs and all other Market Participants in relation to the operation of the ISO Controlled Grid and the participation in the markets for Energy and Ancillary Services in accordance with the CAISO Tariff. ∗ ISO Registry: The register of all the transmission lines, associated facilities and other

necessary components that are at the relevant time being subject to the ISO's Operational Control. ∗ ISO Tariff (CAISO Tariff): The California Independent System Operator Agreement

and Tariff, dated March 31, 1997, as it may be modified from time to time. The current version of the CAISO Tariff is available on the ISO website. [Glossary Index]

J [Glossary Index]

K Kilovolt (kV): 1,000 volts. Kilovolt-Ampere: (kVa) The product of kilovolts times amperes. Used to refer to high voltage alternating current systems. 19

PG&E Transmission Interconnection Handbook

Kilowatt (kW): An electrical unit of power which equals 1,000 watts. Kilowatthour (kWh): 1,000 watts of energy supplied for 1 hour. A basic unit of electric energy equal to the use of 1 kilowatt for a period of 1 hour. kV: Abbreviation for kilovolt. kVa: Abbreviation for kilovolt-ampere. For three-phase circuits, it is found by multiplying line-to-line kV times amps times 1.73. kVar: Abbreviation for kilovolt-ampere-reactive. A measure of reactive power which is required to regulate system voltage. [Glossary Index]

L Lagging Power Factor: Occurs when reactive power flows in the same direction as real power. Stated with respect to the generator, lagging power factor occurs when the generator is producing Vars. Leading Power Factor: Occurs when reactive power flows in the opposite direction to real power. Stated with respect to the generator, leading power factor occurs when the generator is absorbing Vars. Line Losses: Electrical energy converted to heat in the resistance of all transmission and/or distribution lines and other electrical equipment, such as transformers, on the system. Load Entity, OR Load-only Entity: An entity interconnected to PG&E’s Power System at a transmission or distribution voltage level who does not have generation of its own in parallel with PG&E’s Power System, and is not interconnected with any source of generation other than PG&E’s. Local Reliability Criteria: Reliability criteria established at the ISO Operations Date, unique to the transmission systems of each of the Participating TOs. Log: A computer file, a book or loose-leaf sheets for recording all station operations, clearances, readings, ratio reports, and other pertinent active daily data. [Glossary Index]

M Maximum Torque Angle (MTA): The phase angle between the relay measured quantities at which the relay is the most sensitive. Meter Data Management Agent (MDMA): The entity which is providing MDMA Services for a particular service account. Metering Services: Consist of removal, ensuring meter design specifications, installation, calibration, and ongoing testing and maintenance of meters. ∗ MDMA Services: MDMA Services consist of reading the raw data from Interval Meters,

validating the data, editing and estimating the data to 'settlement quality' form, placing the settlement quality data on the MDMA Server and, if necessary, usage adjustment.

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PG&E Transmission Interconnection Handbook

MSA ( Meter Service Agreement): An agreement between the ISO and either a Scheduling Coordinator or a Load Entity. MSP (Meter Service Provider): The entity which is providing Metering Services for a particular account. Megawatt (MW): 1 million watts. Megger: An ohm meter device used to measure the ability of insulation to withstand voltage, as well as measuring the insulation resistance. For example a poor megger test would mean that the insulation is breaking down. [Glossary Index]

N Nameplate Rating (Facility): Output rating information appearing on a generator nameplate, or other electrical device, in accordance with applicable industry standards. ∗ NERC: The North American Electric Reliability Corporation or its successor.

NETA: The InterNational Electrical Testing Association. Net Energy Output: The generation facility's gross output in kilowatt-hours less station use to the point of delivery into the PG&E Power System. Net Sale: The generation facility’s gross output, in kW and kWh, less station use to the point of delivery into the PG&E Power System. Neutral: The common point of a star-connected transformer bank, a point which normally is at zero potential with reference to the earth. No Sale: The Generation Entity desires to operate in parallel and not sell power to PG&E. [Glossary Index]

O Ohm: The unit of resistance of an electric circuit. One-Line Diagram: A diagram in which several conductors are represented by a single line and various devices or pieces of equipment are denoted by simplified symbols. The purpose of such a diagram is to present an electrical circuit in a simple way so that its function and configuration can be readily grasped. ∗ Operating Procedures: Procedures governing the operation of the ISO Controlled

Grid as the ISO may from time to time develop, and/or procedures that Participating TOs currently employ which the ISO adopts for use. ∗ Operational Control: The rights of the ISO under the Transmission Control Agreement

and the CAISO Tariff to direct Participating TOs how to operate their transmission lines and facilities and other electric plant affecting the reliability of those lines and facilities for the purpose of affording comparable non-discriminatory transmission access and meeting Applicable Reliability Criteria. Outage: A condition existing when a line or a substation is de-energized. 21

PG&E Transmission Interconnection Handbook

Output: The energy delivered by a generation facility during its operation. Overload: A load in amperes greater than an electric device or circuit is designed to carry. Overvoltage: Voltage higher than that desired or higher than that for which the equipment in question is designed. [Glossary Index]

P Parallel: (Verb) To connect electrically a generator or energized source, operating at an acceptable frequency and voltage, with an adjacent generator or energized system, after matching frequency, voltage and phase angle. Parallel Operation: As used in this manual, the operation of a non-utility-owned generator while connected to the utility's grid. Parallel operation may be required solely for the power producer's operating convenience, or for the purpose of delivering power to the utility's grid. ∗ Participating Generator: A Generator selling power to the market palce. Such

generators must use the services of a Scheduling Coordinator and must be bound by the terms of the Participating Generator Agreement. Participating Generators may be interconnected to either the transmission or distribution system. ∗ Participating Generator Agreement: An agreement between a Generator and the

ISO that specifies certain requirements and protocols for Participating Generators. The current version of the Participating Generator Agreement may be found the ISO’s website. ∗ Participating TO: A party to the TCA whose application under Section 2.2 of the TCA

has been accepted and who has placed its transmission assets and Entitlements under the ISO’s Operational Control in accordance with the TCA. Peaking: Operation of generating facilities to meet maximum instantaneous electrical demands. Permissive Overreach Transfer Trip Scheme (POTT): A very secure line protection scheme for insuring that a fault is within the protected line section. It requires the presence of both a trip signal from a remote terminal and a trip signal from the local relay before tripping the local breaker. ∗ PG&E Power System: The electric transmission and distribution wires, and their

related facilities owned by PG&E, including PG&E’s portion of the ISO Controlled Grid Point of Interconnection: The point where the Load or Generation Entities’ conductors or those of their respective agents meet PG&E's Power System (point of ownership change). PT (Potential Transformer): A transformer which is intended to reproduce in its secondary circuit, in a known proportion, the voltage of the primary circuit. Also known as Voltage Transformer Power: The time rate of transferring or transforming energy. 22

PG&E Transmission Interconnection Handbook

Power Factor: The ratio of real (MW) power to apparent power (MVA). Power factor is the cosine of the phase angle difference between the current and voltage of a given phase. Primary: Normally considered as the high-voltage winding of a substation or distribution transformer; any voltage used for transmission of electric power in reasonably good-sized blocks and for some distance, as contrasted with low voltage for the immediate supply of power and light locally such as the distribution within a building. The lowest voltage considered as a primary voltage is 2.4 kV although this is also used for some heavy power requirements as short distances. Primary is commonly referred to as 2.4 kV, 4 kV, 17 kV, and 21 kV. Primary Distribution System: A system of alternating current distribution for supplying the primaries of distribution transformers from the generating station or distribution substation. Protection: All of the relays and other equipment which are used to open the necessary circuit breakers to clear lines or equipment when trouble develops. Protective Relay: A device whose function is to detect defective lines or apparatus, or other power-system conditions of an abnormal or dangerous nature and to initiate appropriate control circuit action. [Glossary Index]

Q Qualifying Facility (QF): As defined in the Public Utility Regulatory Policies Act of 1978 (PURPA), a QF is a small-power producer or cogenerator that can sell its electricity to putlic utilities. QFs selling power to PG&E do so under three CPUCjurisdictional standard contracts: Standard Offer 4, Standard Offer 2, and Standard Offer 1. See the Qualifying Facilities Information Center for more information. [Glossary Index]

R Reactance: In an alternating current circuit, the opposition to the flow of current attributable to the inductance and capacitance of the circuit. Reactive Component of Current: That part of a current that does no useful work because its phase is 90 degrees leading or lagging the voltage. Reactive Load: In alternating current work, a load whose current is not in phase with the voltage across the load. Reactor: A coil with no secondary winding provided. The primary use is to introduce inductance into the circuit for purposes such as starting motors, paralleling transformers and controlling current. A current-limiting reactor is a reactor for limiting the current that can flow in a circuit under short-circuit conditions. Reclose: To again close a circuit breaker after it has opened by relay action.

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PG&E Transmission Interconnection Handbook

∗ RAS (Remedial Action Scheme): Protective systems that typically utilize a

combination of conventional protective relays, computer-based processors, and telecommunications to accomplish rapid, automated response to unplanned power system events. Also, details of RAS logic and any special requirements for arming of RAS schemes, or changes in RAS programming, that may be required. Remote Intelligent Gateway (RIG): Specific type of ISO specified Data Processing Gateway (DPG). Remote Station Alarms: Alarms received at an attended location from unattended stations or plants. Remote Terminal Unit (RTU): A remotely located equipment used for collecting data and/or for supervisory control via communication channel. Residual Current: The current which flows in the neutral or star (wye) connected current transformers when the current in the three phases of a line are unbalanced. Resistance: Anything placed in an electric circuit, or already there, which offers resistance to or opposes the flow of electric current. Resistor: A device whose primary purpose is to introduce resistance into an electric circuit. An adjustable resistor is one so constructed that its amount of resistance can be readily changed. Retail Service: Electric sales to PG&E’s end-use or retail customers. Such service is regulated by the CPUC. [Glossary Index]

S ∗ SC (Scheduling Coordinator): An entity certified by the ISO for the purposes of

undertaking the functions specified in Section 2.2.6 of the CAISO Tariff. SCADA: Supervisory Control and Data Acquisition. SCADA is the combination of telemetry and data acquisition and consists of collecting information, transferring it back to a central site, carrying out necessary analysis and control, and then displaying this data on a number of operator screens. SCADA is used to monitor and control a plant, a substation, or other utility installations. SCE: Southern California Edison Company SC Metered Entity: Refer to ISO Metered Entity Schematic: A diagram showing the essential features of a piece of equipment or a control system. SDG&E: San Diego Gas & Electric Company Secondary: The winding of a transformer which is normally operated at a lower voltage than the primary winding. Secondary Distribution System: A low-voltage alternating-current system which connects the secondaries of distribution transformers to the consumer's services.

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PG&E Transmission Interconnection Handbook

Self-excited: A term to describe an electric machine in which the field current is secured from its own armature current. In the case of induction generators, it refers to the condition in which the induction generator is separated from its normal excitation source and is unintentionally excited by the power-factor correction capacitors in the vicinity. Separately Excited: Use of an exciter for sending current through the field windings of an electric machine in place of taking the field current from its own armature current. Service Reliability: The time an entity or group of entities is served compared to the amount of time the entity or entities are without service over a given time period. Service Restoration: The switching procedure a system operator directs or executes to restore services to the entities following an outage. Setting: The values of current, voltage, or time at which a relay is adjusted. Single-Phase Circuit: A circuit in which all current can be represented by only one regular sine wave pattern. Differs from a three-phase circuit, where when all circuit current is plotted, it produces three regular sign wave patterns, 120 electrical degrees apart. ∗ Special Facilities: Those additions and reinforcements to the PG&E Power System

which are needed to accommodate the receipt and/or delivery of energy and capacity from and/or to the entity’s facility(ies), and those parts of the interconnection facilities which are owned and maintained by PG&E at the entity's request, including metering and data processing equipment. Standard Offer Contract: A CPUC-jurisdictional contract under which a Qualifying Facility sells power to PG&E. Standby Capacity: The lesser of (1) net generation capacity, (2) connected loads to generator, or (3) 80 percent of main switch rating. Star-Connected Circuit ("Y" Connected Circuit): A term applied to the manner in which a motor's windings or a transformer's windings are connected, i.e., starconnected armature having one end of each of the coils connected to a common junction. A star-connected transformer is one in which the primaries and secondaries are connected in a star grouping. Station Use: Energy used to operate the generating facility's auxiliary equipment. (Auxiliary equipment includes, but is not limited to, forced and induced draft fans, cooling towers, boiler feed pumps, lubricating oil systems, power plant lighting, fuel handling systems, control systems, and sump pumps.) Step-Down Transformer: A transformer in which the secondary winding has fewer turns than the primary, so that the secondary delivers a lower voltage than is supplied to the primary. Step-Up Transformer: A transformer in which the secondary winding has more turns than the primary, so that the secondary delivers a higher voltage than is applied to the primary.

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PG&E Transmission Interconnection Handbook

Supervisory Control: A system by which equipment is operated by remote control at a distance using some type of code transmitted by wire or electronic means. Surplus Sale: The generator's gross output, in kW and kWh, less any plant load and transformation and transmission losses, is delivered to the PG&E system. Switch: A device for making, breaking or changing the connections in an electric circuit. Switch, Air: A switch in which the arc interruption of the circuit occurs in the air. Switch, Alarm: A form of auxiliary switch which closes the circuit to a bell or other audible signaling device upon automatic opening of the circuit breaker or other apparatus with which it is associated. Switch, Auxiliary: One actuated by some main device such as a circuit breaker for signaling, interlocking, or other purpose. Synchronism: Expresses the condition across an open circuit wherein the voltage sine wave on one side matches the voltage sine wave on the other side in frequency and without phase angle difference. System: The entire generating, transmitting and distributing facilities of an electric utility. ∗ System Emergency: Conditions beyond the normal control of the ISO that affect the

ability of the ISO Control Area to function normally including any abnormal system condition which requires immediate manual or automatic action to prevent loss of Load, equipment damage, or tripping of system elements which might result in cascading outages or to restore system operation to meet the minimum operating reliability criteria. System Protection Facilities: The equipment required by the utility to protect (1) PG&E’s Power System from faults occurring at a Load or Generation Entities’ facility and (2) the Load or Generation Entities’ generating facility from faults occurring on PG&E’s Power System or on the system of others to which it is directly or indirectly connected. [Glossary Index]

T ∗ TAC (Transmission Access Charge): Charges assessed, on behalf of the

Participating Transmission Owner, to parties who require access to the ISO Controlled Grid. See Section G-3. ∗ TCA (Transmission Control Agreement): The agreement (with Appendix A) between

the ISO and Participating TOs establishing the terms and conditions under which TOs will become Participating TOs and how the ISO and each Participating TO will discharge their respective duties and responsibilities, as may be modified from time to time. Telephone Working Limit: A voltage potential of 300 volts or less is present, so personnel can work on the telephone cable without rubber gloves.

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PG&E Transmission Interconnection Handbook

Telemetering: Remote measurement of a physical value or status (i.e. generator kV, status of a switch, etc.) by means of a communication channel. Telemetering of kW, kVar, etc to PG&E’s Electric Energy Control Center in San Francisco and the ISO is required for all generators equal to or greater than 10 MVA. TO (transmission owner): An entity owning transmission facilities or having firm contractual rights to use transmission facilities. TO Tariffs: A tariff setting out a Participating TO’s rates and charges for transmission access to the ISO Controlled Grid and whose other terms and conditions are the same as those contained in the document referred to as the Transmission Owners Tariff approved by FERC as it may be amended from time to time. PG&E’s TO Tariff can be viewed here. ∗ TOC (Transmission Operations Center): This center serves as PG&E's interface to

the ISO on day to day operational matters. The ISO issues operational orders to the TOC which will then process, coordinate, and redirect the orders to the appropriate PG&E Transmission Switching Center as needed. T T (Transfer Trip): A form of remote trip in which a communication channel is used to transmit the trip signal from the relay location to a remote location. Transformer: An electric device, without continuously moving parts, in which electromagnetic induction transforms electric energy from one or more other circuits at the same frequency, usually with changes in value of voltage and current. Transformer Efficiency: The ratio of the electric power of the current going into a transformer to the power of the secondary circuit from the transformer. Transformer Loss: The difference between the input power to a transformer and the output power of the transformer. Transformer Ratio: The ratio of the voltage secured from a transformer to the voltage supplied to that transformer. Transmission: An interconnected group of lines (rated 60 kV and over) and associated equipment for the movement or transfer of electric energy between points of supply and points at which it is transformed for delivery to customers or is delivered to other electric systems.. Transmission Line: A line used for electric power transmission. Distinguished from a distribution line by voltage. Lines rated 60 kV and over are transmission lines. Transmission System: The portion of PG&E’s Power System that is at a voltage of 60 kV and above. The Transmission System is under the operational control of the ISO. Transmission Switching Center: Now termed Electric Control Center – Transmission. [Glossary Index]

U UDC (Utility Distribution Company): An entity that owns a Distribution System for the delivery of Energy to and from the ISO Controlled Grid, and that provides regulated retail electric service to Eligible Customers, as well as regulated procurement service to 27

PG&E Transmission Interconnection Handbook

those End-Use Customers who are not yet eligible for direct access, or who choose not to arrange services through another retailer. PG&E’s UDC System: Refers to those components of PG&E’s electric system which are not a part of the ISO Controlled Grid. Undervoltage Protection: Upon failure or reduction of voltage, the protection device interrupts power to the main circuit and maintains the interruption. Undervoltage Release: Upon failure or reduction of voltage, the protective device interrupts power to the main circuit but does not prevent again completing the main circuit upon return to voltage. Unity Power Factor: A power factor of 1.000 which exists in a circuit wherein the voltage and current are in phase. [Glossary Index]

V Var: A unit of measurement of reactive power. It is an expression of the difference between current and voltage sine waves in a given circuit. VA2 = (Watts)2 + (Vars)2 Volt: The unit of electrical pressure similar to the pounds per square inch pressure on a steam gauge. Volt-Ampere: A unit of apparent power in an alternating-current circuit. Equal to the product of volts and amperes without reference to the phase difference, if any. At unity power factor, a volt-ampere equals a watt. Whenever there is any phase difference between voltage and current, the true power in watts is less than the apparent power in volt-amperes. Voltage Drop: The difference in voltage level between one point and another in a circuit (see Line Voltage Drop). Voltage Loss: The drop of potential in an electric circuit due to the resistance and reactance of the conductor. This loss exists in every circuit. Voltage Ratio of Transformer: The ratio of the effective primary voltage to the effective secondary voltage of a transformer. Voltage Transformer: See PT. [Glossary Index]

W ∗ WEnet (Western Energy Network): An electronic network that facilitates

communications and data exchange among the ISO, Market Participants and the public in relation to the status and operation of the ISO Controlled Grid. ∗ WECC (Western Electricity Coordinating Council) or WSCC (Western Systems

Coordinating Council): The Western Systems Coordinating Council or its successor. Note: The WSCC is now the Western Electricity Coordinating Council or WECC.

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PG&E Transmission Interconnection Handbook

Watt: The unit of electric power. Watts AC = volts x amperes x power factor (singlephase circuits). Watt-Hour: A measure of electric power. The power of 1 watt used for 1 hour. Watt-Hour Meter: An electrical measuring instrument which indicates power in watthours. Wheeling Out: Except for Existing Rights and Non-Converted Rights exercised under an Existing Contract in accordance with Sections 2.4.3 and 2.4.4, the use of the ISO Controlled Grid for the transmission of Energy from a Generating Unit located within the ISO Controlled Grid to serve a Load located outside the transmission and distribution system of a Participating TO. Wheeling Through: Except for Existing Rights and Non-Converted Rights exercised under an Existing Contract in accordance with Sections 2.4.3 and 2.4.4, the use of the ISO Controlled Grid for the transmission of Energy from a Generating Unit located outside the ISO Controlled Grid to serve a Load located outside the transmission and distribution system of a Participating TO. Wholesale Customer: A person wishing to purchase Energy and Ancillary Services at a Bulk Supply Point or a Scheduling Point for resale. Wholesale Distribution Tariff: A tariff executed by wholesale Load or Generation Entities connected to PG&E’s Distribution System. Wholesale Sales: The sale of Energy and Ancillary Services at a Bulk Supply Point or a Scheduling Point for resale. Wholesale Service: Electric Sales to Wholesale Customers for resale. Such service is regulated by the FERC. "Wye" Connected Circuit: A three-phase circuit which is star-connected: the windings of all three phases have one common connection which may be connected to ground [Glossary Index]

X [Glossary Index]

Y [Glossary Index]

Z [Glossary Index]

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PG&E Transmission Interconnection Handbook

Section L1-D: REVENUE-METERING REQUIREMENTS FOR DISTRIBUTION LOAD-ONLY ENTITIES PURPOSE The purpose of this section is to help Direct Access (DA) and Bundled Service load-only entities connected at distribution voltages, to satisfy Independent System Operator (ISO) metering standards, CPUC-approved metering standards and PG&E requirements for measuring and registering electricity supplied to them. Loads connecting at distribution voltages and participating in ISO load management programs shall be in accordance with the relevant metering protocols established by the ISO, or prior to establishing of such protocols, the metering requirements established by PG&E, the Participating Transmission Owner (PTO), or Utility Distribution Company (UDC). For purposes of this handbook, distribution and transmission level is defined in PG&E’s Electric Rule 2. Any exceptions to this section shall be addressed on an individual case basis and must be approved by PG&E. These arrangements may involve Special Facilities, and may require other operating or service agreements, as approved by PG&E and other local governing authorities Such as the ISO. For non-ISO connected loads, metering requirements shall be in compliance with PG&E and local governing authorities and must satisfy the requirements specified below.

L1-D.1. Revenue Metering Requirements For Load Entities For purposes of this section, metering requirements for distribution service are differentiated into two basic types: 1) wholesale (TOs and metered entities) and 2) retail (end-users).

L1-D.1.1. Wholesale Service For wholesale service interconnections (other than TO’s), the Load Entity shall normally provide, install, own and maintain all revenue metering related equipment, including all items provided and maintained by PG&E or a Meter Service Provider (MSP) listed under “Retail Service” below. Wholesale entities must meet the ISO metering standards, CPUC-approved metering standards and PG&E requirements, and must enter into a Meter Service Agreement (MSA) with the ISO, and also in certain instances, the UDC. The MSA specifies requirements regarding retrieval of load data and accessibility by the ISO. The wholesale Load Entity is obligated to ensure the meters are certified and comply with ISO meter standards and accuracy requirements. All Load Entities are advised that they need to contact PG&E local Account Services representatives for PG&E requirements.

L1-D.1.2. End Users (Retail Service)

L1-D.1.2.1. PG&E Direct Access Rule 22  PG&E Electric Rule 22 governs interconnection and operating requirements for DA entities. According to Rule 22, entities will have the

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opportunity to acquire their electric power needs under three options: 1) Bundled Utility Services -traditional service from the UDC (PG&E), 2) DA ¬purchases energy from various suppliers, and related services from Energy Service Providers, ESPs.  For Bundled Utility Services, PG&E, in most cases, continues to own, provide and, in all cases continues to maintain metering equipment including the meter, and continues to read the meter. For entities or customers returning to Bundled service, the Load Entity may also own the meter at the UDC’s discretion if it can be read by the UDC and it meets the UDC’s requirements.  For DA services, the Load Entity, UDC, or ESPs may own the hourly meter. The ESP can be its own MSP or hire an MSP to maintain metering equipment and be its own MDMA or hire an MDMA to read the meter and manage metered data. The ESP may contract the metering services and/or metered data management services to PG&E.  Per CPUC Decision D.97-10-087 on October 30, 1997, revenue metering transformers are part of the distribution system and shall remain the UDCs’ responsibility.  Regardless of meter ownership, PG&E retains the right to physically access any hourly or monthly meter data. In addition, PG&E also has the right to read, test and inspect the said meters on PG&E’s system.  All entities must refer to most recent version of PG&E Electric Rule 22 for more details.

L1-D.1.2.2. PG&E, as an MSP, will provide, install, maintain and test the following meter equipment  Combination revenue-metering voltage and current transformers. These shall be three, single-phase, voltage and current transformers. Appendix C shows a typical piece of equipment for distribution pole top metering.  Wiring from the base of the revenue-metering transformers to the meters, in conduits. Conduits may be metallic or non-metallic. 

Meters, recorders, and associated metering equipment.

The Load Entity or ESP shall reimburse PG&E for the materials and labor cost associated with installation of the metering equipment according to the local governing authority approved tariffs. (E-EUS, E¬ESP or through a CPUC approved Meter sale or lease agreement).

L1-D.1.2.3. PG&E, as an MDMA, will provide the following meter data services 

Read the raw data from interval meter.

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Validate, edit and estimate the data to a “settlement quality” form.

 Place the settlement quality data on the MDMA server and, if necessary, usage adjustment.

L1-D.1.2.4. All PG&E Load Entities will provide, install and maintain  The meter enclosure. The distance between the meter enclosure and the revenue-metering transformers must not exceed 50 feet to maintain the required metering accuracy. PG&E must approve any variance from this general rule. The enclosure must be located within and grounded to the substation ground grid. Access to meters and metering equpment must be readily available for PG&E’s personnel to read and maintain metering equipment. The enclosure must be equipped with an auxiliary 120-volt duplex plug, an overhead light, a light switch adjacent to the door, and a ground bus connected to the ground and mounted near the bottom of the wall where the meters are to be located. Refer to PG&E’s Green Book, Section 9, and Appendix D of this handbook. 

Meter panels specified by PG&E. Refer to PG&E’s Green Book.

 All required conduit, junction boxes and the metering potential safety disconnect switch (60-amp, 3-pole, un-fused, knife disconnect that is lockable in the open and closed positions). A pull line must be installed in the conduit between the metering enclosure and the junction box at the base of the metering unit support structure to facilitate the MSP installing the metering unit secondary wires. Only the MSP’s revenue-metering wire shall be installed in the conduit between the metering enclosure and the CT/PT units. Conduits may be metallic or non-metallic.  Phone lines into the metering enclosure and establishment of phone service. Where telephone lines are required to read the meter, installation of phone lines into the metering enclosure and establishment of phone service are the customer responsibility. Where land line is not available and cellular cell signal is acceptable, the use of cellular phone is acceptable. If the meter phone lines cannot be dedicated to the meter, the Load Entity shall obtain prior approval from PG&E’s local metering group to arrange for a line share switch to be used with the meter being the secondary phone user. Refer also to Section L1-D3.  The requirements for phone line termination at or in switchboards, panels, pole mounted meters and pedestals shall be: o Generally, phone terminals should not be terminated on the switchboard or meter panels. The Load Entities should consult utilities and MSP’s for locations of phone terminals. o The phone terminals shall be installed as follows: 

Within five (5) circuit feet from the centerline of meter, and 32

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Between eighteen (18) inches (minimum) and seventy-two (72) inches (maximum) above finished grade.

 Where cellular phones are used, the same rules for phone termination as above shall apply, and the power supply shall be outside any (utility/MSP's) sealed section and be on load side of meter. Note: All Load Entities interconnected at transmission level 60KV and above, will provide, install and maintain, and comply with the requirements detailed in Section L1-T of this handbook.

L1-D.2. Requirements of Revenue-Metering Point Revenue-metering must be installed at the point of service or ownership change. Highside revenue-metering is PG&E’s standard installation and is required for all Load Entities at distribution voltage levels. Exceptions may be granted if the Load Entity can demonstrate that high-side revenue metering will create significant safety issues or impose extraordinary costs. Where low-side revenue metering is justified, a 2 percent adjustment factor shall be applied for each stage of transformation. Line losses shall be calculated as a function of the maximum load current through, and the electrical characteristics of, the line between the point of service and point of metering.

L1-D.3. Communication Circuits The Load Entity may be obligated to bring as many as four communication lines into the metering enclosure for PG&E’s use. In addition to the following, other communication requirements may apply; refer to Sections L2 and L3 of this manual: 

One phone line dedicated to revenue-metering. Refer to L1-D.1.2.4.

 One basic business line, although there may be alternatives to this requirement. Contact your local PG&E representative or the ISO.  One line dedicated for the interruptible service, if interruptible service is selected by entity and the entity meets the underfrequency relay requirements per rate Schedules E-19 and E-20.  One line dedicated for transfer trip, if required to meet protection standards and system integrity. Note: Underfrequency relay and related accessories shall be required if the Load Entity qualifies for and elects an interruptible rate schedule. At entity expense, PG&E shall provide the labor and equipment required for the installation. In addition to any phone lines required for metering or other purposes, the entity shall provide and pay for the additional, separate phone line (VG36, Type 3002, 4-wire, unconditioned, Class B circuit) obtained from the phone company for this relaying. The line will terminate at the Designated PG&E Electric Control Center (Appendix B). See Form L1-1 in Section L1-T for assistance in properly ordering the leased alarm circuit. The alarm circuit will indicate to the operator that the load has been tripped by an underfrequency condition (see Figure L1-2 in Section L1-T). See Figure L1-3 in Section L1-T for typical underfrequency relay installation.

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L1-D.4. Ground Potential Rise The Load Entity shall determine the ground potential rise (GPR). The GPR value will determine what grade of telephone cable high-voltage protection equipment is required, as well as the minimum required dielectric strength of the cable insulating jacket. The information required to determine the GPR: 1) highest calculated fault current (PG&E provides this information); and 2) ground resistance (entity determines this information).

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Section L1-T: REVENUE-METERING REQUIREMENTS FOR TRANSMISSION-ONLY AND LOAD-ONLY ENTITIES PURPOSE The purpose of this section is to help transmission Load Entities and Transmission Entities satisfy ISO (and PG&E as applicable) revenue-metering requirements for measuring and registering electric power supplied to them. The revenue-metering requirements in this handbook can also be found in the CAISO Tariff which may be obtained from the ISO website. Loads connecting to the ISO Controlled Grid shall be in accordance with the relevant metering protocols established by the ISO, or prior to establishing of such protocols, the metering requirements established by PG&E, the Participating Transmission Owner (PTO). Any exceptions to this section shall be addressed on an individual case basis and must be approved by the ISO. These arrangements may involve Special Facilities with PG&E, and other operating or service agreements, as approved by the ISO and local governing authorities.

L1-T.1. REVENUE-METERING REQUIREMENTS FOR LOAD ENTITIES AND TRANSMISSION ENTITIES CONNECTING LOAD TO THE PG&E TRANSMISSION SYSTEM For purposes of this section, metering requirements for transmission service are differentiated into two basic types: Wholesale Service and Retail Service. (See Glossary)

L1-T.1.1. Wholesale Service For wholesale transmission service interconnections, the Load Entity or Transmission Entity at its expense shall normally provide, install, own and maintain all revenue-metering related equipment, and associated communications devices. Additional details are similar to those shown in L1T.1.2 “End User”. Such wholesale entities must meet the metering requirements of the ISO, and must enter into a Meter Service Agreement (MSA) with the ISO. The MSA covers the obligations regarding retrieval of load data and accessibility by the ISO. The wholesale entity is obligated to ensure the meters are certified and comply with ISO meter standards and accuracy requirements.

L1-T.1.2. End User (Retail Service) End Users receiving transmission service are segregated into two service categories: 

Bundled Service



Direct Access (DA)

In general, a) the meters and associated equipment shall meet the (technical)

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requirements of the ISO, while b) responsibilities and potential providers (such as Meter Service Provider and Meter Data Management Agent) shall be in accord with CPUC Rule 22.

L1-T.1.2.1. Bundled Service PG&E, as supplier of energy, will, at entity expense, provide, install and maintain the meter and any associated communications equipment, and shall ensure meter meets PG&E’s revenue metering requirements. PG&E responsibilities generally include the Energy Service Provider (ESP), MSP, and MDMA service: 

ensure all such entities are metered



ensure meter meets PG&E’s standards including accuracy requirements, and approve and certify the meters



provide access to revenue metering data



provide end-user meter data as requested



install, own and maintain meter(s)



read meters, process meter reading data, render monthly bills, and collect & process payments.

Load Entity or Transmission Entity responsibilities: 

Provide mounting structures, enclosures, conduit, install wiring (PG&E will make connections).



Make arrangements (with local phone company) for communications circuits as required by PG&E as described in more detail in L1-T.3, Communications Circuits, below.



Provide additional equipment as shown in L1-T.1.3 below.

L1-T.1.2.2. Direct Access Service The DA Entity must select an energy supplier and may select a qualified ESP for various additional related services or provide those services themselves if qualified. The entity is responsible either directly, or through their ESP, to provide, install, and maintain the meter and any associated communications equipment, and shall ensure meter meets ISO standards and requirements: Load Entity (or ESP) responsibilities: 

enter into a Meter Service Agreement with the ISO



ensure all such entities are metered



ensure meter meets ISO standards including accuracy requirements, and approve and certify the meters



provide access to revenue metering data

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provide ISO with end-user meter data



submit end-use meter data as per ISO protocols



must install interval meters unless exempt due to small size (less than 50kw). (Such loads seldom qualify for transmission service.)

Note: an interval meter with communication and telephone line access must be capable of reading and storing electric consumption data in conformance with CPUC specifications. Such data must also meet ISO accessibility requirements. Usually a Quad 4 meter, with communications lines and telephone access are sufficient.

L1-T.1.2.3. Equipment Requirements: The supplier of energy will provide, install, own and maintain metering transformers when they are within the Load Entity’s substation. 

Metering CTs and PTs cannot have a bypass switch.



Metering CTs cannot be switched or fused.



Metering class PT/CTs (including Dual Winding devices) shall not be used for relaying purposes in the PG&E system. In particular, combination PT/CTs which are installed by PG&E or an approved meter installed by a qualified meter service provider shall not be connected to Load Entity’s protective relays or used to provide protection of the Load Entity’s owned equipment or devices. Refer to PG&E Guideline E-TSP-G005 in Appendix C.



PG&E may grant exceptions to this policy and allow a dual winding PT/CT unit to be installed. However, in this case, the customer will be required to sign a waiver absolving PG&E from liability in the event of failure of dual winding unit or improper performance of the protective equipment due to, for example, saturation of the CT in the dual winding.



Metering transformers shall be tested by the manufacturer prior to preparallel inspection, and a certified transformer test report shall be provided to PG&E prior to installation. After installation, metering transformers shall be tested by the supplier of energy and a certified transformer test report shall be provided to PG&E. Periodic testing may be required for metering CTs or PTs.



Combination revenue-metering voltage and current transformers shall be three, single-phase, combination voltage/current transformers. If PG&E is the Meter Service Provider, the entity shall reimburse PG&E for the labor cost associated with installation of the metering equipment. Appendix C shows a typical installation of metering equipment. Consult with PG&E Meter Engineering for information on combination revenue-metering voltage and current transformers.



Provide and install wiring from the base of the revenue-metering

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transformers to the meters, in entity-supplied and installed conduits. Conduits above ground must be RSC (rigid steel conduit) and conduits below grade must be PVC (Polyvinyl chloride). PG&E will connect the wires to the metering transformers at Load Entity or Transmission Entity expense. 

Meters recorders and associated metering equipment, and communications equipment as required.

L1-T.1.3. Additional Requirements In addition to the requirements described in the preceding, the Load Entity, whether wholesale or retail, or Transmission Entity shall provide, install and maintain or otherwise meet the following requirements: •

Foundation, structure and disconnect switches for mounting and disconnecting revenue-metering transformers (refer to Section L3.6.1). The support structure may be a pole or a platform-type structure, so long as it can support the CT/PT units. High-side revenue-metering shall have a minimum of two gang-operated, lockable disconnect devices to facilitate establishing a visual open on each primary side of the metering units. Refer to Engineering Standard 063436 in Appendix C for more information.



The meter enclosure shall be owned and maintained by the load entity or Transmission Entity. The distance between the meter enclosure and the revenue-metering transformers must not exceed 50 feet to maintain the required metering accuracy. PG&E must approve any variance from this general rule. The enclosure must be located within and grounded to the substation ground grid. Access to the enclosure must be arranged so that PG&E personnel can read the meters without entering the substation yard. The enclosure must be equipped with an auxiliary 120-volt ac duplex plug, an overhead light, a light switch adjacent to the door, and a ground bus connected to the ground and mounted near the bottom of the wall where the meters are to be located.



Meter panels specified by PG&E. Refer to the Green Book or Engineering Standard 063436 in Appendix C.



All required conduits and junction boxes. A pull line must be installed in the conduit between the metering enclosure and the junction box at the base of the metering unit support structure to facilitate PG&E installing the metering unit secondary wires. Only PG&E’s revenue metering wire shall be installed in the conduit between the metering enclosure and the CT/PT units. Conduits may be metallic or non-metallic. A dedicated land line into the the metering enclosure is required for the revenue meter. Where land line is not available, and cellular cell signals are acceptable, the use of cellular phone is acceptable. If the meter phone line cannot be dedicated to the meter, the load entity shall obtain prior approval from PG&E’s local metering group to arrange for a line shared switch to be used with the meter being the secondary phone user. Also see Section L1-T.3.

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High-voltage protection for phone lines, consult local phone company



Grounding systems in accordance with PG&E requirements. See Appendix E.



A general-arrangement plan of the entity’s substation and metering equipment must be made available to PG&E for review by the PG&E division electric meter Supervisor and the ISO, if applicable. Such review shall be in the early stages of the project, prior to approval of the Load Entity’s or Transmission Entity’s plan, to assure that the proposed interconnection can be metered accurately, tested and operated safely



The entity shall also provide to PG&E a substation arrangement plan showing: o Location and elevation drawings with dimensions for the metering support structure, dead-end structure, disconnect switches, etc. Note: There must be sufficient clear space directly above the top of the support structure for the revenue-metering transformers, and approximately 20 feet of clear space horizontally, before and after construction, to allow the installation or removal of the metering transformers by means of a crane or boom. The top of the metering unit portion of the support structure must not exceed 8 feet above finished grade. PG&E must approve any variance from this general rule. o Location, elevation and detail drawings for the meter enclosure. o Location, size and length of conduit runs for the metering conductors. o Location of the conduit for the revenue-metering telephone line. The conduit for the telephone line must run from the meter enclosure to the nearest telephone company demarcation point. o The location of the permanent maintenance access area reserved for use by a crane or boom truck in the event a metering unit has to be replaced. o Station ground grid drawings. o Other related data.

L1-T.2. Location of Revenue Metering Point Revenue-metering must be installed at the service point which normally is at the point of ownership change. For transmission service, that is the incoming transmission voltage. More explicitly, high-side revenue-metering, at the transmission delivery voltage, is PG&E and ISO’s standard installations and is required for all load entities at transmission voltage levels and Transmission Entities. Exceptions will be rarely permitted and are granted only by the ISO. An adjustment factor specified by the ISO in accordance with their tariffs shall be applied for each stage of transformation, and line

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losses shall be calculated as a function of the maximum load current through, and the applicable electrical characteristics of the facilities and load.

L1-T.3. Communications Circuits To meet the ISO and utility requirements, the Load Entity or Transmission Entity may be obligated to bring as many as four communication lines into the metering enclosure. In addition to the following, other communication requirements may apply; refer to Sections L2 and L3 of the Transmission Interconnection Handbooks: o One phone line dedicated to revenue-metering. This line is mandatory. o One basic business line, although there occasionally may be alternatives to this requirement. Contact your local PG&E representative or the ISO. o One line dedicated for the interruptible service, if interruptible service is selected by entity. o One line dedicated for transfer trip, if required to meet protection standards and system integrity. Underfrequency relay and related accessories shall be required if the Load Entity qualifies for and elects an interruptible rate schedule. At entity expense, PG&E shall provide the labor and equipment required for the installation. In addition to any phone lines required for metering or other purposes, the entity shall provide and pay for an additional, separate phone line (VG36, Type 3002, 4-wire, unconditioned, Class B circuit) obtained from the phone company for this relaying. The line will terminate at the Designated PG&E Electric Control Center (Appendix B). See Form L1-1 for assistance in properly ordering the leased alarm circuit. The alarm circuit will indicate to the operator that the load has been tripped by an underfrequency condition (see Figure L12). See Figure L1-3 for typical underfrequency relay installation. The Load Entity or Transmission Entity shall determine the ground potential rise (GPR). The GPR value will determine what grade of telephone cable high-voltage protection equipment is required, as well as the minimum required dielectric strength of the cable insulating jacket. The information required to determine the GPR: 1) highest calculated fault current (PG&E provides this information); and 2) ground resistance (entity determines this information).

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Form L1-1 ORDER REQUEST FORM UNDERFREQUENCY ALARM CIRCUIT LEASE TO BE REQUESTED FROM THE LOCAL TELEPHONE BUSINESS OFFICE

DESCRIPTION:

CIRCUIT:

Data Quality

PURPOSE:

Electric Underfrequency Trip Alarm Circuit to PG&E Operating Center.

SPECIFICATION:

VG36, Class B, Type 4 Series 3002, Unconditioned, 4-Wire, Full Duplex, Data Circuit.

CUSTOMER INFORMATION:

BUSINESS NAME: CONTACT NAME: ADDRESS:

TELEPHONE NUMBER & AREA CODE:

PG&E COMPANY TERMINAL ADDRESS:

(1)

Pacific Gas & Electric Company

(circuit to terminate on RJ 21 block) PG&E CONTACT:

(2)

TERMINAL ADDRESS: (Customer E-20 Site)

(3)

SPECIAL CONSIDERATIONS:

1. This leased circuit will enter a power substation yard. Special high voltage protection requirements should be reviewed by the telephone company’s protection department. 2. All Telco and PG&E equipment will be supplied with AC power off the line side of the customer’s breaker.

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PG&E Transmission Interconnection Handbook

Section L2: PROTECTION AND CONTROL REQUIREMENTS FOR LOAD-ONLY ENTITIES AND TRANSMISSION-ONLY ENTITIES PURPOSE This section specifies the protective and control requirements for interconnection requests from Load Entities (load-only) or Transmission Entities (transmission-only) to the PG&E Power System. If the interconnection involves both generation and load, or both generation and transmission, or transmission facilities interconnecting network that connects to generation, then Section G2 of the PG&E Interconnection Handbooks shall also apply.

APPLICABILITY For all load-only or transmission-only interconnections: The protective standards of this section apply to all Load Entities interconnecting to any portion of the PG&E Power System. These standards, which govern the design, construction, inspection and testing of protective devices, have been developed by PG&E to assure consistency with Applicable Reliability Criteria and to include appropriate ISO consultation. In addition, for load-only or transmission-only interconnecting directly to the ISO Controlled Grid: The ISO, in consultation with PG&E, may designate certain new or existing protective devices as ISO Grid Critical Protective Systems. Such systems have special ISO requirements, e.g., for installation and maintenance, as described in the CAISO Tariff and the TCA Section 8. In the future, the ISO may develop its own standards or requirements applicable to certain interconnections, and also will review and comment on new requests for interconnection to the ISO Controlled Grid. Refer to the Introduction of the PG&E Interconnection Handbooks. In addition, for load-only or transmission-only connecting directly to the UDC: PG&E‘s UDC must coordinate with the ISO, the PG&E TO and the Load Entity or Transmission Entity, as needed, to ensure that any ISO Controlled Grid Critical Protective Systems, including relay systems, are installed and maintained in order to function on a coordinated and complementary basis with the load’s and the PG&E Power System, in accordance with the CAISO Tariff Section 4 and the ISO-UDC Agreement.

L2.1. PROTECTIVE RELAY REQUIREMENTS An important objective in the interconnection of facilities to the PG&E Power System is minimizing the potential hazard to life and property. A primary safety requirement is the ability to automatically disconnect immediately when a fault is detected. Refer to Electric Rule 2. Moreover, no new facility on the PG&E Power System should degrade the existing PG&E protection and control schemes or lower the levels of safety and reliability to other customers. In view of these objectives, PG&E requires line-protective equipment to either; 1) automatically clear a fault and restore power, or 2) rapidly isolate only the faulted section so that the minimum number of customers is affected by any outage. Due to the

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high energy capacity of the high-voltage transmission system, high-speed fault clearing may be required, to minimize equipment damage and potential impact to system stability. The need for high speed fault clearing shall be determined on a case-by-case basis by PG&E 5. As a general rule, neither party should depend on the other for the protection of their respective equipment. PG&E's minimum protection requirements are designed and intended to protect the PG&E Power System only. The Load Entity or Transmission Entity shall install at the Point of Interconnection, at a minimum, a disconnecting device or switch with load interrupting capability. Additional protective relays are typically needed to protect the Load Entity’s or Transmission Entity’s facilities adequately. It is the Load Entity’s or Transmission Entity’s responsibility to protect its own system and equipment from faults or interruptions originating on both PG&E’s side and the Load Entity’s or Transmission Entity’s side of the Interconnection. The Load Entity’s or Transmission Entity’s facilities shall be designed to isolate any fault or abnormality that would adversely affect the PG&E Power System or the electric Systems of other entities connected to the PG&E Power System. Some of the protective relays used in the Load Entity’s or Transmission Entity’s System Protection Facilities must be PG&E approved devices and must be set to coordinate with the protective relays at the PG&E line breaker terminals for the line to which the Load Entity or Transmission Entity is connected. Typical PG&E minimum requirements would consist of three single phase overcurrent relays and would be designed and set to trip the interrupting device closest to the point interconnection with PG&E. The Load Entity or Transmission Entity shall provide, install, own, and maintain such relays, circuit breakers and all other devices necessary 6 to promptly remove any fault contribution of the Load Entity’s or Transmission Entity’s facilities to any short circuit occurring on the electric system not otherwise isolated by PG&E equipment. Refer to Tables G2-4 for approved overcurrent relay types. Note: There may be additional protective equipment requirements, at the Load Entity’s or Transmission Entity’s cost, which PG&E will coordinate with the Load Entity (or Transmission Entity) or its representatives. PG&E assumes no liability for damage to Load Entity-owned or Transmission Entityowned facilities resulting from mis-coordination between the Entity’s protective device(s) and PG&E’s protective devices. PG&E recommends that the Load Entity or Transmission Entity acquire the services of a qualified electrical engineer to review its plans. The Load Entity or Transmission Entity shall, at its expense, install, operate, and maintain System Protection Facilities in accordance with applicable ISO, WECC and NERC requirements and in accordance this Handbook. The protective devices shown in Table L2-1 may or may not be required for Load Entities as determined by PG&E on a case-by-case basis. Typically, a 230 kV Ring or Breaker-and-a-Half (BAAH) substation bus service may require all of the relays listed, while a 60 kV radial service may require only phase and ground overcurrent relays. Most line relaying depends on the existing system configuration, the existing protection, 5

Refer to Appendix F for a description of pilot protection requirements, the associated transfer trip equipment, communications circuits monitoring, and commissioning test requirement. 6 These facilities in addition to other protection facilities are termed System Protection Facilities.

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and line characteristics such as impedance, voltage, ampacity and available fault duty, at the location in question. Fault-interrupting equipment should usually be located at the point of interconnection to PG&E, or as close to the interconnection point as practicable—typically within one span of overhead line or 200 feet of unspliced underground cable for transmission interconnection and 50 feet of overhead line or 100 feet of unspliced underground cable for distribution interconnections. Neither party should depend on the other for the protection of its own equipment. Refer to PG&E DCS Standard D-S0407 “Electric Primary Service Requirements” in Appendix P for the detailed distribution primary service requirements. For all relays required for the particular installation, a test report (see Form G2-2, Section G2) is mandatory, prior to energizing and every four years. The Load Entity or Transmission Entity shall provide test reports to PG&E, from a qualified testing firm obtained by the entity, a minimum of ten (10) working days prior to energizing. Refer to Section L5 for information regarding the pre-parallel inspections. On-site power (120 volts ac typically) is required for the test equipment. Circuit breakers must be tested every eight years after the pre-parallel inspection. Facilities that fail to meet the above testing requirements are subject either to a delay in service or to being disconnected from the PG&E Power System.

L2.2. RELIABILITY AND REDUNDANCY The protection system must be designed with enough redundancy that failure of any one component still allows the facility to be isolated from the PG&E system under a fault condition.

L2.3. RELAY SPECIFICATIONS RELIABILITY AND REDUNDANCY All load facilities or transmission facilities interconnected to PG&E’s transmission system shall use utility grade relays, which are much more accurate and reliable than industrial grade relays. Utility grade relays also have targets to facilitate testing/troubleshooting and typically have draw-out cases. Utility grade auxiliary relays must be used in the tripping circuits of utility grade protection relays. All such relays must include manually resettable relay targets. Their power supplies must be powered by station battery DC voltage and must include a DC under-voltage detection device and alarm. All proposed relay specifications and settings, for those relays which impact PG&E reliability and/or safety, shall be submitted to PG&E for approval prior to ordering (see Tables G2-4, G2-5, and G2-6 in Section G2). Load Entities or Transmission Entities who fail to submit relay specifications for approval shall risk the possibility of not being able to interconnect with PG&E (refer to Electric Rule 2). In some cases where PG&E may be unfamiliar with a specific proposed relay, PG&E may perform tests on relays provided by the Load Entity or Transmission Entity for approval, or request that test and supporting data from the manufacturer be supplied by the Load Entity or Transmission Entity. Such tests shall be performed at the Load Entity’s or Transmission Entity’s

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expense and prior to PG&E approval of the relay for interconnection use 7. Approval of relays shall not indicate the quality or reliability of a product or service. No endorsements or warranties shall be implied.

L2.4. LINE PROTECTION Line-protection relays must coordinate with the protective relays at the PG&E breakers for the line on which the facility is connected. The typical protective zone is a twoterminal line section with a breaker on each end. In the simplest case of a load on a radial line, current can flow in one direction only, so protective relays need to be coordinated in one direction and do not need directional elements. However, on the typical transmission system, where current may flow in either direction depending on system conditions, relays must be directional. The complexity and the required number of protective devices increase dramatically as the number of terminals increases in each protective zone. With two terminals in a protective zone, there are two paths of current flow. With three terminals there are six paths of current flow, and so on. In coordinating a multi-terminal protective relay scheme, PG&E may require the installation of a transmission line protective relay at the Load Entity’s or Transmission Entity’s substation site particularly if a three-terminal permissive overreach transfer trip (POTT) scheme or a carrier blocking scheme is employed to protect the line. This line relay would be installed at the Load Entity’s or Transmission Entity’s expense as part of a Special Facilities Agreement according to applicable tariffs. Because this line relay is part of a scheme which is designed to protect the PG&E transmission system, PG&E must ensure the maintenance, testing and reliability of this particular type of relay7. In addition, the breaker’s relays must be set to have overlapping zones of protection in case a breaker within any given zone fails to clear. The line protection schemes must be able to distinguish between load, inrush and fault currents. Multiple terminal lines become even more complex to protect. Existing relay schemes may have to be reset, replaced, or augmented with additional relays at the Load Entity’s or Transmission Entity’s expense, to coordinate with the Load Entity’s or Transmission Entity’s new facility. The PG&E required relays must be located so that a fault on any phase of the PG&E line shall be detected. If transfer trip protection is required by PG&E, the Load Entity or Transmission Entity shall provide at its expense a voice-grade communications circuit. This circuit may be a communication line from the telephone company or a dedicated cable. The line must have high-voltage protection equipment on the entrance cable so the transfer trip equipment will operate properly during fault conditions. (For detailed description of protection requirements of the transfer trip equipment, refer to Appendix F).

7

There are additional system tests associated with communication-assisted protection. These tests (also referred to as end-to-end satellite tests) require all terminals of a transmission line to be tested as a system and include the protection, communication equipment and medium between the interconnected terminals. Refer to Appendix F for more information.

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PG&E Transmission Interconnection Handbook

Table L2-1 below lists the minimum protection that PG&E typically uses on its own installations. Higher voltage interconnections require additional protection due to the greater potential for adverse impact to system stability, and the greater number of customers who would be affected. Special cases such as distribution-level network interconnections, if acceptable, may have additional requirements. The acceptability and additional requirements of these interconnection proposals shall be determined by PG&E on a case-by-case basis.

L2.4.1. Fault-Interrupting Devices The fault-interrupting device selected by the Load Entity or Transmission Entity must be reviewed and approved by PG&E for each particular application. There are three basic types of fault-interrupting devices: •

Circuit Breakers



Circuit Switchers



Fuses

PG&E will determine the type of fault-interrupting device required for a load facility, based on the available fault duty at the interconnection point, size of load, the local circuit configuration and the existing PG&E protection equipment

TABLE L2-1 BASIC PROTECTIVE DEVICES Protection Device

Phase Overcurrent (Radial systems) Ground Overcurrent (Radial systems) Phase Directional Overcurrent Ground Directional Overcurrent or Transformer Neutral Distance Relay Zone 1 Distance Relay Zone 2 Distance Relay Carrier Ground Directional Overcurrent Carrier Distance Relay Carrier Block Pilot Wire Permissive Overreaching Transfer Trip (POTT) or Hybrid Power Fail Trip4 Direct Transfer Trip

Device 3 Numbe r 50/51 50/51N 67 67N 50/51N 21Z1 21Z2 21Z2C 67NC 21Z3C 87L 21/67T 27 TT

34.5 kV or less

44 kV 60 kV or 70 kV

X X

X X X1 X1

X1 X2

115 kV

230 kV

X X

X

X1 X1 X1 X1 X1 X1 X1

X X X X X X X

X1 X2

X1 X2

Table L2-1 Notes: 1

May be required by PG&E depending on local circuit configurations.

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PG&E Transmission Interconnection Handbook

2 Transfer trip may be required on load transmission interconnections depending on PG&E circuit configuration and loading, as determined by PG&E. Typically, transfer trip is required on multi-terminal lines. 3 Refer to Table G2-1 (Section G2) for device number definitions and functions. 4 Power failure tripping may be required on load transmission interconnections to facilitate restoration of customer load after a transmission line or area outage.

L2.4.1.1. Circuit Breakers A three-phase circuit breaker at the point of interconnection automatically separates the Load Entity’s or Transmission Entity’s equipment from the PG&E system upon detection of a circuit fault. Additional breakers may be installed in the Load Entity’s or Transmission Entity’s equipment to facilitate operating and protecting the facility, but they are not required by PG&E. The interconnection breaker must have sufficient capacity to interrupt the maximum available fault current at its location. It must be equipped with accessories to: •

Trip the breaker with an external trip signal supplied through a battery (shunt trip);



Telemeter the breaker status when it is required; and



Lock out if operated by protective relays required for interconnection.

Generally, a three-phase circuit breaker is the recommended faultinterruption device at the point of interconnection. It is typically required due to its simultaneous three-phase operation and its ability to coordinate with PG&E line-side devices.

L2.4.1.2. Circuit Switchers A circuit switcher is a three-phase fault-interrupter with limited fault interrupting capability. These devices have typically been used at voltages of 115 kV and below, and may be substituted for circuit breakers if the fault duty is within the interrupting rating of the circuit switcher. With PG&E approval, some circuit switchers with blades can double as the visual open disconnect switch between the metering transformers and the main transformer of the Load-only Entity. Since circuit switchers do not have integral current transformers, they must be installed within 30 feet of the associated current transformers to minimize the length of the unprotected line/bus section.

L2.4.1.3. Fuses PG&E may approve the use of fuses for load-only facilities if they coordinate with the PG&E line-side devices for both phase and ground faults. In limited cases, fuses may be used as a primary protective device (e.g. rural, 60 kV, 70 kV and 115 kV lines, where the Load Entity’s 49

PG&E Transmission Interconnection Handbook

substation is 12 MVA or less). However, if fuses are approved by PG&E, the Load Entity should consider installing a negative sequence relay and/or other devices to protect its facility against single-phase conditions. Fuses are single-phase, direct-acting, sacrificial links that melt to interrupt fault current and protect the equipment. The blown fuses must be replaced manually after each fault before the facility can return to service. Overhead primary fuses must be replaced by trained, qualified personnel. Since fuses are single-phase devices, they may not all melt during a fault and thus may not automatically separate the Load Entity’s system from PG&E. Large primary fuses which do not coordinate with the PG&E substation breaker ground relays shall not be allowed. Otherwise, this could cause all the customers on the circuit to lose power due to a fault inside the Load Entity’s facility.

L2.5. STANDBY/BACKUP SOURCE L2.5.1. Standby Source In cases where the Load Entity’s load or a load served by the Transmission Entity requires a high level of reliability, the Load Entity can request both a transmission source and a back-up distribution or transmission source, at the Entity’s expense. Normally, when the Entity’s load is transferred from the primary source to the standby source or from the standby source to the primary source, a momentary outage (drop-and-pickup operation) is required. When the Load Entity or the load supplied by the Transmission Entity is being fed from the back-up source and wants to transfer the load back to the primary source with a parallel operation (make-before-break), the following requirements must be met: •

Ratios and electrical connections of the transformers on both sources must be well matched to minimize circulating currents.



Impedance of the transformers and the relative phase angles of the sources must be such that any “through load” (i.e. load flowing through the Load Entity’s or Transmission Entity’s electrical system to other customers) does not cause overloads.



Protection must not be degraded during the parallel transfer operation, and neither PG&E’s nor the Load Entity’s or Transmission Entity’s equipment must become over-stressed.



The transfer switches, one on each side of the Load Entity’s load (or the load served by the Transmission Entity), must be controlled by an automatic interlock scheme to minimize the time the parallel is in effect. Thus the transfer switches must be circuit breakers or other suitably rated, automatically controlled switches. Note that the available fault duty will be increased and the Load Entity’s or Transmission Entity’s equipment may be

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overstressed while the two circuits are paralleled so it is very important to make the parallel period as short as possible, typically one second or less. •

Each parallel transfer operation can only proceed after specific approval has been given by PG&E. In some cases, additional protective devices and special operating procedures may be required to avoid endangering customers and/or PG&E facilities. ay withhold approval if, in its sole judgment, the above requirements have not been PG&E’s approval must be obtained prior to parallel transfer operation. PG&E mmet, or if a previously unforeseen factor or change in conditions is deemed to jeopardize operator or public safety or reliability to customers.



The Load Entity or Transmission Entity must assume all liability for any problems or damage resulting from any parallel transfer operation.

L2.5.2. Backup Generators Refer to Section G2 for a discussion of back-up/emergency generators.

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PG&E Transmission Interconnection Handbook

Section L3: SUBSTATION DESIGN FOR LOAD-ONLY ENTITIES AND TRANSMISSION-ONLY ENTITIES PURPOSE This section provides substation design information for Load Entities interconnected at transmission voltage and Transmission Entities. Supplemental information is provided in the Planning Guide for Single Customer Substations Served from Transmission Lines (Refer to Appendix D). Design information for interconnecting at a distribution voltage will be provided by PG&E, upon request.

L3.1. DEAD-END STRUCTURE The Load Entity or Transmission Entity shall supply the structure at which PG&E shall dead-end or terminate its transmission conductors. PG&E shall supply the insulators at the entity’s expense. The entity shall supply the associated hardware for the transmission connection and the conductor up to the first device. The entity’s dead-end structure shall meet the specifications of Table L3-1 below.

Table L3-1 DEAD-END STRUCTURE SPECIFICATIONS VOLTAGE

MINIMUM PHASE SEPARATION

60 kV

7 ft.

MINIMUM CLEARANCE (live part to structure) 2 ft. 6 in.

70 kV

7 ft.

2 ft. 6 in.

32 ft.

#4/0 al

1520

115 kV

10 ft.

3 ft. 9 in.

34 ft.

715 kcmil al #4/0 al

2700 1520

230 kV

18 ft.

7 ft. 3 in.

34 ft.

MINIMUM CLEARANCE phase-to- ground (per GO 95)* 32 ft.

MINIMUM CONDUCTOR SIZE

TENSION PER PHASE IN FT•LB.

#4/0 al 715 kcmil al

1520 2700

715 kcmil al

2700

954 kcmil ACSR 1113 kcmil AACC

2700-6800 2700-6800

* The actual minimum height at which the conductor lands on the structure shall be such that the conductor height at mid span meets these requirements.

L3.2. TRANSFORMERS Before ordering the transformer, the Load Entity or Transmission Entity shall submit the transformer nameplate data to PG&E for approval, because the normal operating voltage in some parts of the system may deviate slightly from the nominal voltages. Approval by PG&E does not imply warranties or endorsement. Load Entities or Transmission Entities interconnecting to 60 kV, 70 kV or 115 kV facilities should be aware that at some future date PG&E may convert those facilities to a higher voltage. It would then be the entity’s responsibility to maintain, at the entity’s expense, compatibility between the entity’s and PG&E’s facility.

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PG&E recommends a high-side delta, low-side grounded wye transformer bank for interconnection. Any other connections may require additional protection, as determined by PG&E. The use of a delta connection also helps to suppress harmonics, helping to keep power quality at acceptable levels. If the entity chooses to install lightning arrestors, the arrestors must be on the transformer side of the fault-interrupting devices.

L3.3. VOLTAGE REGULATION PG&E maintains transmission voltages at levels required for economic and reliable transmission of electricity. Regulation to keep voltage variations within limits acceptable to end-use entities is provided typically on distribution. An entity interconnecting at transmission voltage needs to understand that voltage regulation at transmission voltage levels is different from distribution voltage. For this reason, Load Entities or Transmission Entities are strongly urged to install their own voltage regulation equipment. The entity should contact PG&E regarding the typical range of operating voltages in the area. PG&E usually purchases transformers with a high-side, nominal center tap, and with two taps above and two taps below, each at 2.5 percent of the nominal voltage. The nominal PG&E voltages are 60 kV, 70 kV, 115 kV and 230 kV, but in some areas of the PG&E system, voltages may run significantly higher or lower. The Load Entity or Transmission Entity is advised to contact PG&E before ordering its transformer. PG&E transformers are usually equipped with a low-side regulator or load tap changer (± 7.5 percent or ± 10 percent).

L3.4. POWER FACTOR The CAISO Tariff, effective on March 31, 1998, specifies that all loads connected directly to the ISO grid are to maintain a power factor between 0.97 lag and 0.99 lead, as measured at the point where the retail facilities interconnect with the ISO-controlled facilities; i.e., the high voltage side of the distribution and entity-owned transformer banks. The ISO is currently developing penalties, which, subject to any required regulatory approvals, will be applied to the Scheduling Coordinators for Load Entities’ non-compliance to this power factor requirement.” Many PG&E Load Entities with a transmission connection receive Traditional Bundled Service under electric tariffs that provide for a billing adjustment using a reference power factor of 0.85. Those entities with power factors less than 0.85 incur a penalty and those with power factors greater than 0.85 receive a credit. Receiving service under these electric tariffs does not negate the need to meet the provisions of the CAISO Tariff. However, PG&E would continue to apply the power factor provisions contained in the existing tariffs to all transmission-connected Load-only Entities. Thus, an entity whose power factor is within, or corrects its power factor to be within, the ISOacceptable range would receive a billing credit to the extent it exceeds the 0.85 reference power factor.

L3.5. CIRCUIT BREAKER OR OTHER FAULT INTERRUPTING DEVICES See Section L2, Protection and Control Requirements.

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L3.6. SWITCHES Manual disconnect switches, tap switches and line selector switches are required as described below:

L.3.6.1. Manual Disconnects For a transmission interconnection, there shall be manually operated disconnects on both sides of the metering PT/CTs. The first manual disconnect device must be at the point of interconnection with PG&E. This device would be operated by PG&E and is used to establish a visually open working clearance for maintenance and repair work in accordance with PG&E safety rules and practices. The disconnect device must not be used to make or break parallels between the PG&E system and the Load Entity’s or Transmission Entity’s substation. It shall be a gang-operated, three-pole switch. The device enclosure and operating handle (when present) shall be kept locked at all times with a PG&E lock. If the disconnect device is PG&E-owned, it shall be installed by PG&E at the Load Entity’s or Transmission Entity’s expense. If the device is to be located in the entity’s substation, it must be owned, furnished and installed by the entity. Only devices specifically approved by PG&E may be used. PG&E personnel must inspect and approve the installation before service is energized. The device shall be physically located for ease of access and visibility to PG&E personnel. When installed in the entity’s substation, the device shall normally be located close to the metering. The PG&E-operated disconnect shall be identified with a PG&E¬designated switch number plate. The second manual disconnect device is required between the metering units and the circuit breaker or fault-interrupting device. This device may be operated by the entity and need not have a PG&E lock. This device would be owned, furnished and installed by the entity. Disconnect devices shall have the following specifications: •

Must be rated for the voltage and current requirements of the particular installation.



Must be gang-operated.



Must be weatherproof.



The first disconnect switch, at the point of ownership change, must be lockable in both the open and closed positions with a standard PG&E lock.



Proposed switch specifications must be submitted to PG&E for approval, preferably prior to ordering. For coastal environments, it’s preferable to have copper blade switches, and/or non-wash insulators.

Switch operating platforms should be installed with disconnect devices. Appendix D (Document 034851, “Steel Grating Type Switch Operating Platforms”) contains information on the:

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PG&E Transmission Interconnection Handbook



Size and hold weight of platform



Size of foundation



Method of bonding to the ground grid.

L3.6.2. Tap Switch Tapped connections to the Grid may also require a switch at the tap. The purpose of this switch would be to disconnect the tap line from the main line in the event the tap line needs to be de-energized while keeping the main line in service. Thus the switch would provide a way to isolate trouble or to perform maintenance on the tap line without a long-term service interruption on the main line. The need for a tap switch depends on several factors including the length of the tap line, the exposure of the tap line to potentially adverse elements and the criticality of the main line. PG&E will evaluate these factors and will determine whether such a switch is needed. If needed, this switch would be in addition to the disconnect switches described above. The tap switch would be owned, furnished and installed by PG&E under a Special Facilities Agreement in accordance with applicable electric tariffs.

L3.6.3. Line Selector Switches Line selector switches are installed on one or both sides of a single-tap in order to provide operational flexibility in providing service to customers on the tap line (See Appendix O). They are used to reduce the duration of customer outages for planned maintenance in the main line and to restore service in the case of an unplanned interruption of the main line. At PG&E’s discretion, a selector switch may not be required if the distance from the new single-tap interconnection to either end of the transmission line or to an existing selector switch on the line is relatively short (one mile or less), and have minimal exposure to causes of outages (trees, traffic, etc.). The selector switches would be owned, furnished and installed by PG&E under a Special Facilities Agreement in accordance with applicable tariffs.

L3.7. INTERCONNECTION OF LOAD ENTITY’S OR TRANSMISSION ENTITY’S SUBSTATION WITH PG&E’S SYSTEM For reliable transmission-level interconnection, PG&E will usually provide a substation bus connection from a nearby transmission line. Sometimes a line position can be available at the nearest existing substation. To accommodate an entity’s request for improved reliability, PG&E can provide an additional source at the entity’s expense in accordance with Electric Rule 2. The interconnection facilities and any additional facilities needed to accommodate improved service reliability shall be covered by a Load Special Facilities Agreement (refer to Appendix K for a CPUC jurisdictional example).

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L3.8. LOAD ENTITY OR TRANSMISSION ENTITY INTERFERENCE WITH POWER QUALITY Under Electric Rule 2, the Load Entity or Transmission Entity is responsible for providing facilities and equipment to avoid unacceptable interference which may adversely affect PG&E’s operations or service provided to other customers, whether by voltage fluctuations, harmonics, or inductive interference. The Load Entity or Transmission Entity is responsible for the costs of mitigating interference it causes. Phase Unbalance: Also as outlined in Electric Rule 2, the Load Entity or Transmission Entity is responsible to maintain their demand load balance to which the difference in amperes between any two phases at the Load Entity’s peak load should not be greater that 10% or 50 amperes at the service delivery entrance, whichever is greater. Harmonics: In regards to harmonic issues, it is advised for the Load Entity or Transmission Entity to follow IEEE 519-1992, Recommended Practices and Requirements for Harmonic Control in Electrical Power Systems as a guide to address acceptable limits of voltage and current distortions.

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Section L4: OPERATING PROCEDURES AND REQUIREMENTS FOR LOAD-ONLY AND TRANSMISSIONONLY ENTITIES PURPOSE The purpose of this section is to provide Load Entities and Transmission Entities with a general understanding of applicable PG&E and ISO operating procedures and requirements. PG&E and the Load Entity shall execute a PG&E Load Operating Agreement (Appendix I) prior to commencing interconnected operation.

APPLICABILITY The following operating procedures apply to interconnections with PG&E which do not include generation facilities. If the interconnection involves both generation and load, or both generation and transmission, or transmission facilities interconnecting network that connects to generation, then Section G4 shall also apply. The PG&E operating agreement is in addition to any agreements that the Independent System Operator (ISO) may require to be in place for loads or transmission facilities connected to the ISO Controlled Grid.

L4.1. JURISDICTION OF THE ISO AND THE DESIGNATED PG&E CONTROL CENTER Beginning 3/31/98 the California Independent System Operator (ISO) assumed Operational Control over most of the PG&E transmission grid operating at voltages of 60 kV and above. The jurisdiction of the ISO includes control of operations involving customer loads that are directly connected to the ISO controlled grid as described in the CAISO Tariff and any written agreements between the Load Entity or Transmission Entity and the ISO. Notwithstanding the operational jurisdiction of the ISO over most of the PG&E transmission system, it is expected that the ISO Protocols will delegate certain operational activities to PG&E on selected parts of the ISO Controlled Grid operating at 115 kV and below. Under the ISO’s control and instruction, PG&E will continue to perform all physical switching operations, including de-energization and restoration of PG&E-owned facilities. PG&E will continue to serve as the primary point of contact for Load Entities that are connected to the ISO-controlled grid or the PG&E distribution system and will communicate and coordinate with the ISO as specified in the ISO’s Protocols, Operating Procedures and tariffs.

L4.2. COMMUNICATIONS The Load Entity or Transmission Entity shall maintain telephone service to PG&E from the interconnection facility location. If the location is remote or unattended, telephone service shall be provided to the nearest location normally occupied by the customer (acting on its own behalf or through its designated facility operator). PG&E and the facility operator shall maintain operating communications through the Designated PG&E Control Center. The facility operator shall be accessible at all times and shall provide to

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PG&E Transmission Interconnection Handbook

the Designated PG&E Control Center a 24hour phone number where such facility operator may be reached. The facility operator shall maintain, in a prominent location, the name of the Designated PG&E Control Center along with applicable instructions and a list of necessary telephone numbers and coded alarms for such facility (refer also to Sections L1-D.3 and L1-T.3).

L4.3. ATTENDED LOAD FACILITIESOR TRANSMISSION FACILITIES REQUIREMENTS L4.3.1. Voltage Control Device Operation and Special Service Requirements The facility operator shall operate any voltage control facilities at the direction of the Designated PG&E Control Center and in accordance with applicable provisions of the PG&E Load Operating Agreement (Appendix I), applicable tariffs, ISO requirements, and other electric service schedules or agreements. The facility operator shall post voltage orders from the Designated PG&E Control Center prominently so that any relief or backup operator is aware of the current PG&E voltage instruction. The Load Entity or Transmission Entity is responsible for the safe interruption and de-energization of customer-owned voltage-control devices (e.g., shunt capacitors).

L4.3.2. Connecting and Separating from the Power System The facility operator shall notify the Designated PG&E Control Center before connecting to or separating from the ISO Controlled Grid and/or the PG&E Power System. For unexpected separations, the facility operator shall inform the Designated PG&E Control Center of the nature of the problem (i.e., overvoltage, underfrequency, ground fault, remedial action, etc.) and report any relay target operations. Relays must be capable of retaining targets upon loss of power. Refer to Section L4.4 below for unattended facilities with automatic or remotely initiated restoration.

L4.3.3. Clearances and Switching Requests The facility operator must request a clearance from the Designated PG&E Control Center a minimum of 168 hours (seven calendar days ) in advance if connected to the 230 kV or 120 hours (five calendar days) in advance if connected at 115 kV or below. PG&E shall handle any required coordination with the ISO, and shall notify the Load Entity’s or Transmission Entity’s facility operator of any PG&E plans to take a clearance which affects the customer. As established in the PG&E Load Operating Agreement, each interconnected facility shall have installed an approved disconnect or other switching device for operation by the facility operator as a clearance point. The disconnect switch must be capable of being locked open and be accessible to PG&E personnel.

L4.3.4. Unusual or Emergency Conditions For System Emergencies impacting the ISO Controlled Grid, the ISO is 58

PG&E Transmission Interconnection Handbook

responsible for managing the emergency and for restoration. PG&E is responsible for complying with all directions from the ISO regarding management and alleviation of the System Emergency, unless such compliance would impair the health and Safety of personnel or the general public. PG&E will be responsible for all communication with Load Entities regarding emergencies, as described below, and will coordinate such communications with the ISO as required by the CAISO Tariff, the TCA, and applicable protocols and instructions. Unusual operating conditions or other factors that have affected or may affect the ISO Controlled Grid and/or PG&E’s electric system (e.g. abnormal voltages or loading, or unbalanced loading) must be reported to the Designated PG&E Control Center as soon as possible. Conditions imperiling life or property must be reported to the Designated PG&E Control Center immediately. The Designated PG&E Control Center shall be notified of any forced outage. The Switching Control Center shall notify the facility operator of any unusual PG&E or ISO Controlled Grid conditions that may affect the Load Entity’s facility. During any system emergency the facility operator shall follow the instructions of the Designated PG&E Control Center. Interruptible Load Entities may not reconnect until authorized by the Designated PG&E Control Center.

L4.3.5. Other Communications The facility operator shall notify the Designated PG&E Control Center of the following: •

Any replacement, modification or removal of any interconnection facilities (e.g., transformer, breaker, disconnect, relays, remedial action equipment, etc.).



Results of three-year or four-year bench tests on all PG&E-required relays.



Results of six-year or eight-year tests on interconnection circuit breakers and transformers.



Any relay operations and the targets of the relay that caused the facility to separate, if applicable.



The time of all separations from and reconnections to the PG&E system.



The time of the change in operating status (i.e. opened or closed) of any voltage control device.



Whenever any live line work is being performed and, in addition, whenever such work causes any trouble.

The facility operator shall ensure that any reported time readings are accurate, and maintain their accuracy compared to a reliable time standard.

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L4.4. UNATTENDED LOAD FACILITIES REQUIREMENTS L4.4.1. Verification of Energized Circuit Unattended facilities having remotely initiated restoration may interconnect only after verifying with PG&E that the circuit to which the facility is to be connected is energized by a PG&E-approved source of energy.

L4.4.2. Separation/Restoration After any separation from ISO Controlled Grid or the PG&E’s system, if automatic restoration equipment has locked out or if the connection was separated manually, the facility operator must notify the Designated PG&E Control Center and receive permission before reconnecting.

L4.5. SPECIAL SERVICE REQUIREMENTS If the Load Entity or Transmission Entity is participating in a load management program or other interruptible service schedule, the customer’s facilities may also be required to add equipment that will let it respond to: •

system or local load levels, or



system frequency deviations, or



other direct or automatic control from PG&E

In addition, where identified in an Interconnection Study or required by the ISO, the facility may be required to participate in a Remedial Action Scheme to maintain or enhance the operating capability or performance of the ISO Controlled Grid and PG&E electric system. During any period in which primary relays or protective devices are out of service, backup or secondary relays must be available to clear faults. If the backup relays malfunction, the Load Entity or Transmission Entity must keep an operator ready to manually perform operations that may be necessary. Note that the ISO has special operation, maintenance and replacement requirements for certain relays, designated by the ISO as Grid Critical Protective Devices, and such relays must be treated according to the requirements of the CAISO Tariff and TCA. When restoring any relays that have been out of service, the customer’s facility operator shall verify that any such relay output contact, which is normally open, is in fact open.

L4.6. LOAD ENTITY OR TRANSMISSION ENTITY INTERFERENCE WITH POWER QUALITY Under Electric Rule 2, the Load Entity or Transmission Entity is responsible for operating its facilities and equipment to avoid unacceptable interference which may adversely affect PG&E’s operations or service provided to other customers, whether by voltage fluctuations, harmonics, or inductive interference. As an example, total voltage harmonic distortion may not exceed 5 percent. The Load Entity or Transmission Entity is responsible for the costs of mitigating interference it causes. 60

PG&E Transmission Interconnection Handbook

Phase Unbalance: Also as outlined in Electric Rule 2, the Load Entity or Transmission Entity is responsible to maintain their demand load balance to which the difference in amperes between any two phases at the Load Entity’s peak load should not be greater that 10% or 50 amperes at the service delivery entrance, whichever is greater. Harmonics: In regards to harmonic issues, it is advised for the Load Entity or Transmission Entity to follow IEEE 519-1992, Recommended Practices and Requirements for Harmonic Control in Electrical Power Systems as a guide to address acceptable limits of voltage and current distortions.

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Section L5: PRE-ENERGIZATION TEST PROCEDURES FOR LOAD-ONLY ENTITIES AND TRANSMISSION-ONLY ENTITIES PURPOSE The following is PG&E's procedure for pre-energization inspections. For PG&E to provide the Load Entity or Transmission Entity with timely service it is important that all time requirements be met. It is the Load Entity’s or Transmission Entity’s responsibility to ensure that any inspections required by local government agencies are complete and permits signed off prior to the energize date. If the interconnection involves both generation and load, or both generation and transmission, or transmission facilities interconnecting network that connects to generation, then Section G5 shall also apply. NOTE: The following tests apply only to the equipment at the interconnection point, up to and including the main transformer, and the relays along with their connected circuits that are required by PG&E. Items marked (***) are the common requirements for both fused substations and substations protected by breakers or circuit switchers. Fused substations need meet only the requirements marked (***).

L5.1. TESTS REQUIRED FOR LOAD ENTITIES PRIOR TO ENERGIZING All tests outlined below must be completed and two copies of the test reports submitted to a PG&E representative a minimum of fifteen (15) working days before the requested energize date. All test reports require header information reflecting the equipment identification matching the one or three line diagrams. One line and three line diagrams, of the facility are required with the test reports. All requirements must be met and test reports approved at least three working days before the requested energize date.

L5.1.1. Proving Insulation For any of the megger tests below, a 2,500-volt DC megger or a hi-pot is preferred, but a 1,000-volt DC megger is acceptable. •

(***). T  he main transformer(s) must be meggered winding to winding and each winding to ground.



The circuit breaker(s) or circuit switcher(s) at the interconnection point that are operated by PG&E-required relays must be meggered in the following manner: a) Breaker open: each pole to ground, pole 1-2, pole 3-4, pole 5-6; b) Breaker closed: pole 1-ground, pole 3-ground, pole 5-ground; and c) If the poles are in a common tank or cell: pole 1-3, pole 3-5, pole 5-1.



(***). A  ll busses from the interconnection point to the main transformer must be meggered phase to phase and phase to ground.

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PG&E Transmission Interconnection Handbook



(***). T  he main transformer(s) and main breaker(s) must have a dielectric test performed on the insulating medium (gas or oil). This test is not required for factory-sealed circuit switcher interrupters.



(***). If the main transformer is fused, all fuses must be checked for continuity before energizing.

L5.1.2. Proving Ratios •

(***). T  he main transformer(s) ratio(s) must be proven either by using a turns ratio tester or a voltage ratio test on the final operating tap. This tap shall be recommended by PG&E to best match current transmission system voltages.

L5.1.3. Circuit Breakers and Circuit Switchers •

A minimum to trip test at 70 percent or less of the nominal DC control voltage must be performed on all circuit breakers or circuit switchers operated by PG&E-required relays.



A micro-ohm test must be performed on the main circuit breaker(s) or circuit switcher(s) at the interconnection point.



A timing test showing the time from trip initiation to main poles opening is required.

L5.1.4. Current Transformers and Current Circuits •

A saturation check should be made on all current transformers (CT’s) associated with the required PG&E relays. If this is not possible, a manufacturer’s curve is acceptable.



The ratio of all current transformers must be proven either by using current (primary to secondary) or voltage (secondary to primary).



Current transformers must be checked for proper polarity whenever they feed a PG&E-required directional relay, differential relay or impedance relay.



Current transformer circuits must be checked for proper connections, and continuity must be checked by applying primary current or secondary current at the current transformer block and reading proper current in each phase relay and the ground relay. Each test (primary or secondary) must be performed in all combinations to prove proper connections to all phase relays and ground relays. The current must be applied or injected to achieve a secondary reading of 5 amps in each relay to insure that no loose wiring or parallel current paths exist.



A single-phase burden check must be made on each phase of each current circuit feeding PG&E-required relays.



A megger check of the total circuit with the ground wire lifted must be done to prove that only one ground exists.

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L5.1.5. Relays •

All relays must be utility grade and PG&E-approved. If multi-functional relaying is used, some form of redundancy is required.



All relays must be field tested on site to their specified settings to verify the following:



Minimum operating point at which relay picks up (minimum pickup).



Time delays at three different current test points, in integral multiples of minimum pickup that closely characterize the relay time-current curve.



Phase angle characteristic of directional relay.



Pickup points at maximum torque angle (MTA) and ± 30° of MTA on impedance relays using the approved relay settings.



PG&E tolerances are listed below: o Current/Voltage/Time ± 10 percent o Impedance/Phase Angle ± 0.05 percent o Frequency ± 0.05 Hz



If a pilot relay system is required by PG&E, signal level checks must be performed to PG&E standards.

L.5.1.6. Primary Disconnect Switch •

(***). T  he primary disconnect switch at the point of interconnection shall be assigned a PG&E number by PG&E System Operations. The switch, platform and switch number target plate bracket must be constructed to PG&E’s Engineering Standard 034851 and Engineering Design Standard 454092. A switch number plate bracket shall be furnished by PG&E.

L5.2. ENERGIZING •

(***). I f possible, initial energizing of all equipment shall be done with a proven PG&E breaker. A test program outlining all steps to be taken to energize the equipment shall be written by a PG&E representative.



Trip checks of all required relays must be witnessed by a PG&E technical representative. This may require injecting a signal to trigger the relay. Jumpering the studs on the back of the relay is not acceptable. This is done to prove that the relay will handle the trip current of the breaker, and also provides relay targeting.



After load is placed on the substation a PG&E technical representative shall witness reading of load current in each phase relay and absence of load current in the ground relay. The relays shall then be sealed by the PG&E technical representative.



If differential relays and/or impedance relays are required by PG&E, a load check must be performed on the differential relays and a direction check must be

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performed on the impedance relays using load current. These tests shall be witnessed by a PG&E technical representative. •

All tests shall be performed by the Load Entity or its representative and observed by a PG&E representative. The Load Entity shall provide all test equipment and qualified personnel to perform the required tests. PG&E shall be there strictly as an observer.

L5.3. GENERAL NOTES •

The PG&E system has A-C-B counterclockwise rotation.



Any changes to PG&E-required protection equipment or major substation equipment (transformer, breaker, etc.) must be submitted to the PG&E representative for review and approval by the appropriate PG&E engineer prior to the changes being made.



Routine maintenance on PG&E-required protective relays and the breaker(s) must meet PG&E’s maintenance and test practices. After completion of these tests, test reports must be submitted to the PG&E representative for review and approval by the appropriate PG&E engineer. A PG&E technical representative shall then come to the customer’s facilities and reseal the PG&E-required relays.



Questions shall be directed to the local PG&E representative.

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Contact Information Sheet PG&E STATION CONST. TEST DEPT. BASIC INFORMATION REQUIREMENTS Name of Project: Site Address: Proposed Pre-Parallel Inspection and/or Testing Date: Type of Unit(s): Number of Units: MW or KW Each:

Time:

PG&E CONTACTS Project Manager: Phone:

Cell:

Pager:

Planning Engineer: Phone:

Cell:

Pager:

Sys Prot. Engineer: Phone:

Cell:

Pager:

Switching Center: Phone:

CLIENT CONTACTS Project Manager: Phone:

Cell:

Pager:

Site Contact / Name: Phone:

Cell:

Pager:

Design Engineer: Phone:

Cell:

Pager:

Testing Company: Tester: Phone:

Phone: Cell:

Pager:

BASIC NEEDS ASAP MINIMUM OF TWO WEEKS PRIOR TO REQUESTED PRE-PARALLEL DATE * Single Line Drawings * Three Line Drawings * Complete and Accurate G5-1 Form (approved by Planning Engineer) * All Relay Bench Test Reports * All Other Test Reports as Outlined In Section G5 of the Interconnection Hand Book

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PG&E Transmission Interconnection Handbook

Section G1: METERING REQUIREMENTS FOR TRANSMISSION GENERATION ENTITIES PURPOSE: This section specifies the metering requirements for Generating Entities interconnecting to PG&E’s Transmission Power System.

APPLICABILITY All wholesale generators (Participating Generators who sell power to the market), connected to the transmission system, must meet both PG&E and ISO metering requirements. PG&E metering is required for standby service. All other generators (not providing wholesale service) must meet PG&E’s metering requirements. Furthermore, all Generators 1 MW and above must meet all applicable WECC (Western Electricity Coordinating Council) metering standards. Load entities that install generator(s) to off-set all or part of their load are also subject to telemetering requirements of the generator(s). CPUC Rule 21 typically applies to such installations.

G1.1. BASIC METERING REQUIREMENTS FOR GENERATORS Metering location: PG&E and CAISO standard metering is required on the highvoltage side of the transformer for all Generatoring Entities. Exceptions may be granted if it can be demonstrated that high-side metering will create significant safety issues or impose extraordinary costs not typically associated with such metering. CAISO Metered Entities that have installed low side metering shall supply the Transformer Loss Correction (TLC) as specified in CAISO’s Metering Protocol Section. If it is not possible to install metering at the delivery point, the readings of the meter(s) shall be adjusted to correct for transformation and line losses. A two (2) percent adjustment factor for each stage of transformation shall be applied to the meter readings for bundled (full-service) PG&E customers. Metering equipment: Metered sites served at 60 KV and above, require structures mounted for combination metering units. In addition, a meter enclosure in accordance with Engineering Standard 063436, in Appendix C is required. Note: The metering enclosure shall be sized adequately to meet all applicable codes and standards. If the Interconnecting Customer wishes to include additional equipment such as line protective relays, telecommunication and/or EMS/SCADA equipment, the size must be adjusted accordingly. Foundation, structure and disconnect switches for mounting and disconnecting revenuemetering transformers (refer to Section L3.6.1). The support structure may be a pole or a platform-type structure, so long as it can support the CT/PT units. High-side revenuemetering shall have a minimum of two gang-operated, lockable disconnect devices to facilitate establishing a visual open on each primary side of the metering units. Refer to Engineering Standard. 063436 in Appendix C for more information.

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The meter enclosure shall be owned and maintained by the generating entity or Transmission Entity. The distance between the meter enclosure and the revenuemetering transformers must not exceed 50 feet to maintain the required metering accuracy. PG&E must approve any variance from this general rule. The enclosure must be located within and grounded to the substation ground grid. Access to the enclosure must be arranged so that PG&E personnel can read the meters without entering the substation yard. The enclosure must be equipped with an auxiliary 120-volt ac duplex plug, an overhead light, a light switch adjacent to the door, and a ground bus connected to the ground and mounted near the bottom of the wall where the meters are to be located. Meter panels specified by PG&E. Refer to the Green Book or Engineering Standard 063436 in Appendix C. All required conduits and junction boxes. A pull line must be installed in the conduit between the metering enclosure and the junction box at the base of the metering unit support structure to facilitate PG&E installing the metering unit secondary wires. Only PG&E’s revenue metering wire shall be installed in the conduit between the metering enclosure and the CT/PT units. Conduits may be metallic or non-metallic. A dedicated land line into the metering enclosure is required for the revenue meter. Where land line is not available, and cellular cell signals are acceptable, the use of cellular phone is acceptable. If the meter phone line cannot be dedicated to the meter, the generating entity shall obtain prior approval from PG&E’s local metering group to arrange for a line shared switch to be used with the meter being the secondary phone user. Metering Disconnects: This section applies to non-wholesale customers. High-side metering installations shall have a minimum of two gang-operated, lockable disconnect devices at the primary to facilitate establishing a visual open. Disconnect devices are necessary at the following locations: The first disconnect switch shall be installed at or near the point of interconnection with PG&E (this switch is PG&E-operated) The second disconnect switch shall be installed between the load side of PG&E's metering and the Generation Entity’s electrical facility (this switch is Generation Entity owned and operated). With PG&E’s approval, circuit switches with blades can double as the visual open disconnect between the metering transformers and the main transformer. If the Generating Entity deviates from this present design configuration PG&E approval is required prior to Generating Entity’s initial submission of related drawings or prints. If the Generator is a Qualifying Facility (QF) selling power to PG&E on a surplus sale basis, a separate disconnect device (generator or host-site owned and operated) is required on the metered side of the load. Refer to Figure G1-1, located near the end of this section, for typical interconnections.

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G1.2. DETAILED METERING REQUIREMENTS FOR GENERATORS The following sections describe the detailed requirements for metering electricity supplied by generators connected to or operating in parallel with the PG&E Transmission System.

G1.2.2. Metering Configurations For New Generators Metering configurations for the delivery of power into the PG&E Transmission System fall under the following two general classifications: Wholesale Generators: Wholesale generators that participate in the CAISO market must execute CAISO’s Participating Generating Agreement and meter their power deliveries in accordance with CAISO Tariff. Metering installations must comply with the Meter Certification Requirements and Standards set forth in the CAISO Tariff and Protocols. Meters for Participating Generators are required at the point of interconnection (Figure G1-2). Retail Generators: Power delivered to the generator entity is metered at or near the point of interconnection.

G1.2.3. Metering Requirements For New Generators The Generation Entity (either retail or wholesale) shall provide, install, own and maintain all mounting structures, conduits, meter sockets, meter socket enclosures, metering transformer cabinets and switchboard service sections of the size and type approved by PG&E and/or ISO. The Generation Entity may have the option to provide, own and maintain metering transformers, as specified by PG&E, rated at more than 600 volts when located within the Generation Entity’s substation and used for high-side metering, except when pole-top or metal-clad enclosure metering is used. In addition, wholesale generators are responsible for securing combination revenue metering PT/CT’s. Consult with PG&E Meter Engineering for information on combination revenue-metering voltage and current transformers. The Generation Entity must provide, install, own and maintain all facilities necessary to accommodate PG&E metering or an entity-owned metering which meets PG&E’s metering requirements. PG&E must receive and approve meterlocation and enclosure dimensional drawings prior to installation of metering equipment. Other requirements vary, depending on the amount of power delivered to PG&E. The distance between the meter and the revenue-metering transformers must not exceed 50 feet to maintain the required metering accuracy. PG&E must approve any variance from this general rule.

G1.2.3.1. Wholesale Generators Installation of meters: Generation Entities directly connected to CAISO Controlled Grid are responsible for installing, operating, and maintaining CAISO delivery meters in accordance with applicable CAISO

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requirements. Generation Entities connected to CAISO Controlled Grid are required to provide PG&E access to the Generation Entity’s meter.

G1.2.3.2. Metering Generator’s Loads Metering Generator Loads: When a Generation Entity delivers power to the PG&E Power System, electric service to the auxiliary load associated with the generator plant is also needed. Because deliveries to and from the plant must be separately recorded and treated as separate transactions under PG&E's tariffs, additional revenue-metering will be required in most cases. All meters shall be equipped to prevent reverse registration. In addition, when a generator enters into a service agreement with PG&E for stand-by service, the Generation Entity shall allow PG&E to tap onto CAISO metering circuit with the installation cost to be borne by the end-user (Generation Entity).

G1.3. Telemetering Requirements FOR GENERATOR MONITORING G1.3.1. For New Generation Facilities 1,000 kW or Greater For Generating Facilities 1,000 kW or greater, the following real-time data must at a minimum be telemetered to PG&E’s Control Centers as specified in Appendix F and CAISO, for each generating unit: •

kW



kVar



kWh



generator terminal voltage (kV)



customer substation breaker status



individual generating unit breaker status

A generator equipped with a voltage regulator and power system stabilizer (PSS) must also provide telemetering indicating their status. In addition, transmission kW, kVar, kV depending on the number of generating units and transmission configurations may be required. For protection circuits, a minimum number of alarms to be transmitted include the following: •

breaker trip,



transfer trip receive,



channel/equipment fail.

Telemetering equipment (usually a dual-ported RTU) shall be located in the metering enclosure. At the entity’s expense, PG&E may supply telemetering equipment at the Generation Entity’s site,. at PG&E's Grid Control Center in Vacaville and at the Designated PG&E Switching Center. Generating Entity is 70

PG&E Transmission Interconnection Handbook

responsible for procuring and maintiaining all telecommunication circuits in accordance with requirements detailed in Appendix F.

G1.3.2. For New Generation Facilities Less Than 1,000 kW On a case-by-case basis, PG&E may require telemetering for generators of less than 1,000 kW.

G1.4. METERING CURRENT AND VOLTAGE TRANSFORMERS FOR GENERATORS The customer will provide, install, own and maintain metering transformers when they are within the Generator’s substation, provided the metering transformers are approved by PG&E before installation and meet the following PG&E specifications: •

CTs and PTs cannot have a bypass switch.



CTs cannot be switched or fused.



Metering class PT/CTs (including Dual Winding devices) shall not be used for relaying purposes in the PG&E system. In particular, combination PT/CTs which are installed by PG&E or an approved meter installed by a qualified meter service provider shall not be connected to Generator’s protective relays or used to provide protection of Generator-owned equipment or devices. Refer to PG&E Guideline ETSP-G005 in Appendix C.



PG&E may grant exceptions to this policy and allow a dual winding PT/CT unit to be installed. However, in this case, the customer will be required to sign a waiver absolving PG&E from liability in the event of failure of dual winding unit or improper performance of the protective equipment due to, for example, saturation of the CT in the dual winding.



Metering transformers shall be tested by the manufacturer prior to pre-parallel inspection, and a certified transformer test report shall be provided to PG&E prior to installation. After installation, metering transformers shall be tested by the customer and a certified transformer test report shall be provided to PG&E. Periodic testing may be required for metering CTs or PTs.

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Figure G1-1 TYPICAL INTERCONNECTION Protection and Metering Installation for Surplus Sale PG&E Transmission System PG&E

Disconnect Device Operated by PG&E

Generation Facility

PG&E Metering

Point of Ownership change with PG&E

Generation Entity's Service Transformer

In

Generation Entity’s Load

PG&E1,2 Metering

CAISO3 Metering

Out

Disconnect Device Owned and Operated by Generation Entity

In

Disconnect Device Owned and Operated by Generation Entity

51G

Required Generator and System Protection4 Device Number 25

Dedicated Transformer Owned by Generation Entity 81U

81O

59

Generator Auxiliary Load

27

Synchronizing

Trips Breaker *

(Required for synchronous generators only)

High Side Breaker or Recloser B Owned by Generation Entity

P

Function

27

Undervoltage

A

51G

Ground Overcurrent

B

50/51V

A

59

Overcurrent with Voltage Restraint or Voltage Control Overvoltage

81O

Over Frequency

A

81U

Under Frequency

A

P

Line Protection

B

25 NOTES: AUX PT

1. A

Generator Breaker

2.

50/ 51V

3.

4.

G Generator

72

Additional metering and protection may be required on net generator output. Contact PG&E for details. Telemeterd data for generators 1 MVA or greater must be supplied through a PG&E meter equipped with analog outputs. When a wholesale generator is connected to the CAISO Controlled Grid, it is the Generator Entity’s responsibility to satisfy the CAISO’s delivery metering requirements. See Section G2 for a complete discussion of protection requirements.

A

PG&E Transmission Interconnection Handbook

Figure G1-2 TYPICAL INTERCONNECTION Protection and Metering Installation for Net Sale and Wholesale Transactions PG&E Transmission System PG&E

Disconnect Device Operated by PG&E

Generation Facility

PG&E1,2 Metering

Point of Ownership change with PG&E

Out In

CAISO3 Metering

Disconnect Device Owned and Operated by Generation Entity

51G

High Side Breaker or Recloser B Owned by Generation Entity

P

Required Generator and System Protection4 Device Number 25

27

Undervoltage

A

51G

Ground Overcurrent

B

50/51V

59

81O

59

Synchronizing

Trips Breaker *

(Required for synchronous generators only)

Dedicated Transformer Owned by Generation Entity

81U

Function

Generator Auxiliary Load

27

25

A

A

81O

Over Frequency

A

81U

Under Frequency

A

P

Line Protection

B

NOTES: 1.

AUX PT

Overcurrent with Voltage Restraint or Voltage Control Overvoltage

Generator A Breaker

2.

50/ 51V

3.

4.

G Generator

73

Additional metering and protection may be required on net generator output. Contact PG&E for details. Telemeterd data for generators 1MVA or greater must be supplied through a PG&E meter equipped with analog outputs. When a wholesale generator is connected to the CAISO Controlled Grid, it is the Generator Entity’s responsibility to satisfy the CAISO’s delivery metering requirements. See Section G2 for a complete discussion of protection requirements.

PG&E Transmission Interconnection Handbook

Section G2: PROTECTION AND CONTROL REQUIREMENTS FOR TRANSMISSION GENERATION ENTITIES Purpose This section specifies the requirements for protective relays and control devices for Generation Entities interconnecting to the PG&E Power System.

Applicability The applicable protective standards of this section apply to all Generators interconnecting to any portion of the PG&E’s Transmission Power System, except those that qualify for treatment under the CPUC Rule 21. These standards, which govern the design, construction, inspection and testing of protective devices, have been developed by PG&E to be consistent with Applicable Regional Reliability Criteria 8 and to include appropriate CAISO consultation. The CAISO, in consultation with PG&E, may designate certain new or existing protective devices as CAISO Grid Critical Protective Systems. Such systems have special CAISO requirements, e.g., for installation and maintenance, as described in the CAISO Tariff Section 5 and the TCA Section 8. In the future, the CAISO may develop its own standards or requirements applicable to certain interconnections, and also will review and comment on interconnection requests to the CAISO Controlled Grid. Refer to the Introduction of this handbook. In addition, for Generation Entities connecting directly to a Third Party: A third party must coordinate with the CAISO, PG&E (as the Transmission Owner), and the Generation Entity, as needed, to ensure that any CAISO Controlled Grid Critical Protective Systems, including relay systems, are installed and maintained in order to function on a coordinated and complementary basis with the protective systems of the Generation Entity and the PG&E Power System, in accordance with the CAISO Tariff Section 4 and the CAISO-UDC Agreement, both available on the CAISO website.

G2.1. Protective Relay Requirements An important objective in the interconnection of facilities to the PG&E Power System is minimizing the potential hazard to life and property. A primary safety requirement is the ability to disconnect immediately when a fault is detected. The protection equipment for a generation facility must protect against faults within that facility and faults on the PG&E Power System. A generation facility must also trip offline (disconnect from the PG&E Power System automatically) when PG&E’s power is disconnected from the line into which the unit is generating.

8

See Glossary for more information. NERC reliability standards for transmission voltage levels of 100kV and above require the use of two separate voltage and current sources to be connected to the primary and alternate line protective relays respectively. Conformance to WECC and NERC standards are required for interconnections above 100kV voltage levels.

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In view of these objectives, PG&E requires line-protective equipment to either; 1) automatically clear a fault and restore power, or 2) rapidly isolate only the faulted section so that the minimum number of customers are affected by any outage. Due to the high energy capacity of the PG&E transmission system, high-speed fault clearing may be required, to minimize equipment damage and potential impact to system stability. The requirement of high-speed fault clearing will be determined by PG&E on a case-by-case basis. To achieve these results, relays and protective devices are needed. The requirements are outlined in the following pages and in Appendix R. Some protection requirements can be standardized; however, most line relaying depends on generator size and type, number of generators, line characteristics (i.e., voltage, impedance, and ampacity), and the existing protection equipment connected to the PG&E Power System. Identical generator projects connected at different locations in the PG&E Power System can have widely varying protection requirements and costs. These differences are caused by different line configurations, fault duties and existing relay schemes. See Appendix S for more information. PG&E's protection requirements are designed and intended to protect the PG&E Power System only. As a general rule, neither party should depend on the other for the protection of its own equipment. The Generation Entity shall install at the Point of Interconnection, at a minimum, a disconnecting device or switch with generation interrupting capability. Additional protective relays are typically needed to protect the Generation Entity’s facility adequately. It is the Generation Entity’s responsibility to protect its own system and equipment from faults or interruptions originating on both PG&E’s side and the Generation Entity’s side of the Interconnection. The Generation Entity’s System Protection Facilities shall be designed, operated, and maintained to isolate any fault or abnormality that would adversely affect the PG&E Power System or the systems of other entities connected to the PG&E Power System. The Generation Facility shall, at its expense, install, operate, and maintain system protection facilities in accordance with applicable CAISO, WECC and NERC requirements and in accordance with design and application requirements of this Handbook. The protective relays used in isolating the Generation Facility from the PG&E Power System at the Point of Interconnection must be PG&E-approved devices and must be set to coordinate with the protective relays at the PG&E line breaker terminals for the line on which the Generation Facility is connected. Additional requirements, as to the exact type and style of the protective devices, may be imposed on the Generation Entity based on the proposed station configuration or the type of interrupting device closest to the point of common coupling to PG&E’s facility. Note: There may be additional protective equipment requirements, at the Generation Entity’s cost, which PG&E will coordinate with the Generation Entity or its representatives. PG&E recommends that the entity acquire the services of a qualified electrical engineer to review the electrical design of the proposed generation facility and ensure that it will be adequately protected.

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The required types of protective devices are listed on Tables G2-1a and G2-1b. Typical protection and metering installations are shown on Figures G1-1 and G1-2 in Section G1. Generally, fault-interrupting equipment should be located as close to the interconnection point as possible - typically within one span of overhead line or 200 feet of unspliced underground cable. The Generation Entity should provide PG&E with electrical drawings for review prior to equipment procurement. The drawings provided should consist of Single Line Meter and Relay Diagrams, schematic drawings detailing connectivity (3-Line AC) and tripping schemes (DC) for all PG&E required relays. The Single Line Meter and Relay Diagrams listing the major protective equipment should be provided prior to ordering relays 9. The 3-Line AC and the DC schematics should be provided before fabricating relay panels 10. The following documents must be submitted for review before any agreements are executed: Single Line Diagram, Single Line Meter and Relay Diagrams. It is critical to the project schedule that the required leased circuits are ordered many months in advance of the operational date. In Appendix F the timeframes are provided for different types of circuits and services. These are approximate lead times since each facility will have to be evaluated by the telephone company to determine the availability of adequate cable pair facilities for the required service. If the requisite cable plant is not available, the project timeline may be extended 6 to 12 months. The required leased circuits must be in place before a company may generate electricity into the PG&E power grid. The Generation Entity must provide PG&E with test reports (Form G2-2) for the particular types of protective devices applied as outlined in Tables G2-1a and G2-1b before PG&E will allow the facility to parallel. Where tele-protection is utilized, the communication circuits must be tested and the scheme operation functionally verified prior to release for commercial operation 11. Refer to Pre-parallel Inspection for Generation Customers, Section G5, for information regarding pre-parallel inspections and Appendix F for communication-assisted line protection. Every four years thereafter, the Generation Entity must submit written test reports for qualified testing to PG&E, that demonstrate the relays are operable and within calibration. PG&E will not test the entity's equipment, but may witness the testing performed by a qualified testing firm retained by the entity. On-site power (typically 120 volts) is required for the test equipment. Circuit breakers must be tested at least every eight years after the preparallel inspection. It is also in the Generation Entity’s best interest to make sure all of its protective equipment is operating properly, since significant equipment damage and liability can result from failures of the entity’s protective equipment. Refer to the Operation Procedures, Section G4, of this handbook for the requirements on reporting relay problems. At the same four-year interval as the relay testing, the Generation Entity should obtain confirmation from the appropriate telephone company that the leases for

9

Refer to Appendix F for recommendations and requirements associated with pilot protection. Submittal of these drawings is required before a Generation Entity is allowed to parallel with the PG&E Power System. 11 Communication-assisted protection tests include end-to-end satellite testing of the protection and communication between the interconnected terminals as a system. See Appendix F for more information. 10

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the protection circuits are configured properly (e.g. Mutual Drainage Reactors installed at Central Office or Remote Terminal).

G2.2. Reliability and Redundancy The Generation Entity shall design the protection system with sufficient redundancy that the failure of any one component will still permit the Generation Entity’s facility to be isolated from the PG&E Power System under a fault condition8. Multi-function threephase protective relays must have redundant relay(s) for back-up. The required breakers must be trip tested by the Generation Entity at least once a year. It is PG&E’s practice to use two relays from different manufacturers in order to provide adequate level of redundancy and security and to avoid single mode of failure for both levels of protection. Any customer interface protective devices that have potential impact on PG&E system will have to comply with this practice regardless of transmission line ownership. Protection of customer-owned equipment by two relays from the same vendor is acceptable as long as these relays utilize different operating principles. An example of relays requiring redundancy would be the intertie breaker and the main customer transformer protection. PG&E strongly recommends against using fuses for protection of DC control and protection circuits, since they could fail open without indication resulting in disabling of protection and controls including breaker tripping. If fuses are used in trip circuits, trip coil monitoring and alarming must be used.

G2.3. Relay Grades Only utility grade relays can be used for interconnection protection this requirement shall include the protective and tripping relays used to trip the breaker separating the facility from the PG&E system These relays, used by electric utilities, have much higher reliability and accuracy than industrial grade relays (see Tables G2-4 and G2-5). In addition, they typically have draw-out cases and indicating targets or better recording to facilitate testing and troubleshooting. All utility grade relays must include manually resettable relay targets. All relays must have 5A nominal AC input current. All utility grade relay power supplies must be powered by station battery DC voltage, and the battery system should include a DC undervoltage detection device and alarm. See Section G2.20 and Appendix T (Battery Requirements for Interconnection to PG&E System) All proposed relay specifications must be submitted to PG&E for approval prior to ordering. Line protection relays must come from PG&E’s approved list (See Tables G24 and G2-5). Generation protection relays can come from PG&E’s approved list (Tables G2-4 and G2-5) or the Generation Entity can have testing performed to qualify relays in accordance with the Appendix R - “Generation Protective Relay Requirements”. Any required qualified tests shall be performed at the Generation Entity’s expense and prior to PG&E approval of the relay for interconnection use. PG&E approval does not indicate the quality or reliability of a product or service, and endorsements or warranties

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shall not be implied. If the entity wants to use a relay not on the PG&E approved list (Tables G2-4 and G2-5) the entity should allow additional time for testing and approval.

G2.4. Line Protection Line-protection relays must coordinate with the protective relays at the PG&E breakers for the line on which the generating facility is connected. The typical protective zone is a two-terminal line section with a breaker on each end. In the simplest case of a load on a radial line, current can flow in one direction only, so protective relays need to be coordinated in one direction and do not need directional elements. However, on the typical transmission system, where current may flow in either direction depending on system conditions, relays must be directional. Also, the complexity and the required number of protective devices increase dramatically with increases in the number of terminals in each protective zone. With two terminals in a protective zone, there are two paths of current flow. With three terminals there are six paths of current flow, and so on. In coordinating a multi-terminal scheme, PG&E may require installation of a transmission line protective relay at the Generation Entity’s sub-site. This is commonly the case whenever three-terminal permissive overreach transfer trip (POTT) schemes are employed to protect the line. Because this line relay participates in a scheme to protect the PG&E transmission system, PG&E must ensure the maintenance, testing and reliability of this particular type of relay. The relays must be connected to the breaker CTs in such a way that zones of protection overlap. The line protection schemes must be able to distinguish between generation, inrush and fault currents. Multiple terminal lines become even more complex to protect. Existing relay schemes may have to be reset, replaced, or augmented with additional relays at the Generation Entity’s expense, to coordinate with the Generation Entity’s new facility. The PG&E required relays must be located so that a fault on any phase of the PG&E interconnected line(s) shall be detected. If transfer trip protection is required by PG&E, the Generation Entity shall provide all required communication circuits at its expense. A communication circuit may be a leased line from the telephone company, a dedicated cable, microwave, or a fiber optic circuit and shall be designed with sufficient levels of monitoring of critical communication channels and associated equipment. PG&E will determine the appropriate communication medium to be used on a case-by-case basis. The leased phone line or dedicated communication network must have high-voltage protection equipment on the entrance cable so the transfer trip equipment will operate properly during fault conditions. (Refer to Appendix F for a detailed description of protection requirements and associated transfer trip equipment and communications circuits monitoring.) The PG&E transmission system and the distribution network system are designed for high reliability by having multiple sources and paths to supply customers. Due to the multiple sources and paths, more complex protection schemes are required to properly detect and isolate the faults. The addition of any new generation facility to the PG&E Power System must not degrade the existing protection and control schemes or cause

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existing PG&E customers to suffer lower levels of safety and/or reliability (see Electric Rule 2). Many portions of the PG&E Power System have provisions for an alternate feed. In some locations, the generation cannot be allowed on line while being fed from an alternate source due to protection problems. Whenever possible, the Generation Entity will be given the option of paying for any required upgrades so that they can stay on line while transferred to the alternate source or not paying for upgrades and accepting shutdowns when transferred to the alternate source. Table G2-1a lists the minimum protection that PG&E typically uses on its own installations. Higher voltage interconnections require additional protection due to the greater potential for adverse impact to system stability, and the greater number of customers who would be affected. Special cases such as distribution-level network interconnections, if acceptable, may have additional requirements. The acceptability and additional requirements of these interconnection proposals shall be determined by PG&E on a case-by-case basis.

Table G2-1a Line Protection Devices4 Line Protection Device

Phase Overcurrent (Radial systems) Ground Overcurrent (Radial systems) Phase Directional Overcurrent Ground Directional Overcurrent or Transformer Neutral Distance Relay Zone 1 (phase and ground elements where applicable) Distance Relay Zone 2 (phase and ground elements where applicable) Distance Relay Carrier Ground Directional Overcurrent Carrier Distance Relay Carrier Block Pilot Wire, Current differential, and Phase Comparison Permissive Overreaching Transfer Trip (POTT) or Hybrid Direct Transfer Trip

3

Device Number 50/51 50/51N 67 67N 50/51N 21Z1 / 21 Z1N 21Z2 / 21 Z2N 21Z2C 67NC 21Z3C 87L/78

34.5kV or less X X

44kV, 60kV or 70kV X X 1 X 1 X

X

2

230kV

X X

X

X

1

X

1

X

X

1

X

1

X

X 1 X 1 X 1 X

1

X X X X

X

1

X

X

2

X

21/67T TT

115kV

X

2

2

Notes: 1. May be required on transmission or distribution interconnections depending on local circuit configurations, as determined by PG&E. 2. Transfer trip may be required on transmission-level or distribution-level interconnections depending on PG&E circuit configuration and loading, as

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determined by PG&E. Typically, transfer trip shall be required if PG&E determines that a generation facility cannot detect and trip on PG&E end-of-line faults within an acceptable time frame, or if the generation facility may be capable of keeping a PG&E line energized with the PG&E source disconnected. It should be noted for most PV generating facilities line phase fault detection is not feasible therefore DTT will be required (Appendix F). 3. Refer to Table G2-1 for device number definitions and functions. 4. Line protection application is a function of the power system parameters and equivalent sources to which equipment are interconnected given the rating of the equipment being installed for interconnection purposes. 5. All relays must have 5A nominal AC input current.

G2.5. Generator protection and control Single-phase generators must be connected in multiple units so that an equal amount of generation capacity is applied to each phase of a three-phase circuit. All synchronous, induction and single-phase generators shall comply with the latest ANSI Standards C50.10 and C50.13, dealing with waveform and telephone interference. Synchronous generators of any size will require: a) synchronizing relays, synch check, or auto synchronizer (Device No. 25) to supervise generator breaker closing, and b) reclose blocking at the PG&E side of the line to which the generator is connected (applies to substation breaker/recloser and line reclosers). For Photo Voltaic (PV) systems they shall comply with IEEE Std 519 for dealing with power quality. Generally PV systems are standalone only and do not require autosynchronzing and a synch check functions, however each installation shall be evaluated by PG&E on a case by case basis. Standard device numbers for commonly used protective elements are defined in Table G2-1. The generator protection equipment listed in Table G2-1b, in addition to those listed in Table G2-1a, is required to permit safe and reliable parallel operation of the Generation Entity’s equipment with the PG&E Power System. Additional generator protection requirements shall be determined by PG&E on a case-by-case basis.

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Table G2-1b Generator Protection Devices 1

Generator Protection Device

Device Number

40 kW or Less

Phase Overcurrent Overvoltage Undervoltage Overfrequency Underfrequency Ground Fault Sensing Scheme (Utility Grade) Overcurrent With Voltage Restraint/Voltage Control or Impedance Relay Reverse Power Relay (No Sale)

50/51 59 27 81O 81U 51N 51V 21 32

X X 3 X X X

2

X

6

41 kW to 400 kW 2 X X X X X 4 X 5 X X

6

401 kW and Larger X X X X X X X

6

Notes: 1. Refer to Table G2-1 for device number definitions and functions. 2. Overcurrent protection must be able to detect a line-end fault condition. A phase instantaneous overcurrent relay that can see a line fault under sub-transient conditions is required. This is not required if a 51V relay is used. 3. For generators 40 kW or less, the undervoltage requirement can be met by the contactor undervoltage release. 4. For induction generators and certified non-islanding inverters aggregating less than 100 kW, ground fault detection is not required. Ground fault detection is required for non-certified induction generators of 100kW or larger capacity. For synchronous generators aggregating over 40 kW, and induction generators aggregating over 100kv, ground fault detection is required. 5. A group of generators, each less than 400 kW but whose aggregate capacity is 400 kW or greater, must have an impedance relay or an overcurrent relay with voltage restraint located on each generator greater than 100 kW. Due to the limited fault contribution of photo-voltaic generating systems the 51V and 21 requirements are waived, DTT will be utilized to trip the PV offline. 6. For “No Sale” generator installations, under the proper system conditions, a set of three single-phase, very sensitive reverse power relays, along with the dedicated transformer may be used in lieu of ground fault protection. The relays shall be set to pick-up on transformer magnetizing current, and trip the main breaker within 0.5 second. 7. All relays must have 5A nominal AC input current. 8. Due to the limited fault contribution of photo-voltaic generating systems the 51V and 21 requirements are waived, DTT will be utilized to trip the PV offline. The following paragraphs describe the required protective and control devices for generators:

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G2.5.1. Phase Overcurrent See Table G2-1 (Device 50/51) for definition and function.

G2.5.2. Over/Undervoltage Relay This protection is used to trip the circuit breaker when the voltage is above or below PG&E's normal operating level (see Table G2-6). It is used for generator protection and backup protection in the event that the generator is carrying load that has become isolated from the PG&E Power System.

G2.5.3. Over/Underfrequency Relay This protection is used to trip the circuit breaker when the frequency is above or below PG&E's normal operating level (see Table G2-6). It is used for generator/turbine protection and backup protection. Generator underfrequency relay settings are coordinated with other utilities in the Western Electricity Coordinating Council (WECC) to maintain generation on line during system disturbances. Settings should not be set for a higher frequency or shorter time delay than specified in Table G2-6 without prior written approval by PG&E and the CAISO.

G2.5.4. Ground and Phase Fault Sensing Scheme

G2.5.4.1. General: The ground fault sensing scheme detects PG&E Power System ground faults and trips the generator breaker or the generating facility’s main circuit breaker, thus preventing the Generation Entity's generator from continuously contributing to a ground fault. This scheme must be able to detect faults between the PG&E system side of the dedicated transformer and the end of PG&E's line. The following transformer connections, along with appropriate relaying equipment, are commonly used to detect system ground faults: •

System side - grounded wye; generator side - delta



System side - grounded wye; generator side - wye; tertiary - delta

G2.5.4.2. Ground Grid Requirements Transformers connected to the transmission system at 60 kV and higher must have a grounded wye connection on the system side, and a ground current sensing scheme must be used to detect ground faults on the PG&E Power System. For any substation/generation facility built by other entities but subsequently owned and/or operated by PG&E, the ground grid must meet the minimum design and safety requirements used in PG&E substations. The ground grid design must by analyzed in accordance with

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the Grounding Design Criteria (Appendix E), and documented in accordance with PG&E Analysis Specification (Appendix E). Additionally, when customer facilities (operated by customer personnel) need to be connected to the ground grid of an existing or new PG&E substation (i.e. when they are located inside or immediately adjacent to PG&E substations or switching stations OR when system protection requires solid ground interconnection for relay operation), the ground grid must meet the minimum design and safety requirements used in PG&E substations. (Appendix E) When customer facilities are not in any way connected to the PG&E ground grid or neutral system, the customer will be solely responsible for establishing design and safety limits for their grounding system.

G2.5.5. Overcurrent Relay with Voltage Restraint/Voltage Control or Impedance Relay These relays are used to detect multi-phase faults and initiate a generator circuit breaker trip. The relays must be located on the individual generator feeder. A group of generators aggregating over 400 kW must have an impedance relay or an overcurrent relay with voltage restraint located on each generator greater than 100 kW. Generators equal to or greater than 400 kW must have an impedance relay or an overcurrent relay with voltage restraint. As determined by PG&E protection studies, an overcurrent relay with voltage control may also be acceptable if it can be set to adequately detect end-of-line faults. If the generator step-up transformer is connected wye-delta or delta-wye, a delta-wye or wyedelta auxiliary potential transformer is required on the potential circuits to the voltage restraint or voltage controlled overcurrent relay for phase shift correction based on the relay design and operating principal. The Generation Entity should contact the PG&E representative for assistance in the proper connection of the auxiliary transformers. Due to the limited fault contribution of photo-voltaic generating systems the above 51V requirement is waived.

G2.5.6. Reverse Power Relay See Table G2-1b (Device #32) for definition and function.

G2.6. Dedicated Transformer A dedicated transformer is required to step-up the generator voltage to the interconnection level and isolate the Generation Entity from other customers. The impedance of a dedicated transformer limits fault currents on the generator bus from the PG&E Power System and also limits fault currents on the PG&E Power System from the generator. Hence, it reduces the potential damage to both parties due to faults. It also must have a delta winding to reduce the generator harmonics entering the

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PG&E Power System. The delta winding will also reduce the PG&E Power System harmonics entering the generation facility. A high-side fault-interrupting device is required for transformer protection. A threephase circuit breaker is recommended, but fuses are acceptable for generation facilities of less than 1,000 kW, providing that coordination can be obtained with the existing PG&E protection equipment. If fuses are used, it is recommended that the Generation Entity install single-phase protection for its equipment. Lightning arrestors, if the Generation Entity chooses to install them, must be installed between the transformer and the fault-interrupting devices and be encompassed by the generator’s relay protection zone.

G2.7. Manual Disconnect Switch G2.7.1. General A manual disconnect switch on the tap line (Tap Line Switch) is required for a generation facility. Two additional Line Selector Switches, one on each side of the tap, may also be required to ensure better service and operating flexibility. Refer to PG&E Electric Transmission Guideline G01014 for more details on Line Selector Switches. Note: the installation of Line Selector Switches may impact the protection requirements for the interconnection, specifically the need for direct transfer trip. A PG&E-operated disconnect device must be provided as a means of electrically isolating the PG&E Power System from the generator. This device shall be used to establish visually open working clearance for maintenance and repair work in accordance with PG&E safety rules and practices. A disconnect device must be located at all points of interconnection with PG&E. The disconnect switch should be a gang-operated, three-pole lockable switch. If the switch is to be located on the PG&E side of the interconnection point, PG&E will install the switch at the Generation Entity’s expense. If the device is to be located on the entity’s side, it must be furnished and installed by the Generation Entity. All switch devices must be approved by PG&E. PG&E personnel shall inspect and approve the installation before parallel operation is permitted. If the disconnect device is in the Generation Entity’s substation, it should be located on the substation dead-end structure and must have a PG&Eapproved operating platform. The disconnect device must not be used to make or break parallels between the PG&E Power System and the generator(s). The device enclosure and operating handle (when present) shall be kept locked at all times with PG&E padlocks. The disconnect device shall be physically located for ease of access and visibility to PG&E personnel. When installed on the Generation Entity’s side of the interconnection, the device shall normally be installed close to the metering. The PG&E-operated disconnect shall be identified with a PG&E designated switch number plate.

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Metering is normally on the high-side of the Generation Entity’s step-up transformers. Between the metering units and the circuit breaker, a second disconnect device is required; it shall not have a PG&E lock and may be operated by the Generation Entity.

G2.7.2. Specifications •

Disconnect switches must be rated for the voltage and current requirements of the particular installation



Disconnect switches must be gang-operated



Disconnect switches must be weatherproof or designed to withstand exposure to weather



Disconnect switches must be lockable in both the open/closed positions with a standard PG&E lock.

G2.8. Fault-Interrupting Devices The fault-interrupting device selected by the Generation Entity must be reviewed and approved by PG&E for each particular application. There are two basic types of fault-interrupting devices: •

Circuit Breakers



Circuit Switchers

PG&E will determine the type of fault-interrupting device required for a generation facility based on the size and type of generation, the available fault duty, the local circuit configuration, and the existing PG&E protection equipment.

G2.8.1. Circuit Breakers A three-phase circuit breaker at the point of interconnection automatically separates the generation facility from the PG&E Power System upon detection of a circuit fault. Additional breakers and protective relays may be installed in the generation facility for ease in operating and protecting the facility, but they are not required for the purpose of interconnection. The interconnection breaker must have sufficient capacity to interrupt maximum available fault current at its location and be equipped with accessories to: •

Trip the breaker with an external trip signal supplied through a battery (shunt trip)



Telemeter the breaker status when it is required



Lockout if operated by protective relays required for interconnection

Generally, a three-phase circuit breaker is the required fault-interruption device at the point of interconnection, due to its simultaneous three-phase operation and ability to coordinate with PG&E line-side devices.

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G2.8.2. Circuit Switchers A circuit switcher is a three-phase fault-interrupter with limited fault interrupting capability. These devices have typically been used at voltages of 115 kV and below and may substitute for circuit breakers when the fault duty is within the interrupting rating of the circuit switcher. With PG&E approval, some circuit switchers with blades can double as the visual open disconnect switch between the metering transformers and the main transformer. Since circuit switchers do not have integral current transformers, they must be installed within 30 feet of the associated current transformers to minimize the length of the unprotected line/bus section.

G2.9. Synchronous generators The generating unit must meet all applicable American National Standards Institute (ANSI) and Institute of Electrical and Electronic Engineers (IEEE) standards. The prime mover and the generator should also be able to operate within the full range of voltage and frequency excursions that may exist on the PG&E Power System without damage to themselves. The generating unit must be able to operate through the specified frequency ranges for the time durations listed in Table G2-6, to enhance system stability during a system disturbance.

G2.9.1. Synchronizing Relays The application of synchronizing devices attempts to assure that a synchronous generator will parallel with the utility electric system without causing a disturbance to other customers and facilities (present and in the future) connected to the same system. It also attempts to assure that the generator itself will not be damaged due to an improper parallel action. Refer to Appendix Q for additional information and requirements. Synchronous generators and other generators with stand-alone capability must use one of the following methods to synchronize with the PG&E Power System:

G2.9.1.1. Automatic Synchronizers Approved by PG&E See Table G2-4 for PG&E-approved devices. Automatic synchronization with automatic synchronizer (Device 15/25) to synchronize with the PG&E Power System. The automatic synchronizer must be approved by PG&E and have all of the following characteristics: •

Slip frequency matching window of 0.1 Hz or less



Voltage matching window of ± 10 percent or less



Phase angle acceptance window of ± 10 degrees or less



Breaker closure time compensation. For an automatic synchronizer that does not have this feature, a tighter phase angle window ( ± 5

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degrees) with a one second time acceptance window shall be used to achieve synchronization within ± 10 degrees phase angle Note: The automatic synchronizer has the ability to adjust generator voltage and frequency automatically to match system voltage and frequency, in addition to having the above characteristics.

G2.9.1.2. Automatic Synchronizers (not on PG&E’s approved list) Supervised by a PG&E-Approved Synchronizing Relay Automatic synchronization with a device not approved by PG&E supervised by an approved synchronizing relay (Device 25). The synchronizing relay must have all of the following characteristics: •

Slip frequency matching window of 0.1 Hz or less



Voltage matching window of ± 10 percent or less



Phase angle acceptance window of ± 10 degrees or less



Breaker closure time compensation

Note: The synchronizing relay closes a supervisory contact after the above conditions are met, allowing the non-approved automatic synchronizer to close the breaker.

G2.9.1.3. Manual Synchronization Supervised by a Synchronizing Relay Manual synchronization with supervision from a synchronizing relay (Device 25) to synchronize with the PG&E Power System. The synchronizing relay must have all of the following characteristics: •

Slip frequency matching window of 0.1 Hz or less



Voltage matching window of ± 10 percent or less



Phase angle acceptance window of ± 10 degrees or less



Breaker closure time compensation

Note: The synchronizing relay closes a supervisory contact, after the above conditions are met, allowing the breaker to close.

G2.9.1.4. Manual Synchronization With Synch-Check Relay Manual synchronization with synchroscope and synch-check (Device 25) relay supervision. (Only allowed for generators with less than 1000-kW aggregate nameplate rating). The synch-check relay must have the following characteristics: •

Voltage matching window of ± 10 percent or less.

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Phase angle acceptance window of ± 10 degrees or less.

Generators with greater than 1,000 kW aggregate nameplate rating must have a synchronizing relay or automatic synchronizer.

G2.9.2. Frequency/Speed Control Unless otherwise specified by PG&E, a governor shall be required on the prime mover to enhance system stability. Governor characteristics shall be set to provide a 5 percent droop characteristic. Governors on the prime mover must be operated unrestrained to help regulate PG&E’s system frequency.

G2.9.3. Excitation System Requirements An excitation system is required to regulate generator output voltage. Excitation systems shall have a minimum ceiling voltage of 150 percent of rated full load field voltage and be classified as a high initial response excitation system as defined in IEEE 421.1. Static Systems shall meet these criteria with 70 percent of generator terminal voltage. The offline generator terminal voltage response shall have an overshoot limited to 20 percent and a bandwidth of at least 0.1 to 4 hertz. However, in no case shall the bandwidth upper limit be less than local mode frequency. All systems shall be suitable to utilize a Power System Stabilizer as described in Section G2.9.4. Ceiling current shall have a transient time capability equal to or greater than the short time overload capability of the generator. See ANSI C50.12, 13, or 14. A means shall be provided to quickly remove excitation from the generator field to minimize contributions to faults. The preferred method is to reverse voltage the generator field to drive the current to zero. Excitation systems shall respond to system disturbances equally in both the buck and boost directions. All bridges that govern excitation response shall be full wave type. Bridges feeding a pilot exciter shall have negative forcing capability. Under certain conditions PG&E may grant an exemption for Generating Facilities that have excitation systems not meeting these requirements. Requests for exemption should be sent to PG&E’s Electric T&D Engineering at the following address: Director, Electric T&D Engineering Pacific Gas and Electric Co. Mail Code H12A P.O. Box 770000 San Francisco, CA 94177

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G2.9.4. Voltage Regulator Voltage control is required for all synchronous generators interconnected at transmission level voltages. The regulator must be acting continuously and be able to maintain the generator voltage under steady-state conditions without hunting and within ± 0.5 percent of any voltage level between 95 percent and 105 percent of the rated generator voltage per CAISO requirements. The point of voltage sensing should be at the same point as the PG&E revenue metering. Voltage regulators shall have a minimum of the following signal modifiers: •

Reactive current compensator capable of line drop or droop characteristic



Minimum and maximum excitation limiter



Volts per Hertz limiter



Two levels of over-excitation protection. The first level should provide a forcing alarm and trip the voltage regulator after a time delay. The second level shall have an inverse time characteristic such that the time-current relationship may be coordinated with the generator short time thermal requirements (ANSI C50.13 or C50.14).



A two input Power System Stabilizer (PSS) utilizing Integral of Accelerating Power to produce a stabilizing signal to modify regulator output. The PSS shall be an integral part of the voltage regulator and be incorporated into the excitation systems for all generating units greater than 30 MVA and connected to the transmission system at 60 kV and greater. PG&E can help determine, at the Generation Entity’s expense, the suitability of an excitation system for PSS. The PSS shall provide a positive contribution to damping for a frequency range from 0.1 hertz through local mode frequency.

Voltage schedules will be determined by the Designated Electric Control Center, in coordination with the Transmission Operations Center and the CAISO. At various times, the generating facility may also be requested by the Designated Electric Control Center, in coordination with the ISO, to produce more or less reactive power from that indicated on the regular schedule in order to meet the system needs.

G2.9.5. Power Factor Controller The controller must be able to maintain a power factor setting within ± 1 percent of the setting at full load at any set point within the capability of the generator. However, in no case shall control limits be greater than (closer to 100%) between 90 percent lagging and 95 percent leading. Power factor control is typically required for distribution level generator interconnections where the generator is put on a power factor schedule, rather than a voltage schedule. Power Factor Control shall not be used for units connected to the transmission system.

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G2.9.6. Event Recorder All unattended generation facilities with capacity greater than 400 kW and with automatic or remotely initiated paralleling capability must have an event recorder that will enable PG&E to make an after-the-fact determination of the status of the Generation Facility at the time of the system disturbance, should such a determination be required. The events should be recorded to a one (1) millisecond resolution. In addition, the event recorder of generation facilities with a nameplate rating equal to or greater than 1,000 kW must also provide a record of deliveries to PG&E of real power in kW, reactive power in kVar and output voltage in kV.

G2.10. Special Protection systems As stated in the WECC-NERC Planning Standards, the function of a Special Protection System (SPS) is to “detect abnormal system conditions and take pre-planned, corrective action (other than the isolation of faulted elements) to provide acceptable system performance.” In the context of new generation projects, the primary action of a SPS would be to detect a transmission outage or an overloaded transmission facility and then trip or run back (reduce) generation output to avoid potential overloaded facilities or other criteria violations. Any SPS proposal must be approved by both PG&E and CAISO and must comply with “ISO Grid Planning Guides for New Generator Special Protection systems” section of the California ISO Grid Planning Standards.

G2.11. REMEDIAL ACTION SCHEME (RAS) PARTICIPATION REQUIREMENT FOR GENERATION FACILITIES A RAS is a special protection system that automatically initiates one or more preplanned corrective measures to restore acceptable power system performance following a disturbance. Application of RAS mitigates the impact of system disturbances and improves system reliability. The output of electric generators may flow over the entire interconnected transmission system. A generation facility is therefore required to participate in remedial action schemes to protect local transmission lines and the entire system as PG&E determines necessary. A typical disturbance, as it is considered in the planning and design of the electric transmission system, is the sudden loss of one or more critical transmission lines or transformers. A widely applied corrective measure is to instantaneously drop a sufficient amount of generation on the sending end of the lost transmission facility. This is known as generation dropping, and a participating generation facility may be disconnected from the transmission by the automatic RAS controller, in much the same way as by a transfer-trip scheme. A generation facility should therefore have full loadrejection capability as needed both for local line protection and RAS. The RAS design

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must be such that any single-point failure will not prevent the effective operation of the scheme. 12 Whether RAS shall be required will depend on the overall location and size of the generator and load on the transmission system, the nature, consequences and expected frequency of disturbances and the nature of potential alternative transmission reinforcements

G2.12. Induction Generators Induction generators and other generators with no inherent Var (reactive power) control capability shall be required to provide an amount of reactive power equivalent to that required for a synchronous generator. They may also be required to follow a PG&Especified voltage or Var schedule on an hourly, daily or seasonal basis, depending on the location of the installation. Specific instructions shall be provided by the Designated PG&E Electric Control Center (see Section G3). Induction machines can be self-excited with the nearby distribution capacitors, or as the result of the capacitive voltage on the distribution network. Interconnecting facility should provide for a reclose block mechanism to avoid unintended operation of the unit following an outage on the distribution feeder to which it is interconnected.

G2.13. DC GENERATORS G2.13.1. Inverters Capable of Stand-Alone Operation Inverters capable of stand-alone operation are capable of islanding operation and shall have similar functional requirements as synchronous generators. For units less than 100 kW, usually it is acceptable to have the frequency and voltage functions built into the electronics of the inverter if the set points of these built-in protective functions are tamper-proof and can be easily and reliably tested. These relay functions must receive PG&E approval before they can be used to interconnect with the PG&E Power System. Protection and Synchronizing requirements For units capable of stand alone operation the generation and line protection requirements of Sections G2.1 through G2.5 shall apply. Additionally the functional synchronizing requirements specified under Section G2.9.1 shall apply to stand alone capable units. Voltage Regulating Requirements for units connected to Transmission Inverters do not have excitation systems similar to synchronous generators,, however they have the capability to regulate and follow voltage, therefore the unit shall meet the requirements to regulate output voltage and meet the 12

System studies will determine the nature and intent of the RAS. Any RAS proposals to mitigate possible cascading outages outside the PG&E interconnection points or system requires review and approval by the appropriate WECC study groups and technical committees charged with detailed review.

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requirements of Section G2.9.3 and must meet the functional requirements of Section G2.9.4 with the exception of the two levels of over-excitation protection. They shall also meet the requirements of Section G2.9.6. Regulation Requirements for units connected to Distribution Inverters connected at the distribution level shall meet the requirements of Section G2.9.5 for power factor control. The total harmonic distortion in the output current of the inverters must meet ANSI/IEEE 519 requirements. Inverter-type generators connected to the PG&E Power System must be preapproved by PG&E. For units over 10 kW, a dedicated transformer will be required to minimize the harmonics entering into the PG&E Power System.

G2.13.2. Inverters Incapable of Stand-Alone Operation Non-islanding inverters, rated 10 kW or less, that have met all the type tests and requirements for a utility interactive inverters found in UL Standard 1741, have passed the additional tests outlined in the inverter certification section of Electric Rule 21 and meet IEEE 519-1992 harmonic requirements, are considered approved equipment for connection to PG&E. Inverters that do not meet the above requirements must meet the functional requirements of synchronous generators as outlined in this section and are highlighted below. Protection Requirements For units greater than 100kW the generation and line protection requirements of Sections G2.1 through G2.5 shall apply. Synchronizing requirements For units that are incapable of stand alone operation synchronization is not required however there should be an undervoltage relay on the generation side of the PCC breaker to supervise breaker closing by preventing a close if voltage is on the generation bus. Voltage Regulating Requirements for units connected to Transmission Inverters do not have excitation systems similar to synchronous generators,, however they have the capability to regulate and follow voltage, therefore the unit shall meet the requirements to regulate output voltage and meet the requirements of Section G2.9.3 and must meet the functional requirements of Section G2.9.4 with the exception of the two levels of over-excitation protection. They shall also meet the requirements of Section G2.9.6. Regulation Requirements for units connected to Distribution Inverters connected at the distribution level shall meet the requirements of Section G2.9.5 for power factor control.

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G2.14. Emergency Generator Requirements There are two methods of transferring electric power supply between the PG&E source and the emergency generator system: open transition (break before make) and closed transition (make before break).

G2.14.1. “Break Before Make” This method can be accomplished via a double throw transfer switch or an interlock scheme that prevents the two systems from operating in parallel. The Generation Entity's main breaker shall not be allowed to close until the generator breaker opens. This open transition method does not require any additional protection equipment; however, it does cause the Generation Entity’s load to experience an outage while transferring back to PG&E. The length of this transfer depends on the transfer equipment.

G2.14.2. “Make Before Break” This method is used when the customer wants to minimize any loss of power or disturbance to the electric load. With this scheme, the customer's generator and the PG&E Power System are in parallel for a very short time interval during which the customer's load is being transferred between the PG&E source and the emergency generator. Both the transfer from PG&E to the emergency source and the transfer back can be accomplished without an outage.

G2.14.3. Interconnection Requirements Listed below are the requirements for the interconnection of emergency generators using the transfer schemes. First the general requirements for all transfer schemes are presented. Then the specific requirements for the two methods are listed.

G.2.14.3.1. Interconnection Protection Study13 In general, a protection study is not required for these types of generation arrangements if the applicant meets the requirements outlined in this section and submits the required reports and drawings for review and approval.

G.2.14.3.2. Transfer Switch The transfer switch must be rated for the maximum possible load current.

G.2.14.3.3. Notification and Documentation 1. The customer must notify PG&E in writing regarding all emergency generator installations, regardless of method of interconnection or transfer. 13

Note: This is a different study, not to be confused with a System Impact Study, see glossary for definitions

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2. Complete documentation is required. Information should include but not limited to: a description of generator and control system operation, single line diagrams, identification of all interlocks, sequence of events description for transfer operation and specifications for any PG&E required protective devices. 3. All documentation must be approved by PG&E prior to installation. 4. Relay test reports must be reviewed and approved by PG&E 15 days prior to scheduling pre-parallel inspections.

G2.14.3.4. Operation/Clearance 1. For all line work and clearances, the emergency generator should be treated as a power source. 2. Customers utilizing “make before break” transfer schemes are required to notify the responsible Operation Center of their intent to transfer to their emergency generator and then again back to PG&E source, before any transfers are attempted. This notification is not required for break before make operation.

G2.14.3.5. “Break Before Make” Specific Requirements G2.14.3.5.1. Transfer Switch The transfer switch must be of a design, or have an interlock, that prevents the transfer switch from closing and connecting the customer’s system with PG&E unless the emergency generator is already removed from the system.

G2.14.3.6. “Make Before Break” Requirements G2.14.3.6.1. Transfer Switch 1. The transfer switch must be rated for the maximum available fault duty in the event that the transfer switch closes into a fault condition. 2. There must be an interlock that will trip the main beaker or generator in the event of a failure of the transfer switch so that the unit will not remain paralleled to the PG&E Power System. This can be accomplished via a failure to open timer (see Table G2-5). 3. The controls for the transfer switch must prevent a parallel condition of the customer generator and the PG&E Power System from existing for an extended time period. Any system that allows a parallel to exist for greater than 0.5 seconds (30 cycles) on the transmission system and 1 second (60 cycles) on

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the distribution system should be subjected additional requirements outlined in other section of this document.

G2.14.3.6.2. Manual Disconnect 1. The customer must provide a manual disconnect, located at the point of interconnection, which is used to establish a visually open safety clearance for the PG&E personnel working on the PG&E Power System. 2. The disconnect must be lockable in either the open or closed transition and operated only by PG&E. 3. The disconnect must be easily accessible, preferably located adjacent to the electric meter. 4. The disconnect must have full load break capability.

G2.14.3.6.3. Synchronizing Function The transfer scheme must have adequate control and protection to ensure the PG&E and customer electric systems are in synchronism prior to making the parallel. This is essential to ensure a safe and smooth transition. Synchronization is accomplished through the use of an auto-synchronizer or a synchronizing relay. The major requirements that these devices should possess are briefly listed below: 1. Slip frequency matching of 0.1 Hz or less. 2. Voltage matching of ± 10 percent or less. 3. Phase angle acceptance of ± 10 degrees or less. 4. Breaker closure time compensation.

G2.14.3.6.4. Protection Because the emergency generators are paralleled with the PG&E Power System, protective devices must be installed which will prevent the customer’s generator from remaining connected in the event of a fault occurring on the PG&E Power System during the transition. It is necessary to prevent damage to the customer’s equipment, the PG&E Power System, and other PG&E customers. 1. In most installations, the protection requirement may be satisfied through the installation of the reverse power relay (see Table G2-5). This relay should be installed on the customer’s side of the service transformer that is connected to the PG&E Power System. The relay should trip the customer’s main breaker and must be able to detect transformer core magnetizing power. In this manner, reverse power flow is detected before it actually enters the PG&E Power System and 95

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other customers’ equipment. This can be accomplished by setting the current level pick up equivalent to 60 percent of the transformer bank magnetizing current. Because this current value will be small, the current transformers associated with the relay must be capable of providing these small currents. 2. When transferring the customer’s load back to the PG&E Power System. It is possible to have incidental power flow back to PG&E’s system. By properly setting the synchronizing and/or generator control, this reverse flow can be avoided. However, a short time delay may be required on the reverse power relay to prevent it from tripping the generator unnecessarily each time a transfer is attempted. At no time should this time delay exceed one second.

G2.14.3.6.5. Dedicated Transformer Due to the fact that the emergency generator is connected in parallel with the PG&E Power System, all transfer schemes of this type must have a dedicated transformer. This will lessen the possibility that any transfer activities will affect other PG&E customers. In addition, a dedicated transformer is also necessary to allow the installation of the reverse power relay scheme.

G2.15. Parallel-only (NO sale) Generator requirement Parallel-Only generators shall have similar requirements as that of any other standard synchronous generator interconnection except that PG&E may at its discretion allow the installation of three very sensitive, single-phase, reverse power relays (such as the Basler BE1-32R) along with the dedicated transformer as an alternative to the normally required ground relays. The reverse power relays shall be set to pick up on transformer magnetizing current with a time delay not to exceed 0.5 second. This option may not be feasible on generating systems with a slow load rejection response since they may be tripped off-line frequently for in-plant disturbances. Owners of Parallel-Only generators, particularly Rule 21 customers must execute a parallel-only operating agreement with PG&E prior to operation by the generation owner.

G2.16. GENERATION ENTITY-Owned Primary or Transmission Voltage Tap Lines (60 kV and above) If the Generation Entity constructs, owns and maintains a transmission-level voltage tap line extension, the entity shall also install, own and maintain the following equipment at the point of interconnection with PG&E: •

The fault-interrupting protection device; i.e., breaker, recloser, as specified by PG&E.



The manual isolating disconnects (gang-operated).

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High-side metering installation as outlined in Section G1.

G2.17. PG&E PROTECTION AND CONTROL SYSTEM CHANGES WHICH MAY BE REQUIRED TO ACCOMMODATE GENERATOR INTERCONNECTION At the Generation Entity's expense, PG&E will perform a detailed interconnection study to identify the cost of any required modifications to PG&E's protection and control systems that are required to interconnect a new generation source. Retail generators will execute a Generation Special Facilities Agreement (Appendix L) as indicated in Electric Rule 21 to recover the costs to PG&E associated with any protection and control system modifications which are directly assigned to the Generation Entity. Wholesale generators will execute a FERC-jurisdictional Generator Interconnection Agreement. These protection and control system modifications are in addition to any transmission system upgrades identified in the system impact or facilities studies for interconnection of the new generation facility. Following is a partial list of protection system modifications that may be required: •

PG&E’s automatic restoration equipment shall be prevented from operating until the generator is below 25 percent of nominal voltage as measured at the restoration equipment. Generator damage and system disturbances may result from the restoration of power by automatically re-energizing PG&E's facilities. This modification shall be required when the generator(s) has the capability of energizing a line when the PG&E Power System is disconnected. PG&E will not allow the Generation Entity's generator(s) to automatically re-energize PG&E facilities.



For generation facilities greater than 1,000 kW aggregate nameplate rating, all existing single phase fault interrupting devices (fuses) located in series between the generator and PG&E's substation, shall be replaced with three phase interrupting device to prevent possible single-phasing of other customers.



The PG&E substation transformer high side fuses must be replaced with a threephase interrupting device when the generator is on a distribution circuit fed from a fused PG&E substation transformer bank, and the bank's minimum load is equal to or less than 200 percent of the generator's nameplate rating.



Installation of transfer trip from the high-side circuit breaker/circuit switcher, as well as the distribution breaker and any line reclosers, to the generator if found necessary by PG&E. An associated EMS/SCADA telemetering circuit is required between the Generation Entity’s site and the Designated PG&E Electric Control Center.

G2.18. DIRECT TELEPHONE SERVICE The Generation Entity must obtain direct service from the local telephone company for a business telephone so that operating instructions from PG&E can be given to the designated operator of the Generation Entity's equipment. In addition, another

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telephone must be available near the protection equipment and telemetering equipment. This telephone would be used for maintenance of the various data a protection system that may be in service. Other types of leased circuits would include protection and EMS/SCADA data circuits. Communications circuits for transfer trip and EMS/CADA must be in service at least three weeks prior to connection to the PG&E power grid. It is critical to the project schedule that the required leased circuits are ordered many months in advance of the operational date. In Appendix F, approximate timeframes are provided for different types of circuits and services. These are approximate lead times for planning purposes. The telephone company will need to determine whether adequate cable pair facilities are available at each facility for the required service. If cable plant is not available, the generator should plan on 6-12 months before having the service. A Telephone line may also be required for remote metering at the Gas Valve location as appropriate. PG&E telecommunications personnel should evaluate this installation to make sure that the proper precautions are taken to ensure that the dielectric strength of the cable and protection equipment at the termination points of the cable are adequate to meet safety criteria.

G2.19. STANDBY STATION SERVICE Contact PG&E’s local representative if the Generation Entity desires standby service for station use.

G2.20. STATION BATTERY A stationary battery, either a flooded lead acid type or NiCd type, is required to power utility grade relays and for tripping the breaker. For detailed requirements about type, calculations and design, and test reports, etc., please refer to Appendix T: Battery Requirements for Interconnection to PG&E System.

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Table G2-1 Device Number 15

STANDARD DEVICE NUMBERS Definition and Function Device Definition and Function Number Speed of frequency 46 Reverse-phase or phasematching device is a device balance, current relay is a that functions to match and device which functions when the hold the speed or the polyphase currents are of frequency of a machine or of reverse-phase sequence, or a system equal to, or when the polyphase currents are approximately equal to, that unbalanced or contain negative of another machine, source phase sequence components or system. above a given amount.

21

Distance Relay is a device which functions when the circuit admittance, impedance, or reactance increases or decreases beyond predetermined limits.

47

Phase-sequence voltage relay is a device that functions upon a predetermined value of polyphase voltage in the desired phase sequence.

25

Synchronizing, and synchronism-check, device operates when two a-c circuits are within the desired limits of frequency, phase angle and voltage, to permit or to cause the paralleling of these two circuits.

50

Instantaneous overcurrent, or rate-of rise relay is a device which functions instantaneously on an excessive value of current, or on an excessive rate of current rise, thus indicating a fault in the apparatus or circuit being protected.

27

Undervoltage relay is a device that functions on a given value of undervoltage.

51

32

Reverse power relay is one which functions upon a reverse power flow at a given set point.

52

A-C time overcurrent relay is a device with either a definite or inverse time characteristic that functions when the current in an a-c circuit exceeds a predetermined value. A-C circuit breaker is a device that is used to close and interrupt and a-c power circuit under normal conditions or to interrupt this circuit under fault or emergency conditions.

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PG&E Transmission Interconnection Handbook

Table G2-1 STANDARD DEVICE NUMBERS (Continued) Device Number 59

Definition and Function

60

Voltage balance relay is a device which operates on a given difference in voltage between two circuits..

61

Current balance relay is a device that operates on a given difference in current input or output of two circuits.

62

Time-delay stopping, or opening, relay is a timedelay device which serves in conjunction with the device which initiates the shutdown, stopping , or opening operation in an automatic sequence. A-C directional overcurrent relay is a device that functions on a desired value of a-c overcurrent flowing in a predetermined direction.

67

Overvoltage relay is a device that functions on a given value of overvoltage.

Device Definition and Function Number 79 A-C reclosing relay is a device that controls the automatic reclosing and locking out of circuit interrupter. 81 Frequency relay is a device that functions on a predetermined value of frequency—either under or over the normal system frequency—or rate of change of frequency. 87 Differential protective relay is a protective device which functions on a percentage or phase angle or other quantitative difference of two currents or of some other electrical quantities. 90 Regulating device functions to regulate a quantity, or quantities, such as voltage, current, power, speed, temperature, frequency, and load, at a certain value or between certain limits for machines, tie lines, or other apparatus. 94 Tripping or trip-free relay is a relay that functions to trip a circuit breaker, contactor, or equipment, or to permit immediate tripping by other devices; or to prevent immediate reclosure of a circuit interrupter if it should open automatically even though its closing circuit is maintained closed.

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Form G2-2 RELAY TEST REPORT FACILITY NAME

TESTING BY FIRM ADDRESS TESTED FOR  INSTALLATION

LOCATION FACILITY ACCOUNT NUMBER

*

DATE INSTALLED DATE LAST TESTED

 ROUTINE  OTHER

RELAY INFORMATION DEVICE NO MFR. TIME RANGE OHMIC RANGE @ ANGLE CT RATIO

FUNCTION TYPE

DEVICE NO MFR. TIME RANGE CT RATIO

FUNCTION TYPE

DEVICE NO MFR. TIME RANGE CT RATIO

FUNCTION TYPE

DEVICE NO MFR. TIME RANGE CT RATIO

FUNCTION TYPE

SETTINGS STYLE

INST. RANGE OFFSET PRI. INST.

PRI. MIN.

STYLE INST. RANGE

PRI. MIN.

PRI. INST. STYLE INST. RANGE

PRI. MIN.

PRI. INST. STYLE INST. RANGE

PRI. MIN.

PRI. INST.

DIRECTIONAL ELEMENTS: DEVICE NO. CONTACTS: A PHASE B PHASE CLOSED TO OPEN AT: (DEG. I LAG E) OPEN TO CLOSED AT: (DEG. I LAG E) MAXIMUM TORQUE AT: (DEG. I LAG E) MIN. P.U.: EXI: IXI: TIME ELEMENTS: DEVICE NO. TIMES TAP CURVE TEST A PHASE B PHASE C PHASE

INST. P.U. CURRENT PRIMARY "ONE-SECOND" GROUND CURRENT (JOINT POLE) TIME ELEMENTS: DEVICE NO. TIMES TAP CURVE TEST A PHASE B PHASE

INST. P.U. CURRENT PRIMARY "ONE-SECOND" GROUND CURRENT (JOINT POLE)

101

C PHASE

DEVICE NO. GROUND

DEVICE NO. TIMES TAP CURVE

TEST

INST. P.U. CURRENT DEVICE NO. TIMES TAP CURVE C PHASE

INST. P.U. CURRENT

TEST

PG&E Transmission Interconnection Handbook

Form G2-2 (Continued) STATION

SW. NO.

DATE INSTALLED DATE LAST TESTED AMPS KV

MFR.

TYPE

RATING

SERIAL NO. OPERATOR: TYPE N.P. VOLTS TO:CLOSE ___C VOLTS AT SW. VOLTS TRIP BY C.S. VOLTS TRIP BY RELAY ____C VOLTS AT SW. VOLTS CLOSING

INTERRUPTING RATING MODEL TRIP MIN. VOLTS TO CLOSE MIN. VOLTS TO TRIP MIN. VOLTS TO WIND/PUMP VOLTS WIND/PUMP AND TRIP VOLTS AT SW. WIND/PUMP

POTL. DEVICE/TRANSFORMERS: MFR. TYPE LOCATION RATING N.P. RATIO CURRENT INDICATING METERS: SOURCE AMMETER WATTMETER VARMETER RECLOSING RELAY: DEVICE NO. MFR. STYLE MODIFIED PER DWG. NO. SYNCH CHECK RELAY: DEVICE NO. MFR. STYLE CLOSING ANGLE

SW. COUNTS ON WIND/PUMP SW. TIME: (CYCLES) CLOSE TRIP TRIP-FREE TIME TO WIND IS OPER. ANTIPUMP?

POTL. DEVICE: FULL SEC. WDG. RATIO: BKN. DELTA VOLTS: NO. OF POTENTIAL ELEMENTS SOURCE

RESTORE POWER TEST LINE BANK/BUS TEST

DEG.

CALIB. WATTS

FULL SCALE

PARALLEL LOCKOUT CYCLE TIME

MIN.: SET AT and 115 VOLTS. TIME DELAY: at 115 VOLTS, ø DEG.

VOLTS. ø DEG. DEG. SEC.

ADDITIONAL RELAY DATA DEVICE NO.

MFR.

TYPE/STYLE

RATING

REMARKS:

102

USED FOR

VOLTS, AMPS OR TIME OPERATE RESET

PG&E Transmission Interconnection Handbook

Table G2-4 RELAYS FOR GENERATION APPLICATION2,4 (For Directional Overcurrent and Distance Relays, refer to Table G2-5) (See notes on pages following table)

DEVICE

Synch Check Relay

Synchronizing Relay7

Automatic Synchronizer7

Device Number

25

25

15/25

NonDirectional Overcurrent Relay

Nondirectional Overcurrent Relay Ground

Overcurrent with Voltage Restraint or Voltage Control

Overvoltage Relay 15

Overvoltage5 Ground Fault Detection (Neutral)

Frequency Relay (Under/ Over)

Under, Over, & Reverse Power11

Time Delay

50/518

51N

51V3,6,8

59

59N

81U/O

32

62

Microshield RXIDF CO DPU-2000R

Microshield (MSOC) RXIDF CO DPU-2000R

MCGG

MCGG

BE1-27

BE1-51

BE1-51

BE1-GPS BE1-IPS

BE1-GPS BE1-IPS

BE1-GPS BE1-IPS

M-0296 M-0420 M-3410 M -3410A M-3420 M-3425 M-3425A M-3430 M-3520

M-0420

Undervoltage Relay15

27

MANUFACTURER RXEG CV

ABB (ASEA) (Westinghouse)

DPU-2000R

AREVA

MAVS

BE1-25 Basler Electric

BE1-25A

BE1-GPS13 BE1-IPS

M0390

Beckwith Electric

M3410M3410A

M-0193

M-0193 M-0194

M3520 Cooper Cutler Hammer

IDP-210

M-3410 M-3420 M-3435 M3425A M-3430 M-3520 iDP-210

M-0420 M-3425 M-3410

M-3520 iDP-210

IQ Transfer

RXEG SV COV

RXFE CV8

DPU-2000R

BE1-51/27R8 BE1-51/27c8 BE1-GPS BE1-IPS

M-3420 M-3425 M-3410 M-3410A

M-3520

RXKE RXKD TD

DPU-2000R

MiCOM P921, P923

MiCOM P921, P923

BE1-59

BE1-59N

BE1-81 O/U

BE1-GPS BE1-IPS

BE1-GPS BE1-IPS

BE1-GPS BE1-IPS

M-0296 M-0420 M-3410 M-3410A M-3420 M-3425 M-3425A M-3430 M-3520 iDP-210

M-3425 M-3425A M-3430 M-3520

MVTT

M-0296 M-0420 M-3410 M-3410A M-3420 M-3425M3425A M-3430 M-3520 IDP-210

BE1GPS12 BE1-IPS

BE1-GPS BE1-IPS

M341012 M3410A12

M3520 iDP-210 IQ

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Table G2-4 RELAYS FOR GENERATION APPLICATION2,4 (For Directional Overcurrent and Distance Relays, refer to Table G2-5) (See notes on pages following table)

DEVICE

Synch Check Relay

Synchronizing Relay7

Automatic Synchronizer7

Device Number

25

25

15/25

Undervoltage Relay15

27

NonDirectional Overcurrent Relay

Nondirectional Overcurrent Relay Ground

Overcurrent with Voltage Restraint or Voltage Control

Overvoltage Relay 15

Overvoltage5 Ground Fault Detection (Neutral)

Frequency Relay (Under/ Over)

Under, Over, & Reverse Power11

Time Delay

50/518

51N

51V3,6,8

59

59N

81U/O

32

62

MANUFACTURER IFC IFC IAV SR-489

General Electric (Multilin)

D-60

SASB Mark V

F-60

D-60 L-90 T-60 F-60 F-35

SEL-300G SEL-311C SEL-311L SEL-300G SEL-311C SEL-311L

SR-489 SR-745 D-60

SR-489 SR-745 D-60

F-60 F-60 F-35

F-35

L-90 T-60 SR-735 SR-737

L-90 T-60 SR-735 SR-737

SEL-300G SEL-251 SEL-311C

SEL-300G SEL-251 SEL-501

SEL-321 SEL-351

Schweitzer SEL-221F

SEL-387E SEL-351

IFCV IJCV SR-489

SEL-321 SEL-351 SEL-387 SEL-387E SEL-501 SEL-551 SEL-587

SEL-321 SEL-351 SEL-387 SEL-387E SEL-551

SR-489 SR-745 D-60 L-90 T-60 F-60

F-60 F-35

SEL-300G

IFV IAV SR-489

F-60

SR-489 (two steps) F-60 D-60 L-90 T-60

SEL-300G SEL-311C SEL-311L

SEL-300G SEL-311C SEL-311L

SAM

SFF SR-489

D-60 L-90 F-60

SEL-300G

SEL-321 SEL-351 SEL-387E

SEL-351 SEL-387E

SEL-300G SEL-311C SEL-311L

SEL-387 SEL-501 SEL-351

SEL-300G

SEL-351

F-60 F-35

SEL-351717

SEL-387E SEL-551

Woodward

SPM 9905-005 DSLC, MSLC DSM 9905204

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Notes for Table G2-4: 1. Generation requiring three underfrequency set points may necessitate an additional underfrequency device. 2. All microprocessor-based relays that are applied as a multifunctional protection device will require backup relays. (Alternate or backup protective relays can be electromechanical, solid state, or microprocessor based relays.) Most microprocessor relays include event reporting and fault locating functions. Relay settings, sequences of events listing, and fault records should not be lost or revert to default values when DC source is momentarily lost. Event and Oscillography should not be erased from the relay records when the front panel reset button is exercised to reset the Target LCD display. 3. Voltage restrained overcurrent relays are preferred; however, if no problems with protective coordination occur, voltage controlled relays may be used. An auxiliary potential transformer is required for the 51V if the main interconnecting transformer is a wye-delta bank and the relay does not automatically adjust for appropriate phase shift. 4. The above table contains information regarding specific products, manufacturers and representatives. These tables are not all inclusive. The inclusion or omission of products, a manufacturer or representative is not meant to be an indication of the quality or reliability of a product or service. No endorsements or warranties are implied. Other types of relays may be acceptable but certified test results performed by an independent party must be reviewed and approved by PG&E prior to installation and commercial operation. 5. Refer to the notes on Table G2-5 for a list of approved relays used in open delta ground sensing schemes. Relay should have the magnetic measurement inputs specifically designed to support multiple required tasks. For example, multiple independent relays are required to meet the complements of reverse power, synchronizing check, and ground fault detection overvoltage functions. 6. Distance characteristic relays can be used as an alternate to using voltage restraint relays when system conditions coupled by unit characteristics permit. 7. Synchronizing devices must be ordered with the following option: a) voltage matching, b) phase angle acceptance, c) slip frequency acceptance, and d) breaker time compensation. 8. Three single phase units are implied, a single three-phase overcurrent relay is acceptable if a redundant system is provided. There may be occasions when a three-phase 51V/27R relay may not be applicable. 9. Manual synchronization with synch-check relay and synchroscope only allowed for generators with less than 1000kW aggregate nameplate rating. 10. The Beckwith M-0193 and M-0194 work in conjunction to provide the Automatic Synchronizer function. 11. The Basler BE1-32R has been superceded by the reverse power feature on the devices in this column. For reverse power applications, the relay sensitivity should be evaluated to meet the transformer magnetizing current requirements for reverse power, see Appendix R.

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Notes for Table G2-4: 12. Basler BE1-GPS and Beckwith M3410 have 3 phase measuring power elements. Basler BE1-IPS and Beckwith M3410A and M3520 have three single-phase measuring elements for power measurements and protection computations. Refer to note 11 prior to selection of the devices as different relays have different measuring sensitivity elements. For example, Beckwith M3410A sensitivity is approximately 0.75 mA of real power component, where as Beckwith M-3520 has a sensitivity of 10mA of real component current. The IPS 32 function is suitable for low forward type detection and is suitable for conditions where the power factor is greater than 0.1. 13. The over / under power function of the Basler IPS has user settable 32 setting element that can utilize combination of 1 of 3, 2 of 3, 3 of 3, or total 3-phase power. Verify the user has three phase-to- neutral voltage sources and the relay is set to the 1 of 3 phase power option to meet PG&E’s single phase over / under power requirements. 14. Auxiliary voltage measuring element is required to make use of the Basler BE1-GPS synchronizing check setting option. 15. Multi-function devices in this column have the features that may be utilized provided that the voltage source is utilized. The voltage sensing logic in different styles from the same manufacturer or between different manufacturers may not have capability for loss of voltage detection to alarm, when single phase voltage is used. 16. All relays must have 5A nominal AC input current. 17. For SEL-351-7 verify that the application meets the minimum sensitivity of the relay before selection. The minimum sensitivity of the relay is 3.5 watts secondary (0.05 amps @70v single phase). This relay is approved for Rule 21 "Minimum Import" applications for settings no less than 4 watts secondary. In general, the relay is not approved for reverse power applications (0.1% of bank rating) unless calculations demonstrate that it can be set above the minimum sensitivity.

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Table G2-5 Relays for Generation Interconnection Application (For Voltage, Overcurrent, and Frequency Relays, See Table G2-4) (See notes on pages following table) DEVICE

DEVICE NUMBER MANUFACTURER

ABB (ASEA) (Westinghouse)

AREVA

Distance Relay Zone 1

Distance Relay Zone 2

Distance Zone 2 Pilot Protection

Distance Relay Zone 3 Blocking Pilot

Distance Relay Gnd Distance

Directional Time Overcurrent Phase

Directional Time Overcurrant Ground

Directional Overcurrent Pilot (Phase and Ground)

Current Differential or Phase Compariso n

21

21 Z2

21 Z2C

21Z3C

21Z2G

67

67N

67NC

87L / 78

KD-10

RAKZB (DB) KD-11

REL 301/302 DPU-2000R REL-512

OPTIMHO QUADRAMHO

OPTIMHO QUADRAMHO

REL 302 REL-512 OPTIMHO QUADRAMHO

REL 302

REL 301/302

REL-512

REL-512

OPTIMHO QUADRAMHO

OPTIMHO QUADRAMHO

Basler Electric Beckwith

General Electric

M3425 M3430 M3520 CEY-51

M3425 M3430 M3520 CEB-52

DLP ALPS/LPS SR-489 D-60

DLP ALPS/LPS SR-489 D-60

CEYG-51 DLP ALPS/LPS

DLP ALPS/LPS

DLP ALPS/LPS

D-60

D-60

D-60 L-90

Schweitzer

SEL 221F SEL 221G SEL2PG10

SEL 221F SEL 221G SEL 2PG10

SEL 221-16 SEL-311C SEL 321 SEl-421

SEL 221-16 SEL-311C SEL 321 SEL-421

94

REL-350

Microshield IRV

REL 301/302 DPU-2000R REL-512

Auxiliary

SEL 221F SEL 221G

SEL 221F SEL 221G

SEL 221F

DPU-2000R REL-512

SEL-311C SEL 321 SEL-421

SEL-311C SEL 321 SEL-421

107

IRD IRP REL 301/302 DPU-2000R REL-512

REL-512

OPTIMHO QUADRAMHO

OPTIMHO QUADRAMHO

BE1-67 BE1-IPS

BE1-IPS

M3520 JBC

M3520 JBCG DLP ALPS/LPS

D-60 F-60 T-60 L-90 SEL 267

SEL-311C SEL-311C SEL 321 SEL-421

Microshield

SEL 351 SEL-421

D-60 F-60 T-60 L-90 SEL 267 SEL 221F SEL 221G SEL 2PG10 SEL-311C SEL-321 SEL 351 SEL-421

AR MG-6 SG

REL 302

LFCB

MVAJ

L-90

HFA HGA

DLP ALPS/LPS D-60 L-90

SEL-311C SEL 321 SEL-351 SEL-421

SEL-311L

PG&E Transmission Interconnection Handbook

Notes for Table G2-5: The above table contains information regarding specific products, manufacturers and representatives. This table is not all-inclusive. The inclusion or omission of a product, manufacturer or representative is not meant to be an indication of the quality or reliability of a product or service. No endorsements or warranties are implied. Only PG&E approved relays may be installed for protection of interconnecting distribution or transmission lines. Refer to Appendix F for direct transfer trip (DTT) and pilot protection requirements when applicable. Most microprocessor relays include event reporting and fault locating functions. Relay settings, event, and fault records should not be lost or revert to default values when DC source is momentarily lost. Event and Oscillography should not be erased from the relay records when the front panel reset button is exercised to reset the Target LCD display. All microprocessor based relays being used as a multifunctional protection device will require backup relays, except for generation less than 400 kW aggregate nameplate with relay failure output contact connected to trip the generation breaker. (Alternate or backup protective relays can be electromechanical, solid state, or microprocessor based relays.) Primary and alternate protective devices must utilize different operating principals and not be subject to possible common mode failures in order to minimize the potential for insufficient interconnection protection, where applicable, or unnecessary plant shut down; for example, due to possible product advisory letters issued by the manufacturers. Neutral or broken delta ground detection relays approved for interconnection are ABB CV-8 and GE IAV and I All relays must have 5A nominal AC input current.

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Table G2-6 OVERFREQUENCY AND UNDERFREQUENCY RELAYS OVERVOLTAGE AND UNDERVOLTAGE RELAYS Transmission System Interconnection Description of Facility Generation of 100 kW or Less Generation > 100 kW (except hydro generators using three set point relay) Generation > 100 kW (hydro generators only using single set point relay) Generation > 100 kW (non-hydro induction generators using single set point relays) Generation > 100 kW (using single set point relay except hydro and induction generators)

3

4

Under Voltage (% of Nominal)

Over Frequency

Under Frequency

Over Voltage (% of Nominal)

62.0 Hz @ 1 sec

58.0 Hz @ 30 sec

120

80

63.0 Hz @ 30 cycles

58.4 Hz @ 1.5 min 58.0 Hz @ 30 sec 57.6 Hz @ 7.5 sec

120

80

1,2,6

63.0 Hz @ 30 cycles

54.0 Hz @ 6 cycles

120

80

63.0 Hz @ 30 cycles

55.0 Hz @ 6 cycles

120

80

120

80

63.0 Hz @ 30 cycles

57.0 Hz @ 0 cycles

Notes: 1. Underfrequency relays shall be set no higher than the recommended settings above. 2. Generators 75 MW and larger must use underfrequency relay with three set points. For generators greater than 100 kW and less than 75 MW, except hydro generators, an underfrequency relay with three set points is recommended. 3. The overvoltage relay is set to initiate a trip of the circuit breaker without an intentional time delay when the voltage is equal or above the stated percent of normal. 4. For undervoltage relays, set time delay typically at 3 to 5 seconds at zero voltage to allow for motor starting and for coordination of line protection devices. 5. All settings meet the WECC underfrequency requirement

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Section G3: OPERATING REQUIREMENTS FOR TRANSMISSION GENERATIN ENTITIES PURPOSE The purpose of this section is to help all generators satisfy applicable PG&E operating requirements. In addition to the operating requirements in this handbook, a more detailed description may be found in the CAISO Tariff and Protocols, which may be obtained from the ISO. See Appendix A for the ISO’s address or visit the ISO website.

Applicability The operating requirements of this section apply to all generators interconnecting with the Transmission System, All generators must meet applicable Western Electric Coordinating Council (WECC) standards. Participating Generators shall operate, or cause their facilities to be operated, in accordance with the CAISO Tariff and Protocols, and are required to have signed applicable Agreements with the ISO. Participating Generators, connected to the ISO Controlled Grid, are required to schedule energy or Ancillary Services through a designated Scheduling Coordinator. Furthermore, Participating Generators greater than 10 MW (and their active Scheduling Coordinator) electing to provide Ancillary Services must possess and maintain a valid ISO certification to provide such Ancillary Services. In the absence of specific ISO Protocols, the Participating Generator shall abide by the CAISO Tariff and operating requirements established by PG&E. If conflicts arise between the PG&E’s operating requirements and the CAISO Tariff or Protocols, the CAISO Tariff and Protocols shall take precedent subject to resolution through the TAC or ADR processes.

G3.1. REACTIVE AND VOLTAGE COLTROL REQUIREMENTS FOR GENERATORS Reactive power (Var) and voltage control are vital components of safe and reliable system operation. It is essential that PG&E receive both real and reactive power from interconnected generators. Where a Generator is unable to furnish reactive power support, due to interconnection limitations, type of generator, the generator loading or other reasons, the Generation Entity shall install equivalent reactive support or power factor correction at the Generation Entity’s expense or make other arrangements with PG&E. How a generator meets PG&E’s reactive requirements depends on its type and size. Synchronous generators have an inherent reactive flexibility that allows them to operate within a range to either produce or absorb Vars. Induction generators operate at a power factor absorbing Vars and require power factor corrective equipment such as capacitors. Inverters, such as those used to connect Photo-voltaic (PV) generating facilities to AC systems, are also subject to reactive and voltage control requirements.

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G3.1.1. Synchronous Generator Control

G3.1.1.1. Frequency/Speed Control To enhance system stability, a governor is required on the prime mover, set to provide a 5 percent droop characteristic. Exceptions must be approved by PG&E. Governors shall be operated unrestrained to regulate system frequency.

G3.1.1.2. Voltage Control Voltage regulators are required for all synchronous generators larger than 100 kW. All synchronous generators connected to PG&E’s transmission system shall operate the units using the voltage regulators for voltage control. The Designated PG&E Electric Control Center will specify the required voltage schedule that will be used to determine the set point of the automatic voltage regulator. Generators connected to the distribution system in most cases will also require a power factor controller. Generators connected to the transmission system that have both voltage and power factor modes available on the controller system, shall be set on voltage control mode. In rare exceptions the Designated PG&E Electric Control Center may direct a specific generator(s) to operate on power factor control mode. Voltage regulators must be capable of maintaining the generator voltage under steady-state conditions without hunting and within ± 0.5 percent of any voltage level between 95 percent and 105 percent of the rated generator voltage

G3.1.1.3. Power System Stabilizer Operating Requirements For Generators Synchronous generators larger than 30 MVA are required to have power system stabilizers (PSS).. Generators with properly tuned and calibrated PSS provide damping to electric power oscillations. Such damping improves stability in the electrical system and may also prevent an individual generator from unnecessary tripping. The PSS must be calibrated and operated in accordance with the latest standard procedures for calibration, testing and operation of such equipment. See Appendix H for WECC tuning guidelines. Recalibration and testing of the PSS is required at least every five years; data must be submitted for approval to PG&E’s Director of Electric Planning, Strategy, and Engineering.

G3.1.1.4. Power Factor Control A power factor controller is generally only applicable to units connected to the distribution system It shall maintain a constant power factor on a

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synchronous generator by controlling the voltage regulator. The controller must be capable of maintaining a power factor within ± 1 percent at full load at any set point within the capability of the generator. However, in no case shall control limits be greater than (closer to 100%) between 90 percent lagging (producing Vars) and 95 percent leading (absorbing Vars) at the generator terminals. In addition, all power factor controllers for synchronous generators larger than 1,000 kW must have programmable capability to vary hourly settings. The Designated PG&E Electric Control Center shall specify required settings for voltage or power factor. Generally, a power factor of 1.0 is preferred on distribution level systems.

G3.1.2. Non-Synchronous Generator Control (without Var Control) Induction generators or other generators without Var control absorb Vars and therefore require reactive power support from PG&E’s system. All facilities require power factor correction. Power factor correction or capacitors must be installed either by the Generation Entity or as part of the special facilities installed by PG&E at customer expense. Care must be exercised by the Generation Entity in connecting capacitors directly to the generator terminals to avoid selfexcitation. Switched capacitors supplied by the Generation Entity shall be switched on and off at the request of PG&E.

G3.1.2.2. Induction Generators Larger Than 40 kW Under Electric Rule 21, the Generation Entity must provide reactive supply equivalent to operating at 95 percent leading power factor (absorbing Vars). Wind generating facilities must provide unity power factor at the point of interconnection (POI), unless PG&E studies specify a range. PG&E may further require the provision of reactive support equivalent to that provided by operating a synchronous generator anywhere within the range from 95 percent leading power factor (absorbing Vars) to 90 percent lagging power factor (producing Vars) within an operating range of ± 5 percent of rated generator terminal voltage and full load. (This is typical, if the induction project is greater than 1,000 kW.) When PG&E determines that it is not practical for the Generation Entity to provide this level of support, the customer shall be charged the cost to install capacitors on the PG&E system as special facilities to correct to either 95 percent leading power factor (absorbing Vars) or to 90 percent lagging power factor (producing Vars).

G3.1.3. Inverter-Based Generating Facilities Inverters convert the output of DC systems such as Photo-Voltaics to AC. The AC voltage is then stepped-up to a higher voltage through one ore more transfomers such that the power is delivered at utility-compatible transmission or distribution voltage levels. Inverter-based generating facilities need to provide

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reactive power (Vars) to control voltage. It shall be measured at the facility side (generally the low voltage side) of the step-up transformer that connects to PG&E. The facility reactive capability shall be at least capable of providing 43 percent of facility Watt rating into the system and capable of accepting 31 percent of facility Watt rating from the system.

G3.2. GENERATOR STEP-UP TRANSFORMER The available voltage taps of a Generation Entity’s step-up transformer must be reviewed by PG&E for their suitability with PG&E’s system. The Generation Entity is expected to request this review before acquiring the transformer. PG&E shall determine which voltage taps would be suitable for a step-up transformer for the Generation Entity’s proposed project. Suitable taps are required to give the transformer the essential capacity for the generator to: •

Deliver maximum reactive power to PG&E’s system at the point of interconnection (generator operating at 90 percent lagging power factor) and,



Absord maximum reactive power from PG&E’s system (generator operating at 95 percent leading power factor).

The Generation Entity’s transformer, with correct voltage taps, helps maintain a specified voltage profile on PG&E’s system for varying operating conditions. Actual voltage tap settings can be different for transformers connected at the same voltage level, depending upon their geographic location.

G3.3. POWER QUALITY REQUIREMENTS G3.3.1. Voltage Fluctuation Limits A generator connected to the PG&E system must not cause harmful voltage fluctuations or interference with service and communication facilities. Any generation facility that does so is subject to being disconnected from the PG&E system until the condition has been corrected. Refer to Electric Rule 21, Section D.2.

G3.3.2. Harmonic Limits All generators shall comply with the voltage and current harmonic limits specified in IEEE Standard 519-1992, “Recommended Practices and Requirements for Harmonic Control in Electrical Power Systems”. The harmonic content of the voltage and current waveforms in the PG&E system must be restricted to levels which do not cause interference or equipmentoperating problems for PG&E or its customers. Any harmonic problems shall be handled on a case-by-case basis. A generation facility causing harmonic interference is considered by PG&E as a serious interference with service and is subject to being disconnected from the PG&E system until the condition has been corrected. (Refer to Electric Rule 21, Section

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D.2). If the cause of the problem is traceable to the Generation Entity’s facilities, all costs associated with determining and correcting problems shall be at the customer’s expense. Many methods may be used to restrict harmonics. The preferred method is to install a transformer with at least one delta connection between the generator and the PG&E system. This method significantly limits the amount of voltage and current harmonics entering the PG&E system. Generation system configuration with a star-grounded generator and a two-winding (both stargrounded) transformer shall not be allowed.

G3.4. VOLTAGE RIDE-TROUGH REQUIREMENTS PG&E currently follows the Low Voltage Ride-Through Criteria that WECC has adopted to ensure continued reliable service. More information on voltage ride-through requirements is available at the WECC website: http://www.wecc.biz/committees/StandingCommittees/PCC/TSS/Shared%20Documents /Voltage%20Ride%20Through%20White%20Paper.pdf More information on voltage ride-through issues associated with alternative technologies can be found on the FERC website: http://www.ferc.gov/industries/electric/indus-act/gi/wind.asp

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Section G4: OPERATING PROCEDURES FOR TRANSMISSION GENERATION ENTITIES PURPOSE The purpose of this section is to provide generators with a general understanding of applicable PG&E and the California Independent System Operator (CAISO) operating procedures. PG&E and the generator must be in agreement on specific operating parameters before the generator is allowed to interconnect with the grid.

Applicability The operating procedures of this section apply to all generators interconnecting with the CAISO Controlled Grid. For all other Generation Entities, including Participating generators, the PG&E agreement may not include certain provisions of this section, such as energy reporting, paralleling/separating, and Ancillary Services (handled by Scheduling Coordinators), and maintenance scheduling (handled by the CAISO). Such provisions, which are described in the CAISO Tariff, will be covered under separate agreements between the generator and these entities. In the future, and subject to appropriate regulatory approval, the CAISO may develop additional procedures applicable to certain interconnections. If conflicts arise between the PG&E operating procedures and the CAISO’s procedures, the CAISO procedures shall take precedent subject to resolution through the CAISO ADR processes.

G4.1. JURISDICTION OF THE CAISO AND THE PG&E GRID CENTER (GCC) On March 31, 1998 the CAISO assumed operational control over most of PG&E’s 60 Kv and above transmission grid. Notwithstanding the operational jurisdiction of the CAISO over most of the PG&E transmission system, the CAISO Protocols delegate certain operational activities to PG&E on selected parts of the CAISO Controlled Grid. Under the CAISO’s control and instruction, PG&E performs all physical switching operations, including de-energization and restoration of PG&E-owned facilities. PG&E continues to serve as the primary point of contact for Generation Entities that are connected to the CAISO Controlled Grid and will communicate and coordinate with the CAISO, as specified in the CAISO’s Protocols, Operating Procedures and tariffs. The Generation Entity, while operating its facility interconnected with the CAISO Controlled Grid or the PG&E system, shall at all times follow the operating instructions of the CAISO and PG&E. The Grid Control Center (GCC) shall be responsible for implementing the CAISO’s Orders, Protocols and Operating Procedures. The GCC may delegate the communication of operating instructions for Generation Entities to the designated PG&E Area Operations Center (AOC).

G4.2. COMMUNICATIONS The generation customer shall maintain telephone service at the Generating Facility. If the facility is remote or unattended, telephone service shall be provided to the nearest

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location normally occupied by the entity responsible (acting on its own behalf or through its designated Generating Facility operator). PG&E and the Generating Facility operator shall maintain operating communications through the designated PG&E Electric Control Center. The Generating Facility operator shall be accessible at all times and shall provide to the designated PG&E Electric Control Center a 24-hour phone number where the facility operator may be reached. The facility operator shall maintain, in a prominent location, the name of the designated PG&E Electric Control Center along with applicable instructions and a list of necessary telephone numbers and coded alarms for such Generating Facility.

G4.2.1. Daily Capacity and Energy Reports Generation Entities whose facilities may produce 1000 kW or more must provide data, via telemetry, to the CAISO according to the requirements of the CAISO Tariff. PG&E may also require telemetry of data depending on the number of generators and the complexity of the transmission configuration. The Generating Facility operator shall provide and maintain the data circuits required for telemetering. When such telemetering is inoperative, the facility operator shall report to the designated PG&E Electric Control Center on a daily basis the voltage reading and the real and reactive power quantities delivered each hour and the energy delivered each day.

G4.2.2. Voltage Control Operation and Other Service Requirements The Generating Facility operator shall operate any voltage control (i.e., generator controls, shunt capacitors) at the direction of the designated PG&E Electric Control Center and in accordance with the provisions of applicable agreements, applicable tariff(s), CAISO requirements and other electric service schedules. The facility operator shall post voltage orders from the designated PG&E Electric Control Center prominently so that any relief or backup operator is aware of the current PG&E voltage instruction. The Generation Entity is responsible for the safe operation and interruption and de-energization of the generatior-owned voltage control devices. If a Generating Facility; a) becomes separated from the power system and is carrying a portion of system load (islanded operating condition), and b) is unable to communicate with the designated PG&E Electric Control Center or the PG&E Grid Control Center (GCC) , the generator shall be set to operate for unrestrained governor operation and maintain normal frequency and voltage until communications are restored. Prime movers for generators with power system stabilizers shall be operated on free governor, unless the Generating Facility operator and the CAISO system dispatcher otherwise agree for a temporary period. The standard governor droop setting shall be 5 percent. If the Generation Entity is participating in any interruptible service schedule, the Generating Facility operator must be capable, through additional equipment, of controlling generation to respond to system or local load conditions or system

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frequency deviations or other direct or automatic control from the CAISO. In addition, where identified in the interconnection study, the Generating Facility may be required to participate in a remedial action scheme to maintain or enhance the operating capability or performance of the PG&E electric system. Whenever primary relays or protective devices are out of service, backup or secondary relays must be available to clear faults. If the backup relays malfunction, the Generation Entity must provide a designated representative in readiness to manually perform necessary operations. When restoring any relays that have been out of service, the Generating Facility designated representative shall verify that the contacts of any such relays, which are normally open, are in fact open. Generating entity must ensure that relays do not have standing trip output. Note: The CAISO may have additional requirements for systems designated as CAISO Grid Critical Protective Systems. Refer to the CAISO Tariff available on the CAISO website.

G4.2.3. Paralleling to and Separating from PG&E (Attended Generating Facilities Only) The Generating Facility designated representative shall notify the Designated PG&E Electric Control Center prior to paralleling or separating from the PG&E system. For unexpected separations, the generatorgenerator designated representative will inform the Designated PG&E Electric Control Center of the nature of the problem (i.e., overvoltage, underfrequency, ground fault, remedial action, etc.) and report on any relay target operations. See Section G4.3 for unattended generation facilities with automatic or remotely initiated paralleling.

G4.2.4. Clearances and Switching Requests The Generating Facility operator must request a clearance from PG&E a minimum of 96 hours (four calendar week days) in advance. PG&E shall notify the Generating Facility 96 hours (four calendar week days) in advance of any plans to take a clearance which affects the Generating Facility. Each interconnected facility shall have installed an approved disconnect or other switching device for operation by the Generating facility as a clearance point. The disconnect must be capable of being locked open and accessible to PG&E personnel.

G4.2.5. Unusual or System Emergency Conditions For all System Emergencies, the CAISO is responsible for managing the emergency and for restoration as specified in the CAISO Tariff. All Generating Units and System Resources that are owned or controlled by a Participating Generator are (without limitation to the CAISO’s other rights under this CAISO Tariff) subject to control by the CAISO during a System Emergency and in circumstances in which the CAISO considers that a System Emergency is imminent or a threat. The CAISO shall, subject to CAISO Tariff Section 5.6.2, have the authority to instruct a Participating Generator to bring its Generating

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Unit on-line, off-line, or increase or curtail the output of the Generating Unit and to alter scheduled deliveries of Energy and Ancillary Services into or out of the CAISO Controlled Grid, if such an instruction is reasonably necessary to prevent an imminent or threatened System Emergency or to retain Operational Control over the CAISO Controlled Grid during an actual System Emergency. PG&E is responsible for complying with all directions from the CAISO regarding management and alleviation of the System Emergency, unless such compliance would impair the health and safety of personnel or the general public. As directed by the CAISO, PG&E will be responsible for communicating with Generation Entities regarding emergencies. Unusual operating conditions or other factors that have affected or may affect the CAISO Controlled Grid or PG&E’s electric system (e.g., abnormal voltages or loading or unbalanced loading) must be reported to the Designated PG&E Electric Control Center as soon as possible. Conditions imperiling life or property shall be reported to the designated PG&E Electric Control Center immediately. The Designated PG&E Electric Control Center shall be notified of any forced outage. The Designated PG&E Electric Control Center shall notify the Generating Facility of any unusual CAISO Controlled Grid or PG&E conditions that may affect the customer’s facility. During any emergency the facility operator shall follow the instructions of the designated PG&E Electric Control Center. Interruptible Generation Entities may not re-parallel until authorized by the Designated PG&E Electric Control Center.

G4.2.6. Emergency/Backup Generators For additional emergency generator paralleling requirements, refer to Section G2.14.

G4.2.7. Other Communications The facility operator shall notify the designated Account Manager of the following: •

Any replacement, modification or removal of any interconnection generation facilities (i.e., transformer, breaker, changes in EMS/SCADA, disconnect, relays, remedial action equipment, etc.).

Note: Regardless of generator size, protective equipment designated as CAISO Grid Critical Protective devices utilize special CAISO procedures, as specified in the CAISO Tariff. The facility operator shall follow the manufacturer’s minimum maintenance requirements on file for audit by the PG&E Designated Substation Maintenance Supervisor: •

Results of three-year or four-year bench tests on all PG&E-required relays.



Results of six-year or eight-year tests on interconnection circuit breakers and transformers.

The facility operator shall notify the designated PG&E Electric Control Center:

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The time of any relay operations and targets of the relay that caused the Generating Facility to separate, if applicable.



The time of any paralleling with and separations from the PG&E system.



The time of the change in voltage-control device set points (if applicable) and the time of change in the operating status (i.e., opened or closed) of any other voltage-control device (i.e., shunt capacitors or reactors).

Note: These three items in boldface type are information an event recorder at an unattended facility must be able to provide to PG&E, and are referred to in Section G4.3.3.

G4.3. UNATTENDED GENERATING FACILITIES G4.3.1. Verification of Energized Circuit An unattended Generating Facility with remotely initiated restoration must consult with the designated PG&E Electric Control Center prior to re-parallel. PG&E must confirm that the circuit to which the generation facility will be paralleled is energized by a PG&E-approved source of energy.

G4.3.2. Loss of Power/Automatic Re-paralleling All unattended Generating Facilities with automatic or remotely initiated paralleling must have the following capabilities in the event of loss of power: •

Relays must have the capability of retaining targets on loss of power, or an event recorder must be provided which will permanently record all relay target information including time and duration.



Automatic re-paralleling must be accomplished in less than 5 minutes after the initial trip. If a re-parallel attempt after the initial trip is unsuccessful, the automatic re-paralleling equipment must lock-out. No subsequent reparalleling attempt shall be made under any of the following conditions: o One unsuccessful attempt to re-parallel was made. o A successful re-parallel was followed by a subsequent trip within 5 minutes due to lack of electrical potential on the circuit to which the Generating Facility would be connected.

Unattended Generating Facilities with automatic initiated connection are not required to notify the designated PG&E Electric Control Center prior to making an automatic initiated parallel with the CAISO Controlled Grid or the PG&E system or following an automatic separation, unless a lock-out condition has occurred. After any separation from PG&E’s system, if automatic re-paralleling equipment has locked out or if the connection was separated manually, the Generation Entity may not re-parallel either automatically or manually until authorized by the designated PG&E Electric Control Center.

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G4.3.3. Event Recorder All unattended Generating Facilities with capability greater than 1.0 MW and with automatic or remotely initialed paralleling capability must have an event recorder recorder that will enable PG&E to make an after-the-fact determination of the status of the Generating Facility at the time of the system disturbance, should such a determination be required. The events should be recorded to a one (1) milli-second resolution. The Generating Facility shall ensure the time reading is correct and synchronized to an accurate time standard. The event recorder or other recording device(s) at the Generating Facility must be capable of providing a record of the information specified in the three items in Section G4.2.7 which are in boldface type. In addition, for generation facilities with a nameplate rating equal to or greater than 1,000 kW, the event recorder must also provide a record of deliveries to PG&E of real power in kW and reactive power in kVar and output voltage in kV.

G4.4. PROCEDURES ON TRANSFER TRIP PROTECTION FOR GENERATION FACILITIES These procedures describe the interaction between PG&E and generation facilities when malfunctions of transfer trip (TT) protection schemes occur. The procedures apply to all generation facilities with transfer trip protection that have a direct connection, at any voltage level, to the CAISO Controlled Grid or the PG&E system.

G4.4.1. Purpose and Definition There is a potential risk to both PG&E generation facilities and non-PG&E owned generation facilities when a generator’s TT protection is out of service. This risk includes, but is not limited to: •

The generator would continue to feed a fault on a line after the line has relayed and is no longer connected to the rest of the CAISO Controlled Grid or the PG&E system, thereby endangering life and property. Significant damage could occur to the generator and associated equipment.



The generator would continue to feed a fault on a line for a longer period of time, thereby risking equipment damage and reducing reliability.

All generators having TT protection shall be classified by level of risk in one of two categories: •

Type A (inadequate back-up protection). The generator’s back-up protective relays cannot see end-of-line faults and as such represent a hazard, as described above, while TT protection is out of service.



Type B (adequate back-up protection). The generator’s back-up protective relays can see end-of-line faults, but will separate the generator from the system more slowly than with the TT protection in service.

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G4.4.2. Separation Following Loss of Transfer-Trip Protection The following standard applies to all generators that have TT protection •

Type A (inadequate back-up protection) generation facilities shall separate from PG&E’s system immediately upon loss of TT protection. generatorgenerators that have two or more PG&E TT terminals are not required to separate immediately if the remaining TT channel(s) provide backup protection.



Type B (adequate back-up protection) generation facilities will be allowed to remain on-line, provided they restore the TT protection to working order within seven calendar days and initiate repairs within 24 hours of loss of TT protection.



Repeated intermittent TT failures (regardless of Type A or Type B category) may indicate that the TT is unreliable. In such cases, the Designated PG&E Electric Control Center will notify the Generating Facility that it has seven days to restore the TT scheme to reliable operation. If at the end of seven days this has not been done, the generator must then immediately separate from the CAISO Controlled Grid or the PG&E system.



A small number of Type A generators have a protection scheme designed to trip the generator automatically when TT protection is lost. The procedures set forth in this document apply to these generation facilities, except that the “order to separate” described below need not be issued because the generator will have already been separated from the system when the TT protection is lost.

G4.4.3. Procedures When the Generating Facility is made aware of loss of Transfer-Trip protection, they shall notify the designated PG&E Electric Control Center. If the Designated Electric Control Center receives a “TT channel failure” alarm and has not been notified by the Generating Facility, the Designated PG&E Electric Control Center will attempt to contact and notify the Generating Facility operator that transfer trip has been lost. Contact with the Generating Facility will be considered to have been made if the Designated PG&E Electric Control Center has called the listed phone number for the Generating Facility and a fax of the orders/notification has been sent to the facility. •

Type A: The Designated PG&E Electric Control Center will order a Type A Generating Facility to immediately separate from the CAISO Controlled Grid or the PG&E system.



Type B: The Designated PG&E Electric Control Center will direct a Type B Generating Facility to remain on-line provided it begins repair work within 24 hours and restores TT protection to working order within seven calendar days. Type B facilities must report back to the Designated PG&E Electric Control Center, by phone or fax, to confirm that repair work was in fact initiated within 24 hours of the notification. At the end of seven days, if the TT 121

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protection scheme has not been restored, the Designated PG&E Electric Control Center will order the Generating Facility to immediately separate from the CAISO Controlled Grid or the PG&E system.

G4.4.4. Separation Orders All conversations regarding PG&E notifications and separation orders shall be logged by both the Designated PG&E Electric Control Center and Generating Facility Operators. The log shall include as a minimum: date, time, names of both operators, the reason for the separation order, switch number(s) to be opened and any other pertinent information. Upon completion of separation, the facility operator shall report back to the Designated PG&E Electric Control Center, confirming the time separation was completed. The “Report of Completion” conversation shall be logged to include the items specified in the preceding paragraph.

G4.4.5. Non-Compliance Separation Order It is critical to both parties' interests that a Generating Facility separates from PG&E's system upon receipt of separation orders. Failure to comply with a separation order following loss of TT protection is unacceptable. CAISO •

Type A: If the non-compliant Generating Facility fails to comply with a separation order, the Designated PG&E Electric Control Center will take immediate action to separate it from the CAISO Controlled Grid or the PG&E system.

G4.4.5. Re-parallel of Generating Facility After Restoration of TT Protection Before a Generating Facility is allowed to re-parallel with the CAISO Controlled Grid or the PG&E system after having received separation orders from PG&E for the loss of TT protection, one of the following criteria must be satisfied: 1. If the loss of TT protection was caused by hardware or communication path change, the PG&E Protection Engineer must authorize and notify the Designated Control Center that TT protection has been restored to proper operation. 2. If the loss of TT protection was caused by communication circuit failure only, and after the TT circuit is repaired and tested, the Designated PG&E Electric Control Center operator will give an OK to cut in the transfer trip and reparallel the generator if necessary.

G4.5. GENERATION ENTITY INTERFERENCE WITH POWER QUALITY Under Electric Rule 21 and IEEE Standard 519, the Generating Entity is responsible for operating its facilities and equipment to avoid unacceptable interference which may adversely affect PG&E’s operations or service provided to other customers, whether by voltage fluctuations, harmonics, or inductive interference. As an example, total voltage

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harmonic distortion may not exceed 5 percent. The Generation Entity is responsible for the costs of mitigating any interference it causes.

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Section G5: ENERGIZATION AND SYNCHRONIZATION REQUIREMENTS FOR TRANSMISSION GENERATION ENTITIES PURPOSE The following is PG&E's procedure for performing pre-parallel inspections and preparing to energize and synchronize the generator to the PG&E transmission system. All time requirements must be met for PG&E to provide the Generation Entity with timely service. Any inspections required by local government agencies must be completed and permits signed off prior to the pre-parallel date. Failure to meet the succeeding requirements within the timeframes specified may result in a delay to successful operations parallel to the PG&E system.

G5.1. TEST RESULTS AND/OR INFORMATION REQUIRED PRIOR TO PRE-PARALLEL TESTING All tests outlined below must be complete and two copies of the test reports submitted to a PG&E representative a minimum of 15 business days before the requested energize date. All test reports require header information reflecting the equipment identification matching the one or three line diagrams. One line and three line diagrams of the facility are required with the test reports. Test reports must be approved by PG&E at least three business days before the requested pre-parallel date. Failure to have PG&E approved test requirements will result in delay of energizing and testing of generation entity’s equipment.

G5.1.1. Proving Insulation For any of the megger tests referred to below, a 2,500 volt DC megger or a hi-pot is preferred, but a 1,000 volt DC megger is acceptable. •

All transformers connected to the primary bus and the main transformer must be meggered winding to winding and each winding to ground. For purposes of this document, “primary bus” is defined as the source-side bus or conductor from the primary interrupting device to the generating plant.



All circuit breakers and circuit switchers connected to the primary bus and at the interconnection point must be meggered in the following manner: Breaker open - each pole to ground, pole 1-2, pole 3-4, pole 5-6; breaker closed - pole 1-ground, pole 3-ground, pole 5-ground and if the poles are in common tank or cell, pole 1-3, pole 3-5, pole 5-1.



All buses and cables shall be meggered phase-to-phase and phase-toground.



The main transformer(s) and main breaker(s) shall have a dielectric test performed on the insulating medium (gas or oil). This does not apply to factory-sealed circuit switcher interrupters. 124

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The generator(s) must be meggered or hi-pot tested phase-to-phase and phase-to-ground.

G5.1.2. Proving Ratios All ratios of transformers connected to the primary bus must be proven using either a turns ratio tester or a voltage ratios test. The main transformer must be tested on the final operating tap. This tap shall be recommended by PG&E to best match current transmission system operating voltages.

G5.1.3. Circuit Breakers and Circuit Switchers •

A minimum to trip at 70 percent or less of the nominal DC control voltage must be performed on all circuit breakers and/or circuit switchers that are operated by PG&E-required relays.



A Micro-Ohm test must be performed on all circuit breakers and circuit switchers.



A timing test showing the time from trip initiation to main poles opening is required.



A timing test showing the time from close initiation to main poles closing is required.

G5.1.4. Current Transformers and Current Circuits •

A saturation check should be made on all current transformers (CTs) associated with the required PG&E relays. If this is not possible, a manufacturer's curve is acceptable.



The ratio of all CTs must be proven either by using current (primary to secondary) or voltage (secondary to primary).



CT circuits must be checked for proper connections and continuity by applying primary or secondary current and reading in the relays. Each test (primary or secondary) must be performed in all combinations to prove proper connections to all phase and ground relays. Current must be applied or injected to achieve a secondary reading of 5 amps in each relay to ensure that no loose wiring or parallel current paths exists.



A single-phase burden check must be made on each phase of each current circuit feeding PG&E-required relays.



A megger check of the total circuit with the ground wire lifted must be done to prove that only one ground exists.

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G5.1.5. Relays All relays 14 must be field tested on site to their specified settings to verify the following: •

Minimum operating point at which relay picks up (minimum pickup).



Time delay at three different current test points, in integral multiples of minimum pickup, that closely characterize the relay time-current curve.



Phase angle characteristic of directional relay.



Pickup points at maximum torque angle (MTA) and ± 30 degrees of MTA on impedance relays using the approved settings.



Slip frequency, voltage matching, phase angle acceptance and breaker compensation time on synchronizing relays.



PG&E tolerances are listed below: o Current/Voltage/Time:

± 10 percent

o Impedance/Phase Angle: ± 0.05

± 0.05 Hz

o Frequency:

If a pilot relay system is required by PG&E, signal level checks must be performed to PG&E standard.

G5.1.6. Primary Disconnect Switch The primary disconnect switch at the point of interconnection shall be assigned a PG&E number by PG&E. The switch, platform, and switch number plate bracket must be constructed to PG&E’s Engineering Standard 034851 and Engineering Design Standard 454092, see Appendix G. A switch number plate bracket shall be furnished by PG&E (Appendix G).

G5.1.7. RTU/RIG/DPU The final RIG/DPG/RTU database shall be provided to PG&E at least 30 calendar days prior to scheduled energization date.

G5.1.8. Station Battery When a battery is installed, proof of discharge testing to ensure that the battery has the capacity to support the load and trip is required.

G5.2. PRE-PARALLEL TEST The Generation Entity is responsible for ensuring that all relays, data telemetry and other protective devices are adjusted and working properly prior to the pre-parallel inspection. If problems arise with equipment during testing, the PG&E protection representative may elect to cancel the test and reschedule. 14

Please see Section G-2 specifically Table G2-5 for information on relay requirements.

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All pre-parallel tests should be scheduled to begin at 8:00 AM and completed by 6:00 PM, Monday through Friday only. Functional tests shall be performed by the Generation Entity and all tests shall be observed by PG&E as outlined below. The Generation Entity shall provide all test equipment and qualified personnel to perform the required tests. PG&E shall be there strictly as an observer. Form G5-1 shall be completed by the PG&E representative on site at the time of the pre-parallel inspection. Before the unit is paralleled to the System to complete tests that require parallel operation, a “permission to parallel for test purposes” letter must be obtained from PG&E’s Electric Operations department. This letter would typically be issued after the functional tests as described in Section G5.2.1 are completed, but before the remaining tests that require the unit to be paralleled begin.

G5.2.1. Functional Tests The following functional tests shall be performed after the equipment has been energized, but before the generator is paralleled with PG&E's system: •

Check that each protective relay trips the appropriate generator breaker and/or main breaker. This may require injecting a signal. Jumpering across contact on the back of the relay is not acceptable.



When first energized, check that proper secondary potential is applied to all voltage and frequency relays.



Check the synchronizing meter, synchronizing equipment and phasing panel (if used) with the paralleling breaker closed and the generator off-line. This typically requires lifting the generator leads. The equipment should show an "in-phase" condition.



Check the generator phase rotation. (PG&E's phase rotation is A-C-B counterclockwise). All three phases must be checked using hot sticks with a phasing tool or a phasing panel provided by the Generation Entity. The synchronizing equipment typically checks one phase only. Any other method of demonstrating correct phasing and phase rotation shall be approved by PG&E in writing prior to conducting the test. Alternative methodologies to check phasing and phase rotations must be submitted to PG&E fifteen business days in advance of scheduled pre-parallel test. PG&E must approve the methodology three business days in advance of pre-parallel test date.

G5.2.2. Impedance and Directional Relay Tests Direction check all impedance and directional relays by doing the following: •

Bring up load on the plant and/or generator.



Verify direction of power flow.



Measure the phase angle between the current and potential applied to the relay.

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Observe the current action of the directional contacts according to the direction of power flow. Reverse either the potentials or current to prove contact operation for reverse power flow.

G5.2.3. Generator Load Tests For generators, the following load tests shall be performed after the generator picks up load: •

Verify operation of the generator at 90 percent lagging power factor and at 95 percent leading power factor at rated output.



Verify operation of the generator at 95 percent and 105 percent of per unit voltage while delivering rated output.



Load check all PG&E required differential relays. The load current must balance to zero in all differential relays.



Load check voltage restraint overcurrent relays to prove correct connection of currents and potentials (Form G5-2).



The generator(s) may have to be paralleled temporarily with PG&E’s system to run the load tests. Permission to do this shall be given by the PG&E Operations.

G.5.2.4. Data Telemetry Tests PG&E Operations must verify the following prior to Pre-Parallel Operations. •

Communications circuits meet Appendix F specifications and are functioning properly.



RIG/DPG/RTU data is mapped correctly to PG&E EMS and SCADA systems. o Scaling on all analog data points is correct. o Point to Point check on all status points is verified at PG&E electric control centers.

Typically, pre-parallel inspections can be performed within a normal working day. PG&E shall dedicate one full work day to observe the test. If a test cannot be completed by 6:00 PM, the PG&E representative may cancel the remainder of the test and reschedule it. In this case, the Generating Entity shall incur additional costs for the pre-parallel inspection.

G5.3. REQUIREMENTS FOR COMMERCIAL (PARALLEL) OPERATION G5.3.1. Clearance for Parallel Operation (For Testing Purposes Only) Generating Entity shall certify that it has met all pre-parallel requirements ten business days before commencing Commercial Operation. The PG&E representative shall notify the California Independent System Operator in writing that the Generating Entity has met all the requirements to synchronize to the grid

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at least 7 calendar days before the pre-parallel test and prior to obtaining a clearance for parallel operation. The PG&E representative shall contact the designated PG&E Electric Control Center at least 72 hours before the pre-parallel test and obtain a clearance for parallel operation. The PG&E representative shall provide the designated PG&E Electric Control Center a drawing indicating which PG&E circuit the generation facility will be connected to, and which PG&E operated disconnect will be identified with a PG&E designated number. When the pre-parallel test is passed, the generator may at PG&E’s discretion be allowed to operate in parallel with PG&E for testing purposes only. This should not be mistaken as an official release for parallel operation. Once this testing-only permission is granted, the generator may operate in accordance with the previously executed Generation Interconnection Agreement for a maximum of 14 days, or a period previously approved by PG&E. If applicable, firm capacity performance testing of new generators cannot begin until the Generation Entity receives written permission from PG&E.

G5.3.2. Power System Stabilizer (PSS) During the Parallel Operation for Testing period, the Power System Stabilizer shall be calibrated and tested in accordance with the latest WECC standard calibration and test procedures as outlined in Appendix H. The test report shall be submitted for approval to PG&E’s Director, Transmission & Distribution Engineering at the following address: Director, Electric T&D Engineering Pacific Gas and Electric Co., Mail Code H12A P.O. Box 770000 San Francisco, CA 94177 Adequate testing of the PSS can only occur on the generating unit(s) after preparallel inspection has been satisfactorily completed and the units are paralleled and supplying load. The generation facility shall not be considered officially operational until this PSS calibration and testing has been done to PG&E’s satisfaction. Failure of the Generation Entity to maintain its PSS could adversely impact system operation. PG&E reserves the right either to disconnect from, or refuse to parallel with, any Generation Entity which does not operate and maintain its generator control systems in accordance with applicable reliability criteria. The PSS Reports shall include a minimum of the following: •

Description of unit including ratings.



Excitation system type and ratings.



PSS type, inputs, and available setting ranges for adjustable parameters. Include description of failure detection system if provided.

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Modifications required to provide final settings.



List of final settings, including: o Limit settings + and – gain. o Lead and lag time constants. o Washout time constant. o Any included filtering (fixed or settable).



Models: o PSS model and parameters. o Excitation model and parameters.



Bode plots: o Excitation response with unit connected to electrical system without PSS in service (See Figure 7 of Appendix H). o PSS response alone (See Figure 8 of Appendix H). o Excitation response with PSS in service and unit connected to electrical system. This plot can be either via test or calculated based on previous two plots. o If settings are developed through simulations, actual excitation response versus excitation model response used in simulation. (See Figure 3 of Appendix H).



Time plots: o Step response showing generator terminal voltage, field voltage, field current, power, PSS output, AVR output with PSS in service and out of service. (See Figure 5 of Appendix H).

PG&E will not grant permission for a generating facility to commence commercial operations until PSS has been calibrated to PG&E's satisfaction.

G5.3.3. Model Testing and Validation Report Following WECC guidelines, generation equipment shall be tested to verify that data submitted for steady-state and dynamics modeling in planning and operating studies is consistent with the actual physical characteristics of the equipment. The data to be verified and provided shall include generator gross and net dependable capability, gross and net reactive power capability, voltage regulator controls, speed/load governor controls, and excitation systems.

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G5.3.4

Permission for Parallel Operation

At the end of this period, if the Generation Entity has not received written permission from PG&E to operate in parallel, the entity must isolate from PG&E until written permission is received. Written permission to parallel shall be sent to the Generation Entity via U.S. First Class Mail. This shall be done after PG&E has verified the following: •

All proper contracts and documents have been executed and are in place.



The pre-parallel test has been passed.



The Power System Stabilizer tests and calibration have been completed.



All other outstanding issues have been resolved, including rights-of-way, deeds of conveyance, insurance verification and operating agreements.



PG&E has received final copies of the single line diagram and elementary diagrams that show "As-Built" changes made during construction, as well as a completed finalized generator data sheet (Appendix M).

If applicable, firm capacity performance testing of new generators cannot begin until the Generation Entity receives written permission from PG&E to parallel.

G5.4. GENERAL NOTES •

The PG&E system has A-C-B counterclockwise rotation.



Any changes to PG&E required protection equipment or major substation equipment (transformer, breaker, etc.) must be submitted to the PG&E representative for review and approval by the appropriate PG&E engineer prior to the changes being made.



Protective Relays: Routine maintenance on PG&E required protective relays and the breaker(s) must meet PG&E’s maintenance and test practices. After completion of these tests, test reports must be submitted to the PG&E protection specialist for review and approval by the appropriate PG&E engineer. A PG&E technical representative shall then come to the customer’s facilities and verify the settings.

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Form G5-1 (Page 1 of 3) PG&E LOG WO/GM D&C

PACIFIC GAS AND ELECTRIC COMPANY GENERATION PRE-PARALLEL INSPECTION Name of Project: Location: Transmission Line No. 1.

Distance Circuit No.

Maintenance Data: Generation Customer’s Maintenance Chief Telephone Number Generation Customer’s Regular Maintenance Interval Electrical Contractor

2.

Test Reports Attached:

Yes

No

If not, who has the reports: 3.

Generation Facility Manual Disconnect Device for PG&E Line Clearances: Manufacturer Model Number PG&E Device Number

4.

Designated PG&E Electric Control Center

5.

PG&E Inspector NAME

PHONE NO.

Date Inspection Performed: Date Facility Placed on 30 Day Test Released: Distribution: PG&E Designated Electric Control Center (1) Division Project Coordinator (1) Marketing Services (1) Power Contracts (1) GM&C Area Engineering (1) System Dispatch (1)

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Form G5-1 PG&E LOG WO/GM D&C

(Page 2 of 3)

PACIFIC GAS AND ELECTRIC COMPANY GENERATION PRE-PARALLEL INSPECTION 1a. b.

Generator Nameplate:

kW

Generator Type: Synchronous Induction DC w/ Inverter

Volts

Pf

Synchronizing: Auto Manual w/ Relay

Manufacturer c.





Connection: WYE-Ground WYE-Ungrounded Delta

Serial No.

Generator Prime Mover: Wind

Water

Steam

Solar

Fuel Cell

Other, specify d.

Generator Breaker or Contactor: Manufacturer

Serial No. Thermal/Magnetic Overcurrent Undervoltage Release (optional under 40kW) DC Shunt Trip (required over 40kW) w/battery ________ Capacitor Trip _______ Control Voltage (Not acceptable for use)

2.

Dedicated Transformer:

Yes No

Customer owned Bank Rating:

KVA Transformer

Transformer Connection:

Protected by: 3.

3φ Bank of 3-1φ

3-1φ

PG&E owned %

MVA Base

Primary Secondary

Fuse Size

Ground Protection Required:



volts volts Amps

Yes

Other No

If Yes, type of ground detection (check type): Ground Bank with overcurrent relay. Broken Delta Ground Bank with low pick up overvoltage relay. Ground Overcurrent relay in neutral or dedicated transformer. Low voltage pick up overvoltage relay in elevated neutral of dedicated transformer. Other

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Form G5-1 (Page 3 of 3) GENERATION PRE-PARALLEL INSPECTION PROTECTIVE DEVICES:

Zone 1 Distance

Standard Device Number 21Z1

Zone 2 Distance

21Z2

RELAY

Directional Phase O.C. Directional Ground O.C. Non-directional O.C. Ground or Neutral O.C.

Settings

Specific Breaker Tripped

Date of Function Test

67N 50/51 50/51N 59N

Overcurrent with voltage restraint

51V

Underfrequency

81U

Overfrequency

81O

Auto Synchronizing

Mfr and Model

67

Overvoltage Ground

Synchronizing

Required Yes/No

25 15/25

Undervoltage

27

Overvoltage

59

Transfer Trip From: Transfer Trip From: Reclose Block at: Reclose Block at: GENERATORS OPERATION: Verify operation of the generator(s) at 0.90 P.F. lag and at 0.95 P.F. lead while delivering rated output: PG&E (A). inspector initials (B). Verify operation of the generator(s) at 1.05 per unit voltage while delivering rated output: PG&E inspector initials

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PG&E Transmission Interconnection Handbook

Figure G5-1 SIMPLIFIED FLOW CHART OF PRE-PARALLEL / PARALLEL TEST PROCEDURE

SUBMIT RELAY TEST REPORTS (2 COPIES)

Two Weeks

PRE-PARALLEL TEST COMPLETE BY 6 PM

LETTER FOR RELEASE TO PARALLEL FOR TEST PURPOSES ONLY

WRITTEN PERMISSION FOR COMMERCIAL OPERATION

FIRM CAPACITY DEMONSTRATION TEST (IF APPLICABLE)

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Form G5-2 POWER GENERATION - HYDRO GENERATION VOLTAGE RESTRAINT OVERCURRENT RELAY LOAD CHECK FORM #74-961 Powerhouse Date Tested By:

Unit NO. Device NO. Gen. Nameplate Voltage Rating

LOAD CONDITIONS: AMPS VOLTS

MW

(IN)

PT Ratio Type

(OUT)

MVAR

(IN)

REFERENCE PHASE ANGLES USING GENERATOR A PHASE CURRENT: MAIN TRANSF. HIGH SIDE POTENTIAL: 5(4-0) 5(6-0) PHASE ANGLES: (SOURCE OF POTENTIAL IS) GENERATOR POTENTIAL TRANSFORMERS CONNECTED: SEC. AMPS

POTENTIAL Y OR  5(4-0) (4-8) 7(6-0) (6-4) 9(8-0) (8-6)

5(8-0)

OPEN 

WYE

READINGS TAKEN IN METERING BLOCKS Y OR  Y OR  5(4-0) (4-8) 5(4-0) (4-8) 5(6-0) (6-4) 7(4-0) (4-8) 5(8-0) (8-6) 9(4-0) (4-8)

MAIN TRANSFORMER BANK CONNECTED:

Y

Y T TRANSFORMER CONNECTED:

AB DELTA

Y

/AB DELTA

/AC DELTA

AC DELTA

/Y

PHASE ANGLES: (SOURCE OF POTENTIAL IS) SEC. AMPS 5(4-0) 7(6-0) 9(8-0)

CURENT

(OUT)

/Y

READINGS TAKEN AT RELAYS 5(4-0) 5(6-0) 5(8-0)

POTENTIAL

5(4-0) 7(4-0) 9(4-0)

CONTACTS: OPEN / CLOSING NORMAL ONE PHASE POTENTIAL POT'L REMOVED

Ø ANGLE

AØ RELAY BØ RELAY CØ RELAY NEUTRAL GROUNDING BANK

4

MAIN TRANSFORMER PCB

GEN PT

YT

6

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Section G6: SITING POLICY AND REQUIREMEENTS FOR TRANSMISSION GENERATION ENTITIES PURPOSE The following is PG&E's (Company) policy for siting wind turbine generation facilities near electric transmission easements. This policy and all requirements must be met for the Company to provide the Generation Entity with timely service. Any inspections required by local government agencies must be completed and permits signed off prior to the pre-parallel date. Failure to meet the succeeding requirements within the timeframes specified may result in a delay to successful operations to parallel to the Company’s system.

APPLICABILITY The policy and requirements of this section apply to all Generators interconnecting a wind turbine to any portion of the Company’s Transmission Power System. This policy has been developed by the Company to be consistent with applicable local (typically County) ordinances. In the future, the State or Federal Government may develop its own safety or siting standards. Refer to the Introduction of this handbook.

POLICY In order to protect Company property and for the safety of Company personnel working on equipment within Company right-of-way a “Safety Setback” shall be established.

G6.1. CRITERIA FOR NEW OR PROPOSED RE-POWERING PROJECTS G6.1.1. 60/70 kV, 115kV, 230kV & 500kV TRANSMISSION FACILITIES Except for Generator tap lines, a minimum safety setback from PG&E transmission lines of three times the total turbine height, with a blade in vertical position, from the edge of Company facility shall be maintained. If a greater safety setback is required by any local government authority, then the greater safety setback shall be observed.

G6.1.2. GENERATOR TAP LINES Protection equipment shall be installed, as required by Section G2 of this handbook, to isolate the tap line from the Company’s transmission circuit.

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Appendix A: WHERE TO OBTAIN REFERENCE DOCUMENTS AND INFORMATION Entity

Example Documents

Who To Contact

California Public Utilities Commission (CPUC)

Retail Tariffs Electric Rules

Energy Division California Public Utilities Commission 505 Van Ness Avenue San Francisco, CA 94102 Phone: (415) 703-1974 Toll-Free: (800) 848-5580

Federal Energy Regulatory Commission (FERC)

Code of Federal Regulation Orders

Federal Energy Regulatory Commission 888 First Street, NE Washington, DC 20426 Phone: (202) 502-6088 Toll-Free: (866) 208-3372

Independent System Operator (ISO)

ISOTariff ISO Standards ISO Protocols

Independent System Operator P.O. Box 639014 Folsom, CA 95673-9104 Phone: (916) 351-4400

North American Electric Reliability Council (NERC)

National Reliability Standards

North American Electric Reliability Council Princeton Forrestal Village, 116-390 Village Boulevard Princeton, New Jersey 08540-5731 Phone: (609) 452-8060

Pacific Gas and Electric (PG&E)

TO Tariffs Standards Electric Transmission Handbook

Pacific Gas and Electric Company 77 Beale St San Francisco CA 94177 Generation Entities: (415) 972-5676 Load Entities: (209) 726-6455

Western Electricity Coordinating Council (WECC)

Western Reliability Standards

Western Electricity Coordinating Council WECC - Salt Lake City 155 North 400 West, Suite 200 Salt Lake City, UT 84103 Phone: (801) 582-0353

Energy Division

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Appendix B: INSTALLATION REQUIREMENTS FOR TIME METERED INTERRUPTIBLE SERVICE THIS APPENDIX HAS BEEN INTENTIONALLY LEFT BLANK Refer to Appendix D for the following documents relevant to the title of this Appendix: “Installation Requirements for Time Metered Interruptible Service” PG&E Document Number 062143

Appendix C: METERING TRANSFORMER UNITS AND TYPICAL PRIMARY METERING INSTALLATIONS THIS APPENDIX HAS BEEN INTENTIONALLY LEFT BLANK Refer to Appendix D for the following documents relevant to the title of this Appendix: “Pole-Top Primary Metering Installation, Cluster Mounted (12 or 21 kV Line)” PG&E Document Number 058779 “Application of Primary CTS and Dual Winding PT/CT Metering Units for Interconnection to the Pacific Gas and Electric Company's System” PG&E Document Number G13079 “Electric Revenue High-Voltage Metering” PG&E Document Number 063436

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Appendix D: ENGINEERING NUMBERED DOCUMENTS Document Number

Document Title

034851

Steel Grating Type Switch Operating Platforms

055103

Planning Guide for Single Customer Substations Served from Transmission Lines

058779

Pole-Top Primary Metering Installation, Cluster Mounted (12 or 21 kV Line)

059659

Property Fences and Gates

060559

Disconnect Switches for Interconnection with Small Power Producers and Cogenerators

062143

Installation Requirements for Time Metered Interruptible Service

063436

Electric Revenue High-Voltage Metering

066195

25kV Underarm Side-Break Switch, Manual and Automated

067910

Grounding Requirements for Outdoor Electrical Substations

454092

Signs, Nameplates and Supports for Transmission and Distribution Substations

2004PGM-11

Technical Requirements for Electric Service Interconnection at Primary Distribution Voltages

G0104

Requirements for Transmission Line Selector Switches and Associated Cost Responsibilities

G13079

Application of Primary CTS and Dual Winding PT/CT Metering Units for Interconnection to the Pacific Gas and Electric Company's System

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Appendix E: SUBSTATION GROUNDING REQUIREMENTS THIS APPENDIX HAS BEEN INTENTIONALLY LEFT BLANK Refer to Appendix D for the following documents relevant to the title of this Appendix: “Steel Grating Type Switch Operating Platforms” PG&E Document Number 034851 “Grounding Requirements for Outdoor Electrical Substations” PG&E Document Number 067910 “Electric Revenue High-Voltage Metering” PG&E Document Number 063436

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Appendix F: TELEMETERING AND TRANSFER TRIP FOR TRANSMISSION GENERATION ENTITIES F.1. APPLICATIONS Before a new Generation Facility may be connected to the PG&E Power System, PG&E will specify the protection and telecommunications systems that will be required. These protection and telecommunications systems must be operational and satisfactorily commission-tested before parallel operation may begin. Due to the highly specialized and critical nature of transfer trip equipment, PG&E recommends that all such equipment be owned, installed and maintained as Special Facilities by PG&E, at the customer’s expense.

F.2. GENERAL REQUIREMENTS The Generation Entity is responsible for acquiring the communication medium (lines) for transmission of transfer trip signals, alarms/status points, and the telemetry data from the local telephone company, or multiple phone companies where applicable. Typical requirements are shown in Figure F-1. PG&E should be contacted to determine applicable transmission media. The types of circuits which may be required between the Generation Facility and PG&E’s facilities fall into the following categories:

F2.1. EMS/SCADA Telemetering Telemetering signals must be transmitted via telephone company leased circuits between the Generation Facility, PG&E’s Grid Control Center and the Designated PG&E Electric Control Center (as specified in Section G-1 of this handbook). A typical telemetry installation is shown in Figure F-1. The telemetering circuit, required to monitor the transfer trip protection circuit(s), is intended to ensure equipment operability and the continuity of the leased circuit from the telephone company. Alarms, including transfer trip channel fail, receive signals and generator breaker status must be transmitted to the Designated PG&E Electric Control Center using a leased circuit at the Generation Entity’s expense. Any maintenance support labor costs, incurred by PG&E personnel to assist in the restoration of the Generation Entity’s lease circuits (both EMS/SCADA and protection circuits) will be billed to the Generation Entity for reimbursement. If the generation is 100MW or more, the Generation Entity will be required to provide a second or alternate EMS/SCADA circuit to the Designated Electric Control Center. On a case by case basis, PG&E may approve of allowing the customer to lease a circuit to the nearest PG&E data node facility. PG&E would then route the alternate data on its infrastructure to the TOC.

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F2.1.1. Telemetering for New Generation Facilities 1,000 kW or Greater For Generating Facilities 1,000 kW or greater, the following real-time data must at a minimum be telemetered to PG&E’s Control Centers for each generating unit: •

kW



kVar



generator terminal voltage (kV)



customer substation breaker status



individual generating unit breaker status

A generator equipped with a voltage regulator and power system stabilizer (PSS) must also provide telemetering indicating their status. In addition, transmission kW, kVar, kV depending on the number of generating units and transmission configurations may be required. For protection circuits, a minimum number of alarms to be transmitted include the following: •

breaker trip,



transfer trip receive,



channel/equipment fail.

Telemetering equipment (usually a dual-ported RTU) shall be located in the metering enclosure. At the entity’s expense, PG&E may supply telemetering equipment at the Generation Entity’s site, at PG&E's Grid Control Center. The Generating Entity is responsible for procuring and maintaining all telecommunication circuits. For Load Entities that install generation 1000 KW or greater to off-set some or all of their load, such as those subject to CPUC Rule 21, telemetering will generally be required. However, the specific need for telemetering and associated requirements will be reviewed individually and will be based on the operational needs of the system. Telephone Company Line Treatment Equipment. [Remote Terminal Unit's (RTU) only] In some cases, the telephone company may install amplifiers or line treatment equipment. This equipment is operated by 110V AC power. It is recommended that an uninterruptible power supply (UPS) be provided and powered by a station DC battery. CPUC tariffs may prevent the local telephone company from using customer provided DC power for its termination equipment.

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F2.2. Protection PG&E will determine if non-pilot protective relays will be adequate for emergency tripping of the Generation Facility and PG&E’s station equipment, or if additional systems such as tele-protection assisted pilot wire (PW), current differential or phase comparison type protection equipment and systems are needed15. The Generation Entity, or its representative, is responsible for specifying the style to meet proper DC voltage, desired mounting configuration, and other substation pertinent hardware specifics. The Generation Entity is also responsible for coordinating and performing complete functional testing of the protective scheme including the end-to-end tests. End-to-end testing is associated with testing of the relay and associated communication between all terminals (protecting an interconnected line) as a system. Should PG&E be required to assist in future maintenance, the Generation Entity will arrange for design and installation of the equipment with necessary isolation and test switches in conformance to the PG&E standards. •

Pilot Wire. This type of system generally requires the installation of a special dedicated cable between the Generation Facility and the nearest major PG&E substation. Special consideration is required on the routing of the PG&E cable. It may not be built under the transmission or distribution line that carries the Generation Facility’s power. Special entrance cable specifications for this application are the same as those discussed in the next section.



Current differential and phase comparison. Current differentials or phase comparison line relays may be required for line protection16. The relay may be applied using tone (at 9600 bps) or digital communication17 medium.



Fiber Optics Cable (FOC). In the case of fiber optics cable, special consideration should be given to routing. It is recommended not to incorporate it as part of the same transmission line that carries the Generation Facility’s power. Special entrance cable specifications for this application are the same as those discussed in the next section.



The following considerations shall be applied where fiber optics cable is used for protection18: o PG&E will determine whether one level of high speed pilot protection is sufficient or redundant pilot protection is required for interconnection.

15

Pilot wire or any communication-assisted protective system must be end-to-end satellite tested (as a system) prior to release for commercial operation and as determined necessary by PG&E for the life cycle of the generation project. End-to-end tests and overall system tests are performed after satisfactory testing of individual devices, components, and trip and control circuits at each of the interconnected terminals prior to initial release for operation. However, there are occasions when PG&E will require the end-to-end tests to be repeated after the original tests are completed. 16 Refer to Table G2-1a. 17 Some systems may require a 64 kbs communication interface and communication link. 18 Refer to Appendix S and Section G-2 for additional information and regional reliability requirements.

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o Should one level of pilot protection be sufficient, the communication medium route must be separate, independent, and not subject to possible common mode unavailability as the transmission line which carries the Generation Facility’s power. o Should two levels of pilot protection be required, the communication medium route for one level of transmission line protection may be the same as the transmission line that carries the Generation Facility’s power. o Based on the types and the levels of protection and the required communications mediums, PG&E will determine whether independent channel or equipment are required for direct transfer trip. o PG&E recommends that the ordering information for current differential and phase comparison type relays between all the terminals of a transmission line be coordinated, particularly when the equipment for the remote terminal is procured by the Generating Facility or its representative. •

Power Line Carrier. Power line carrier protection may be possible in certain interconnection projects. This type of tele-protection is usually associated with distance based relay systems19. The Generating Facility is responsible for scheduled (route) maintenance of the carrier associated equipment including tuning of the wave trap and associated coupling devices, as necessary20.



Direct Transfer Trip. A direct transfer trip (DTT) system is the typical type of system installed for high-speed tripping of the Generation Facility’s station equipment. When a line fault occurs, the DTT equipment provides faster fault clearing and helps to isolate and protect the Generation Facility from damage. A typical system diagram is provided in Figure F-1. Elementary diagrams for the typical relay circuit configurations at the Generation Facility, with auto reset and lockout relay schemes, are provided in Figures F-2 and F-3, respectively. Because this type of circuit must be highly reliable, the following requirements must be met: o Uninterruptible Power Source. In order to ensure operation of the Transfer Trip (TT) circuit even during a fault situation, the TT transmitting and receiving equipment must be supplied with DC battery power from a separate circuit breaker. For a 125 Volt DC station, the DC source shall be equipped with a dedicated 15 amperes circuit breaker21. The station battery voltage must be decided upon before the TT equipment can be ordered.

19

The application must meet IEEE and PG&E recommended X/R ratios. Signal Amplifiers may also be required for proper transmission of signals. 21 The Generation Entity, or its representatives, are responsible for determining the proper size of the DC circuit breaker. 20

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o Class A Service Objective. The leased circuit must meet the Class “A” Service Objective (circuit will work before, during and after the fault). This also means that carbon block, gas tube, and/or solid state protectors that arc or short the Tip and Ring to ground for voltages of 300-350 volts will not be able to be used in the circuit. The telephone company must use Mutual Drainage Reactors (MDRs) at their Central Office (CO) or Remote Terminal (Remote CO). o Protection circuits such as TT require the use of a line termination unit, which is a passive data interface and has no loop-back capabilities. By requiring a C6 conditioned circuit22, the telephone company will provide the line amplifiers at their central office.

F2.3. Business Telephone A business telephone is required at the locations of TT, telemetering, alarm, and metering equipment, so that maintenance and repair work can be performed efficiently. The meters will be interrogated remotely using this same dedicated business telephone.

F2.4. Environmental Considerations. PG&E must review and approve the customer’s proposed equipment and room arrangement. See Figure F-4 for the typical room and conduit requirements for a small power plant. Deviations from PG&E's requirements must be approved by PG&E. •

Human Environment. Personnel cannot be expected to maintain and repair equipment that is located in an outdoor cabinet or in a small building, which would subject the personnel, or their test equipment to extremes in temperature and/or precipitation. In addition, 36 inches of working space must be provided in front and back of equipment that is powered by 0-600 volts. Aisles must be a minimum of 36” wide.



Equipment Environment. Extreme temperatures and/or excessive moisture can increase the deterioration of equipment components and wiring. Premature failure of vital protection and telemetering equipment could result in severe damage to expensive transformer banks and line conductors, as well as the loss of vital data required for efficient operation of PG&E’s Transmission Operating Center and the Designated PG&E Electric Control Center. Therefore, the following requirements shall be met: o All telemetering and transfer trip equipment should be installed in environmentally controlled buildings whenever possible. Temperature limits shall be from -30° to +60° C (0° to +50° C is preferred).

22

A circuit on which no active devices are placed that require AC power.

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o If an air-conditioned building is not feasible, other means of cooling should be used, such as thermostatically controlled exhaust fans, so that the temperature inside the equipment cabinets or chassis will not exceed the temperature rating specified by the manufacturer. Entrance louvers for venting must have an air filter that is periodically replaced. o Maintenance of equipment area. Typically, environmentally controlled buildings are cleaner and easier to keep clean. When emergency exhaust fans are used, an air filter shall be installed and maintained on a regular basis. It should be noted that any failures of vital equipment at the customer premise due to excessive dirt could severely damage station equipment. Labor and material costs for work performed to repair equipment so damaged will be billed to the Generation Entity.

F.3. INSTALLATION OF TELEPHONE COMPANY ENTRANCE CABLE IN SUBSTATIONS It is extremely important that the proper cable and protection equipment be installed at substations and other high-voltage electric facilities. The main determinant is the highest expected ground potential rise (GPR). The calculated GPR value will determine what grade of telephone cable high-voltage protection equipment is required as well as the minimum dielectric strength of the cable insulating jacket. The information required to determine the GPR is as follows: •

Highest calculated line-to-ground fault current and the X/R value. The responsible party shall provide the information.



Ground resistance (customer- provides information, after the station ground grid is installed).

The Generation Entity must also provide the station ground grid area. Based on the grid area and the GPR, the responsible party will determine the estimated distance from the grid, that the sheath of the entrance telephone cable must not be grounded. This is the distance where the GPR is expected to diminish to a magnitude of 300 volts (working limit). The working limit is the voltage at which gas tube protectors can be used (except for Class A service. The telephone company serving the area in which the Generation Facility is located should be contacted early (up to six months) so outside plant facilities can be engineered to serve the Generation Facility location. Failure to do this could result in the postponement of the Generation Facility’s operational date and additional cost, if the entrance facility is not installed properly or the wrong materials are used. For example, entrance conduits should be non-metallic. Detailed specifications will be provided by both PG&E and the local telephone company.

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F.4. CIRCUIT REQUIREMENTS FOR PROTECTIVE RELAYING AND EMS/SCADA CIRCUITS INSTALLED BETWEEN GENERATION FACILITY STATIONS AND PG&E POWER SUBSTATIONS The circuits requested shall be used for protective relaying purposes. This use requires that the telephone company service, including entrance circuits entering the terminal sites via the protective relaying circuit dedicated entrance cable, conform to the protection standards determined by the telephone company power and PG&E’s responsible engineer. Certain independent telephone companies are not tariffed to provide protection equipment for the required circuits. In such a case, the Generation Entity is responsible for the purchase of the necessary protection equipment. Even if the telephone company is tariffed to provide the protection equipment, the customer may decide to purchase their own high voltage equipment to save on monthly and installation charges. PG&E can provide the Generation Entity with the name of the telephone company that serves its site and assist in determining the appropriate protection equipment. It should be noted that the customer is responsible for the leased circuits or alternative communication media for circuits. If PG&E personnel are requested to perform work, and it is later determined that the cause of the problem is related to the telephone line, or other customer-owned equipment, PG&E will bill the customer for the labor and travel expenses. When the Generation Entity’s personnel are requesting EMS/SCADA telemetering, telephone, and/or transfer trip circuits from the telephone company, they should submit their request per the information provided on the forms included at the end of this section (Forms F5 through F9). PG&E will assist in determining the addresses for the PG&E facilities as well as confirm the circuit ordering specifications. The customer, when placing the service request, should inform the telephone company that the circuit will terminate in a high voltage location and if the circuit will terminate at other high voltage locations. Special high voltage protection requirements should be reviewed by the telephone company’s protection department. The time required for this type of service is typically a minimum of 3-4 months. Ground potential rise data (ground resistance and ground mat area) is required by the telephone company. The responsible party shall provide the maximum fault current value and the X/R value. The customer must determine if the high voltage protection equipment will be leased or owned. In the SBC service territory, the customer should contact its SBC account manager. In the service request, reference should be made to the “METPRO” for high voltage protection. If the customer does not know who the account manager is, then the customer should call (800) 750-2355 to obtain that information.

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Form F-5 ORDER REQUEST FORM EMS/SCADA TELEMETERING TO SF TOC TELEPHONE LEASE DESCRIPTION: CIRCUIT:

Data Quality

PURPOSE:

Electric Generation Telemetry to PG&E’s Transmission Operations Center (TOC) in San Francisco

SPECIFICATION:

Class B Service Objective, Type 3, VG36,-4 wire Full Duplex, Data Circuit, 1200 Baud,with Sealing Current

HIGH VOLTAGE PROTECTION EQUIPMENT OWNERSHIP: A. EXISTING SVC: CUSTOMER OWNED ______(YES/NO), TELEP. CO. OWNED ________ (YES/NO); B. NEW SERVICE: CUSTOMER OWNED ______ (YES/NO), TELEP. CO. OWNED ________ (YES/NO) CUSTOMER’S NAME: _______________________________________________________________ SITE CONTACT NAME: _______________________________ TELEPHONE: __________________ ADDRESS: _________________________________________________________ _________________________________________________________ _______________________________ ZIP CODE _____________ TELEPHONE NUMBER: TERMINAL ADDRESS:

__(___)__________________________________________________ (1) CUSTOMER SUB: ______________________________ ______________________________ ______________________________ (2) PG&E TOC:

PG&E 245 Market St., Rm B117 San Francisco, CA 94105

(3) PG&E Line Name: _____________________________ ______________________________ ______________________________

PG&E CONTACT:

Field Support (415) 973-2275

SPECIAL CONSIDERATIONS: 1. The customer, when placing the service request, should inform the telephone company that the circuit will terminate in a high voltage location and if the circuit will terminate in other high voltage locations. Special high voltage protection requirements should be reviewed by the telephone company’s Protection Department. Ground potential rise data (ground resistance and ground mat area) is required by the telephone company. The Responsible Party shall provide the maximum fault current value and the X/R value. The customer must determine if the high voltage protection equipment will be leased or owned. The time required for this type of service is 1-2 months. 2. This leased circuit may be terminated at the California- ISO in the future. 3. Class B Service Objective means that the circuit will operate before and after a line to ground fault.

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Form F-6 ORDER REQUEST FORM

EMS/SCADA TELEMETERING TELEPHONE LEASE TO DESIGNATED ELECTRIC CONTROL CENTER DESCRIPTION: CIRCUIT:

Data Quality

PURPOSE:

EMS/SCADA to Local Electric Control Center Operations (ECCO) Office

SPECIFICATION:

Class B Service Objective, Type 3, VG 36 4-wire, Full Duplex, Data Circuit, 1200 Baud, With Sealing Current

HIGH VOLTAGE PROTECTION EQUIPMENT OWNERSHIP: A. EXISTING SVC: CUSTOMER OWNED ______(YES/NO), TELEP. CO. OWNED ________ (YES/NO); B. NEW SERVICE: CUSTOMER OWNED ______ (YES/NO), TELEP. CO. OWNED ________ (YES/NO) CUSTOMER’S NAME: _______________________________________________________________ SITE CONTACT NAME: _______________________________ TELEPHONE: __________________ ADDRESS:

_________________________________________________________ _________________________________________________________ _______________________________ ZIP CODE _____________

TELEPHONE NUMBER: __(___)______________________________________________________ TERMINAL ADDRESS: (1) CUSTOMER SUB: ______________________________ ______________________________ ______________________________ (2) PG&E Sub:

PG&E CONTACTS:

_______________________________ ______________________________ ______________________________

(3) PG&E Line Name: _____________________________ ______________________________ ______________________________ Engineer: Name ________________ Telephone. ________________ Site Contact: Name ________________ Telephone ________________

SPECIAL CONSIDERATIONS: 1. The customer, when placing the service request, should inform the telephone company that the circuit will terminate in a high voltage location and if the circuit will terminate in other high voltage locations. Special high voltage protection requirements should be reviewed by the telephone company’s Protection Department. The time required for this type of service is 1-2 months. Ground potential rise data (ground resistance and ground mat area) is required by the telephone company. The Responsible Party shall provide the maximum fault current value and the X/R value. The customer must determine if the high voltage protection equipment will be leased or owned. 2. The circuit shall be supplied with a firm uninterruptible power source. 3. Class B Service Objective means that the circuit will operate before and after a line to ground fault.

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Form F-7 ORDER REQUEST FORM BUSINESS TELEPHONE SERVICE DESCRIPTION: CIRCUIT:

Business Telephone Service

SPECIFICATION:

Class B Service Objective, Type 1 (1 MB)

HIGH VOLTAGE PROTECTION EQUIPMENT OWNERSHIP: A. EXISTING SVC: CUSTOMER OWNED ______(YES/NO), TELEP. CO. OWNED ________ (YES/NO); B. NEW SERVICE: CUSTOMER OWNED ______ (YES/NO), TELEP. CO. OWNED ________ (YES/NO)

CUSTOMER’S NAME: _________________________________________________________ SITE CONTACT NAME: _______________________________ TELEPHONE: __________________ ADDRESS:

_________________________________________________________ _________________________________________________________ _______________________________

TELEPHONE NUMBER:

(

ZIP CODE

_____________

)

TERMINAL ADDRESS: _________________________________________________________ _________________________________________________________ _________________________________________________________

SPECIAL CONSIDERATIONS: 1. The customer, when placing the service request, should inform the telephone company that the circuit will terminate in a high voltage location and if the circuit will terminate in other high voltage locations. Special high voltage protection requirements should be reviewed by the telephone company’s Protection Department. The time required for this type of service is 1-2 months. Ground potential rise data (ground resistance and ground mat area) is required by the telephone company. The Responsible Party shall provide the maximum fault current value and the X/R value. The customer must determine if the high voltage protection equipment will be leased or owned. 2. MB means Measured Business type of service. 3. Class B Service Objective means that the circuit will operate before and after a line to ground fault.

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Form F-8 ORDER REQUEST FORM TRANSFER TRIP ANALOG TELEPHONE LEASE DESCRIPTION: CIRCUIT:

Voice Grade

PURPOSE:

Transfer Trip Protective Relaying

SPECIFICATION:

Class A Service Objective, Type 4, VG36 C6 Conditioning, 4-wire, Full Duplex, With Sealing Current

HIGH VOLTAGE PROTECTION EQUIPMENT OWNERSHIP: A. EXISTING SVC: CUSTOMER OWNED ______(YES/NO), TELEP. CO. OWNED ________ (YES/NO); B. NEW SERVICE: CUSTOMER OWNED ______ (YES/NO), TELEP. CO. OWNED ________ (YES/NO) CUSTOMER’S NAME: ____________________________________ SITE CONTACT NAME: _______________________________ TELEPHONE: __________________ ADDRESS: _________________________________________________________ _________________________________________________________ _______________________________ ZIP CODE _____________ TELEPHONE NUMBER: TERMINAL ADDRESS:

__(___)__________________________________________________ (1) CUSTOMER SUB: ______________________________ ______________________________ ______________________________ (2) PG&E Sub:

PG&E CONTACTS:

_______________________________ ______________________________ ______________________________

(3) PG&E Line Name: _____________________________ ______________________________ ______________________________ Engineer: Name ________________ Telephone. ________________ Site Contact: Name ________________ Telephone ________________

SPECIAL CONSIDERATIONS: 1. Class “A” Service Objective means that the circuit will work before, during and after a power line to ground fault. This also means that carbon block, gas tube, and/or solid state protectors that arc or short the Tip and Ring to ground voltages of 300-350 volts will not be able to be used in the circuit. The telephone company must use Mutual Drainage Reactors (MDRs) at their Central Office (CO) or Remote Terminal (Remote CO). 2. C6 Conditioning means that no active devices (none AC powered) such as amplifiers or other network connecting termination equipment (NCTE) are installed at the cable termination point. 3. Documentation must be submitted by the Generation Entity that the telephone company has stated that they have complied with all of the specifications for the protection leased circuit. 4. The customer, when placing the service request, should inform the telephone company that the circuit will terminate in a high voltage location and if the circuit will terminate in other high voltage

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locations. Special high voltage protection requirements should be reviewed by the telephone company’s Protection Department. The time required for this type of service is 3-4 months. Ground potential rise data (ground resistance and ground mat area) is required by the telephone company. The Responsible Party shall provide the maximum fault current value and the X/R value. The customer must determine if the high voltage protection equipment will be leased or owned. 5. The circuit shall be supplied with a firm uninterruptible power source.

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Form F-9 ORDER REQUEST FORM TRANSFER TRIP DIGITAL TELEPHONE LEASE DESCRIPTION: CIRCUIT:

Digital Grade

PURPOSE:

Transfer Trip Protective Relaying

SPECIFICATION:

Class A Service Objective, Type 4, 56 Kbps ADN circuit, With Sealing Current

HIGH VOLTAGE PROTECTION EQUIPMENT OWNERSHIP: A. EXISTING SVC: CUSTOMER OWNED ______(YES/NO), TELEP. CO. OWNED ________ (YES/NO); B. NEW SERVICE: CUSTOMER OWNED ______ (YES/NO), TELEP. CO. OWNED ________ (YES/NO) CUSTOMER’S NAME: ____________________________________ SITE CONTACT NAME: _______________________________ TELEPHONE: __________________ ADDRESS: _________________________________________________________ _________________________________________________________ _______________________________ ZIP CODE _____________ TELEPHONE NUMBER: TERMINAL ADDRESS:

__(___)__________________________________________________ (1) CUSTOMER SUB: ______________________________ ______________________________ ______________________________ (3) PG&E Sub:

_______________________________ ______________________________ ______________________________

(4) PG&E Line Name: _____________________________ ______________________________ ______________________________ PG&E CONTACTS:

Engineer: Name ________________ Telephone. ________________ Site Contact: Name ________________ Telephone ________________

SPECIAL CONSIDERATIONS: 1. Class “A” Service Objective means that the circuit will work before, during, and after a power line to ground fault. This also means that carbon block, gas tube, and/or solid state protectors that arc or short the Tip and Ring to ground for voltages of 300-350 volts will not be able to be used in the circuit. The telephone company must use Mutual Drainage Reactors (MDRs) at their Central Office (CO) or Remote Terminal (Remote CO) 2. The customer, when placing the service request, should inform the telephone company that the circuit will terminate in a high voltage location and if the circuit will terminate in other high voltage locations. Special high voltage protection requirements should be reviewed by the telephone company’s Protection Department. The time required for this type of service is 3-4 months. Ground potential rise data (ground resistance and ground mat area) is required by the telephone company. The Responsible Party shall provide the maximum fault current value and the X/R

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value. The customer must determine if the high voltage protection equipment will be leased or owned. 3. The circuit shall be supplied with a firm uninterruptible power source. 4. Documentation must be submitted by the Generation Entity that the telephone company has stated that they have complied with all of the specifications for the protection leased circuit.

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Appendix G: DISCONNECT DEVICES THIS APPENDIX HAS BEEN INTENTIONALLY LEFT BLANK Refer to Appendix D for the following documents relevant to the title of this Appendix: “Disconnect Switches for Interconnection with Small Power Producers and Cogenerators” PG&E Document Number 060559 “Steel Grating Type Switch Operating Platforms” PG&E Document Number 034851 “25kV Underarm Side-Break Switch, Manual and Automated” PG&E Document Number 066195 “Signs, Nameplates and Supports for Transmission and Distribution Substations” PG&E Document Number 454092

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Appendix H: POWER SYSTEM STABILIZER The Western Electricity Coordinating Council (WECC) has developed many documents applicable to Power System Stabilizer (PSS) requirements, including: •

WECC Power System Stabilizer Tuning Guidelines



WECC Power System Stabilizer Design and Performance Criteria

For more information, visit the WECC website.

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Appendix I: LOAD OPERATING AGREEMENT Purpose The following agreement establishes operating responsibilities and associated procedures for communications between a Load Entity and PG&E. In addition, the agreement obligates the Load Entity to operate its facility in a safe and prudent manner and establishes procedures for safe work practices on electric systems. This agreement shall be executed by PG&E and the Load Entity prior to interconnecting facilities and commencing any parallel operation.

Applicability All the requirements of this agreement apply to all loads connected to PG&E’selectric system. The PG&E agreement may not include certain provisions, such as energy reporting, or other provisions of the ISO, and will be covered under separate agreements between these entities and the Load Entity. Attachment: Electric Sample Form 79-847, “Transmission Load Operating Agreement”

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Appendix J: SPECIAL AGREEMENT FOR ELECTRICAL STANDBY SERVICE REFER TO APPENDIX L FOR “GENERATION INTERCONNECTION AGREEMENTS”

Purpose The following agreement establishes the service request for electrical Standby service between a Generator or other Non-regular Load customer and PG&E. In addition, the agreement establishes the options for service, exemptions, and sets the Reservation Capacity and service parameters. This agreement shall be executed by PG&E and the Generator or Non-regular Load customer prior to interconnecting generation facilities and commencing parallel operation, or connection of non-regular load.

Applicability All the requirements of this agreement apply to all Generators and Non-regular Load customers connected to PG&E’s electric system, unless exempted.

Relevant Documents ATTACHMENT 1: Special Agreement for Electrical Standby Service (Form 79-285) 23 ATTACHMENT 2: Reactive Demand Exemption Form for Synchronous Generators with AVR Control (Form 79-1110) 24 ATTACHMENT 3: Standby Data Sheet ( Form 79-843) -- refer to next page ATTACHMENT 4: Electric Schedule S – Standby Service 25

23

http://www.pge.com/tariffs/tm2/pdf/ELEC_FORMS_79-285.pdf http://www.pge.com/tariffs/tm2/pdf/ELEC_FORMS_79-1110.pdf 25 http://www.pge.com/tariffs/tm2/pdf/ELEC_SCHEDS_S.pdf 24

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Appendix K: LOAD SPECIAL FACILITIES AGREEMENT This Appendix contains an example of the CPUC Special Facilities Agreement for Load Entities. FERC jurisdictional Special Facilities Agreements are unique to each project but follow similar principles.

This contract shall at all times be subject to such changes or modification by the Public Utilities Commission of the State of California as said Commission may, from time to time, direct in the exercise of its jurisdiction. As such, applicant must request the most recent copy of this agreement from any PG&E office.

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Division Applicant Customer Operations Plant Accounting Customer Billing

Reference:

Pacific Gas And Electric Company AGREEMENT FOR INSTALLATION OR ALLOCATION OF SPECIAL FACILITIES At the request of _______________________________________________________________ (Applicant), PACIFIC GAS AND ELECTRIC COMPANY (PG&E) hereby agrees, as an accommodation, to install at the Applicant's expense within a reasonable time, or allocate for Applicant's use at ______________________________ _____________________________________________________________________________________________ ___________State of California, certain facilities consisting of ___________________________________________ _____________________________________________________________________________________________ ________________________________________________(Special Facilities), at an estimated total additional installed cost of $ _______ over and above the cost of standard facilities which PG&E would normally provide or allocate for regular service in accordance with its tariffs on file with and authorized by the California Public Utilities Commission (Commission), subject to the following terms and conditions: 1.

Applicant shall pay to PG&E, on demand and in advance of construction by PG&E, the initial sum of:

(a) $ ______ (Advance) which consists of a credit of $ ______ for that portion of the facilities provided by and conveyed to PG&E by the Applicant, and Applicant's payment of $ ______ representing PG&E's additional costs for Special Facilities; plus, (b) $ ______ (Rearrangement) a non refundable amount representing PG&E's cost of rearranging existing facilities to accommodate the installation of the Special Facilities. 2. Applicant shall also pay to PG&E, in addition to the monthly rates and charges for service, at the option of PG&E, either: (a) A monthly charge for the Special Facilities of $ ______ (Cost of Ownership Charge) representing the continuing ownership costs of the Special Facilities (_____% per month) as determined in accordance with the applicable percentage rate established in the Special Facilities section of PG&E's applicable Gas or Electric Rule No. 2, copy attached; or, (b) $ ______ (Equivalent One-Time Payment) which is the present worth of the monthly ownership costs ( %) for the Special Facilities in perpetuity. Refunds and adjustments, if any, of the Advance and Equivalent One-Time Payment will be made in accordance with paragraph 13. Interest at the rate of _____% annually will be added to the unamortized balance of the Equivalent One-Time Payment on each anniversary of the date the Special Facilities are first made available, as such date is established in PG&E's records, before the current year's Cost of Ownership Charges are deducted. The monthly Cost of Ownership Charge shall commence on the date the Special Facilities are first available for Applicant's use, as such date is established in PG&E's records. PG&E will notify Applicant, in writing, of such commencement date. 3. The annual ownership cost used to determine the Equivalent One-Time Payment or used to determine the monthly charges in paragraph 2 above shall automatically increase or decrease without formal amendment to this agreement if the Commission should subsequently authorize a higher or lower percentage rate for monthly costs of ownership for Special Facilities as stated in Rule No. 2, effective with the date of such authorization. Thereafter, such revised annual ownership cost shall also be used to determine the unamortized balance of the Equivalent One-Time Payment, as provided in paragraph 13.(a). 4.

Where it is necessary to install Special Facilities on Applicant's premises, Applicant hereby grants to PG&E:

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(a) the right to make such installation on Applicant's premises along the shortest practical route thereon and of sufficient width to provide legal clearance from all structures now or hereafter erected on Applicant's premises for any facilities of PG&E; and, (b) the right of ingress to and egress from Applicant's premises at all reasonable hours for any purposes reasonably connected with the operation and maintenance of the Special Facilities. 5. Where formal rights of way or easements are required on and over Applicant's property or the property of others for the installation of the Special Facilities, Applicant understands and agrees that PG&E shall not be obligated to install the Special Facilities unless and until any necessary permanent rights of way or easements, satisfactory to PG&E, are granted without cost to PG&E. 6. PG&E shall not be responsible for any delay in completion of the installation of the Special Facilities resulting from shortage of labor or materials, strike, labor disturbance, war, riot, weather conditions, governmental rule, regulation or order, including orders or judgments of any court or Commission, delay in obtaining necessary rights of way and easements, act of God, or any other cause or condition beyond the control of PG&E. PG&E shall have the right, in the event it is unable to obtain materials or labor for all of its construction requirements, to allocate materials and labor to construction projects which it deems, in its sole discretion, most important to serve the needs of its customers, and any delay in construction hereunder resulting from such allocation shall be deemed to be a cause beyond PG&E's control. 7. In the event that PG&E is prevented from completing the installation of the Special Facilities for reasons beyond its control within twelve (12) months following the date of this Agreement, PG&E shall have the right to terminate this Agreement upon thirty (30) days' written notice to Applicant. 8. If this Agreement is terminated as set forth in paragraph 7, the provisions of paragraph 13 shall be applicable, based on that portion of the Special Facilities then completed, if any, including charges for any expense incurred by PG&E for any engineering, surveying, right of way acquisition expenses and other associated expenses incurred by PG&E for that portion of the Special Facilities not installed or, in PG&E's sole judgment, not useful in supplying permanent service to PG&E's other customers. 9. Special Facilities provided by PG&E hereunder shall at all times be provided by PG&E hereunder shall at all times be and remain the property of PG&E. 10. As provided in PG&E's applicable Electric Rule 14 or Gas Rules not guarantee electric or gas service to be free from outages, interruptions or curtailments and that the charges for the Special Facilities represent the additional cost associated with providing the Special Facilities rather than for a guaranteed level of service or reliability. 11. If it becomes necessary for PG&E to alter or rearrange the Special Facilities, including, but not limited to the conversion of overhead facilities to underground, Applicant shall be notified of such necessity and shall be given the option to either terminate this Agreement in accordance with paragraphs 12 and 13, or to pay PG&E additional Special Facilities consisting of: (a) A facility termination charge for that portion of the Special Facilities which is being removed because of alteration or rearrangement. Such charge to be determined in the same manner as described in paragraph 13; plus, (b) An additional Advance and/or rearrangement costs, if any, for any new Special Facilities requested which shall be determined in the same manner as described in paragraph 1; plus, (c) A revised Equivalent One-Time Payment or monthly charge based on the total net estimated additional installed costs of all new and remaining Special Facilities. Such revised Equivalent One-Time Payment or monthly charge shall be determined in the same manner as described in paragraphs 2 and 3. 12. This Agreement shall be effective when executed by the parties hereto and shall remain in effect until terminated by either party on at least thirty (30) days' advance written notice. 13. Upon discontinuance of the use of any Special Facilities due to termination of service, termination of this Agreement, or otherwise: (a) Applicant shall pay to PG&E on demand (in addition to all other monies to which PG&E may be legally entitled by virtue of such termination) a facility termination charge defined as the estimated installed cost, plus the estimated removal cost, less the estimated salvage value for the Special Facilities to be removed, as determined by

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PG&E in accordance with its standard accounting practices. PG&E shall deduct from the facility termination charge the Advance plus the unamortized balance of the Equivalent One-Time Payment previously paid, if any. If the Advance paid plus the unamortized balance of the Equivalent One-Time Payment is greater than the facility termination charge, PG&E shall refund the difference, without interest, to the Applicant; (b) PG&E shall be entitled to remove and shall have a reasonable time in which to remove any portion of the Special Facilities located on the Applicant's premises; (c) PG&E may, at its option, alter, rearrange, convey or retain in place any portion of the Special Facilities located on other property off Applicant's premises. Where all or any portion of the Special Facilities located off Applicant's premises are retained in place and used by PG&E to provide permanent service to other customers, an equitable adjustment will be made in the facility termination charge. 14. Applicant may, with PG&E's written consent, assign this Agreement if the assignee thereof will agree in writing to perform Applicant's obligations hereunder. Such assignment will be deemed to include, unless otherwise specified therein, all of Applicant's rights to any refunds which might become due upon discontinuance of the use of any Special Facilities. 15. This agreement shall be subject to all of PG&E's applicable tariffs on file with and authorized by the Commission and shall at all times be subject to such changes or modifications as the Commission may direct from time to time in the exercise of its jurisdiction.

Dated this _____ day of __________, 20____.

_______________________________________ _______________________________________ Applicant

PACIFIC GAS AND ELECTRIC COMPANY

BY:____________________________________

BY:____________________________________

TITLE:

Manager,

MAILING ADDRESS: _______________________________________ _______________________________________ _______________________________________

Attachments:

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Appendix L: INTERCONNECTION AGREEMENTS FOR GENERATORS CONNECTING TO THE ISO CONTROLLED GRID Purpose and Applicability The interconnection agreements on the follow attachments are governed by the CAISO Tariff Standard Large Generator Interconnection Procedures (LGIP) Appendix U, Large Generator Interconnection Procedures (LGIP) for Interconnection Requests in a Queue Cluster Window Appendix Y and the Small Generator Interconnection Procedures (SGIP) Appendix AA. The agreements, as applicable, shall apply to: (a) Each new generating unit that seeks to interconnect to the ISO Controlled Grid; (b) Each existing generating unit connected to the ISO Controlled Grid that will be modified with a resulting increase in the total capability of the power plant; (c) Each existing generating unit connected to the ISO Controlled Grid that will be modified without increasing the total capability of the power plant but has changed the electrical characteristics of the power plant such that its re-energization may violate Applicable Reliability Criteria; and (d) Each existing qualifying facility generating unit connected to the ISO Controlled Grid whose total generation was previously sold to PG&E or an on-site customer but whose generation, or any portion thereof, will now be sold in the wholesale market.

Relevant Documents ATTACHMENT 1: Serial Large Generator Interconnection Agreement (LGIA) ATTACHMENT 2: Cluster Large Generator Interconnection Agreement (LGIA) ATTACHMENT 3: Small Generator Interconnection Agreement (SGIA) ATTACHMENT 4: CAISO Affidavit

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Appendix M: GENERATION INTERCONNECTION DATA SHEET 1.

PROJECT NAME: ________________________________ 2. PROJECT NUMBER: STREET ADDRESS: _______________________________ PHONE: ( ____ ) _____ - ________ CITY: ____________________________________ STATE : ________ ZIP CODE: __________

3.

CONTRACTUAL NAME: _______________________________________________________________ STREET ADDRESS: _______________________________ PHONE: ( ____ ) _____ - ________ CITY: _____________________________________ STATE: ________ ZIP CODE: __________

4. DEVELOPER NAME: _________________________________________________________________ STREET ADDRESS: _______________________________ PHONE: ( ____ ) _____ - ________ CITY: _____________________________________ STATE: ________ ZIP CODE: __________

5. SITE OWNER NAME: ________________________________________________________________ STREET ADDRESS: ________________________________ PHONE: ( ____ ) _____ - ________ CITY: _____________________________________ STATE: ________ ZIP CODE: __________

6. TYPE OF PROJECT: _________ Cogeneration _________ Small Power Producer _________ Biomass

_________ Hydro _________ Photovoltaic _________ Recip. Engine

_________ Steam Turbine _________ Wind

_________ Gas Turbine _________________________________

_________ Other:

7. TYPE OF CONTRACT BEING CONSIDERED: S.O.1 _________

S.O.3 ___________

_________ Surplus Energy Output No Sale With Parallel Agreement _________ Small Power Output _________ kW _________ Will Negotiate For _________ kW of Contract Capacity

8. WILL THERE BE REDUCED GENERATOR OUTPUT? IF YES, _________kW

_______ YES

________ NO

FROM ________ TO ________

9. a. EXISTING PG&E PREMISES AND ACCOUNT NUMBERS INTERCONNECTED: PREMISES ____________________ ____________________ ____________________ ____________________

ACCOUNT: _________ - ________ - ________ _________ - ________ - ________ _________ - ________ - ________ _________ - ________ - ________

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10.

MAXIMUM GENERATOR POWER DELIVERED TO PG&E AT INTERCONNECTION POINT: a. b. c. d. e.

Generator rated output: Less generator auxiliary load: Maximum power delivered to PG&E: Load to be served when generator is OFF: Existing load being displaced by this generator:

Rated Output kW + ____________ Auxiliaries kW - ____________ Max Delivered kW = ____________ Load kW ____________ kW ____________

11.

THE ANTICIPATED OPERATION DATE: ________________________________________________

12.

DO YOU PLAN ANY OTHER POWER GENERATION AT THIS SITE?

13.

GENERATOR a. Size:

kW: ______

KVA: ______

b. Type:

Induction: _____

Synchronous: _____ D.C. with Inverter: _______

c.

*

14.

_____ YES _____ NO

Synchronizing:

Auto _____ Manual _____

Voltage:

Output ________

d. Phase:

1φ __________

e. Connection:

Delta ________

f.

Power Factor (%): _______

Relay Supervision: Yes _____ No _____

Interconnection ______ 3φ __________ Grounded WYE ______

Ungrounded ______

2

Inertia Constant: _______________ lb-ft (when available)

PROVIDE PROPOSED GENERATOR OPERATING SCHEDULE (Total kWhrs): ________ January ________ February ________ March ________ April

________ May ________ June ________ July ________ August

________ September ________ October ________ November ________ December

PROVIDE PROPOSED AVERAGE PRODUCTION kWhrs AS REQUESTED: Daily: __________ kWh

Monthly: __________ kWh

Yearly: __________ kWh

Schedule Maintenance Shutdown: 15.

ELECTRIC METERING IS TO BE: Voltage _____

16.

GAS REQUIREMENTS: Operations:

Primary __________

Pole Top _____

Secondary __________

Switchboard _____ Customer Owned Sup. _______

Volume: _____ MCFH Daily Hours: __________

Pressure: _________ PSIG Days Per Week: __________

Scheduled Shutdowns: ______________________________________________________________ 17.

GENERATOR VOLTAGE REGULATION RANGE: _________________________________________ GENERATOR POWER FACTOR REGULATION RANGE: ___________________________________

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GENERATOR SHORT CIRCUIT DATA (Final transformer and generator data must be based on actual test results for the particular transformer and generator. Typical values, calculated values or type testing are acceptable only if guaranteed in writing by manufacturer to be within +/- 3% accuracy): Synchronous Transient Subtransient Negative Sequence Zero Sequence

18.

(Xd) (Xd) (Xd) (X2) (X0)

________ % ________ % ________ % ________ % ________ %

@ ________ MVA @ ________ MVA @ ________ MVA @ ________ MVA @ ________ MVA

N/A (T’d) ______ SEC (T’d) ______ SEC N/A N/A

OUTPUT: If the generator output is greater than 40kW (individually or as an aggregate group), ground protection will be required. If grounding will be required, please indicate type of ground detection below: _________ WYE GROUNDED/DELTA GROUND BANK WITH OVERCURRENT RELAY *WYE GROUNDED/BROKEN DELTA: Ground Bank with Low Pick-up Overvoltage Relay _________ * Preferred CURRENT TRANSFORMER WITH OVERCURRENT RELAY: In Neutral of Dedicated _________ Transformer *POTENTIAL TRANSFORMER WITH VOLTAGE RELAY: In Neutral of Dedicated _________ * Preferred Transformer _________ OTHER: ________________________________________________________________

19.

WHO WILL SUPPLY TRANSFORMER:

Customer: _____

IF CUSTOMER SUPPLIED:

Primary Voltage: _____ Secondary Voltage: _____

PG&E: _______ Size: _________ KVA Z _____ % Impedance

(Final transformer and generator data must be based on actual test results for the particular transformer and generator. Typical values, calculated values or type testing are acceptable only if guaranteed in writing by manufacturer to be within +/- 3% accuracy):

Available Taps: _____________________________________________________________________ Transformer Fuse: 20.

Type: __________ Size __________

WHAT TRANSFORMER CONNECTION IS DESIRED: Delta

Grounded Wye

PG&E Side

_______

_________

________

Generator Side

_______

_________

________

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21.

PROVIDE: Two original prints and one reproducible copy (no larger than 36” x 24”) of the following: a. SITE DRAWING to scale, showing generator location and point of interconnection with PG&E. b. SINGLE LINE DIAGRAM, showing switches/disconnects of the proposed interconnection, including the required protection devices and breakers. c. THREE LINE DIAGRAM, showing the proposed CTs and PTs as they are connected to the relays and meters. d. DESCRIPTION of operation and elementary drawings, showing the synchronization (if appropriate), sand tripping of breakers by the required relays are desirable. (If not provided, they may be requested after approval of the single and three line diagrams.)

22.

BREAKER(s) EQUIPPED WITH: Undervoltage Release: ________

23.

Capacitor Trip: ________ *(Not acceptable for use)

D.C. Trip: ________

DO YOU WISH RECLOSE BLOCKING FOR INDUCTION GENERATORS? Yes No We test automatically. Sufficient capacitance may be on the line now, or in the future, and your generator may self-excite unexpectedly.

24.

PROVIDE a list of relays, switches and revenue meters (if customer provided), disconnects, etc., specified to meet PG&E requirements. Please include the following information: a. Manufacturer’s name and model number, with each device listed. b. Range of available settings. c.

Proposed settings.

d. Ratio of associated current and potential transformers. If multi-ratio, state the available ratios and which one is proposed.

25. **

RELAYS REQUIRED: See Power Producer’s Interconnection Handbook, Section 3. 26. For generation greater than 1000 kW provide the following: a. Substation grounding drawings showing all ground connections. b. A list of the amount and location of the shunt capacitor compensation that will be provided (induction generators only).

NOTE: Generation customers are required to pay all costs to connect their projects to the PG&E system. Final estimated costs will have an accuracy of +10%. Unless otherwise requested, PG&E’s study will include reinforcements, modifications, and additions to PG&E’s electrical and/or gas system. It will not include on-site transformers, switchgear, or any other project substation facilities owned by the developer. PG&E’s requirements are summarized in greater detail in Electric Rule 21. Completed By: _____________________________

Date: __________________

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Appendix N: GENERATOR DATA SHEET FOR SYNCHRONOUS GENERATORS CONNECTED TO PG&E ELECTRIC SYSTEM TECHNICAL DATA SHEET FOR SYNCHRONOUS MACHINES IN THE PG&E SYSTEM FOR POWER FLOW, TRANSIENT STABILITY, AND FAULT ANALYSIS Revision 5/95 Note 1: If you have more than 1 generator that normally operates interconnected with PG&E’s system, please complete a separate data sheet for each generator. Note 2: This data sheet is for synchronous machines only, not induction machines Questions? Please Contact: Manager, Transmission Planning Department Pacific Gas and Electric Company P.O. Box 770000 – Mail Code Z6A San Francisco, CA 94177 Transmission Planning Department (415) 973-7611

Unit Number Project Name

Name of Person Completing Data Sheet

Telephone Number

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Log Number

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Generator Data (Final transformer and generator data must be based on actual test results for the particular transformer and generator. Typical values, calculated values or type testing are acceptable only if guaranteed in writing by manufacturer to be within +/- 3% accuracy): 1.

Generator Manufacturer

____________

2.

Year Generator was Manufactured

____________

3.

Rated Generator MVA

____________

MVA

4.

Rated Generator Terminal Voltage

____________

kV

5.

Rated Generator speed

____________

rpm

6.

Number of Poles

____________

7.

Rated Generator Power Factor

____________

8.

Generator Efficiency at Rated Load

____________

%

9.

Moment of Inertia (Turbine plus Generator)

ωR2

____________

lb-ft2

10.

Inertia Time Constant (on machine base):

H:

____________

sec or MJ/MVA

11.

SCR (Short-Circuit Ratio - the ratio of the field current required for rated open-circuit voltage to the field current required for rated short-circuit current.

____________

12.

Typical Generator Auxiliary Load

____________

MW

13.

Maximum Power Output

____________

MW

14.

Please attach generator reactive capability curves. If these curves are not available, provide the max and min reactive limits

QMAX:

____________

MVAR, lagging

QMIN:

____________

MVAR, leading

____________

psig

15.

Rated Hydrogen Cooling Pressure (Steam Units only)

16.

Please attach a simple one-line diagram that includes the generator step-up transformer bank, plant load, meter, and transmission-level bus.

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Generator Data (continued) All impedance data should be based on MVA given in (3.) and on kV given in (4.) on the previous page. 17.

Xd

direct-axis unsaturated synchronous reactance

____________

pu

18.

Xq

quadrature-axis unsaturated synchronous reactance

____________

pu

19.

X′d

direct-axis unsaturated transient reactance

____________

pu

20.

X′ds

direct-axis saturated transient reactance

____________

pu

21.

X′q

quadrature-axis unsaturated transient reactance

____________

pu

22.

X′qs

quadrature-axis saturated transient reactance

____________

pu

23.

X′′d

direct-axis unsaturated subtransient reactance

____________

pu

24.

X′′ds

direct-axis saturated subtransient reactance

____________

pu

25.

X′′d

quadrature-axis unsaturated subtransient reactance

____________

pu

26.

X′′ds

quadrature-axis saturated subtransient reactance

____________

pu

27.

XL

stator leakage reactance or Potier reactance

____________

pu

28.

Ra

armature resistance

____________

pu

29.

Tq0

direct-axis transient open-circuit time constant

____________

sec

30.

T′q0

quadrature-axis open-circuit time constant

____________

sec

31.

T′′q0

direct-axis subtransient open-circuit time constant

____________

sec

32.

T′′q0

quadrature-axis subtransient open-circuit time constant

____________

sec

33.

TAGEN

armature short-circuit time constant

____________

sec

34.

T′D

direct-axis transient short-circuit time constant

____________

sec

35.

T′Q

quadrature-axis transient short-circuit time constant

____________

sec

36.

T′′D

direct-axis subtransient short-circuit time constant

____________

sec

37.

T′′Q

quadrature-axis subtransient short-circuit time constant

____________

sec

38.

X2

negative sequence reactance (saturated/unsaturated)

______/______ pu

39.

X0

zero sequence reactance (saturated/unsaturated)

______/______ pu

40.

Please attach a plot of generator terminal voltage versus field current that shows the air gap line, the open-circuit saturation curve, and the saturation curve at full load and rated power factor.

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Excitation System Information Listed below are the most common excitation systems used for voltage regulation of large synchronous generators. Each type of excitation system has been specified according to its manufacturer and name. In addition, the different excitation systems have been grouped together according to common characteristics. Please indicate, in the space provided on the left, the excitation system used for your generator. If your type of excitation system is not listed, please write the manufacturer and exciter type under the category that most accurately describes your excitation system. A. Rotating DC commutator exciter with continuously acting regulator. The regulator power source is independent of the generator terminal voltage and current. ___ 1. Allis Chalmers, Regulex regulator ___ 2. General Electric, Amplidyne regulator – NA101 ___ 3 General Electric, Amplidyne regulator – NA108 ___ 4. General Electric, Amplidyne regulator – NA143 ___ 5. General Electric, GDA regulator ___ 6. Westinghouse, Mag-A-Stat regulator ___ 7. Westinghouse, Rototrol regulator ___ 8. Westinghouse, Silverstat regulator ___ 9. Westinghouse, TRA regulator ___ 10. Brown Boveri, Type AB or Type ABC regulator ___ 11. Brown Boveri, Type DC regulator ___ 12. Other: Manufacturer _________________________________________ Type

_________________________________________

B. Rotating DC commentator exciter with continuously acting regulator. The regulator power source is bus fed from the generator terminal voltage. ___ 1. Westinghouse, PRX-400 regulator ___ 2. Other: Manufacturer _________________________________________ Type:

_________________________________________

C. Rotating DC commutator exciter with non-continuously acting regulator (i.e., regulator adjustments are made in discrete increments). ___ 1. General Electric, GFA4 regulator ___ 2. Westinghouse, BJ30 regulator ___ 3. Other: Manufacturer Type:

_________________________________________ _________________________________________

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D. Rotating AC Alternator Exciter with non-controlled (diode) rectifiers. The regulator power source is independent of the generator terminal voltage and current (not bus-fed). ___ 1. Westinghouse Brushless ___ 2. Westinghouse High Initial Response Brushless ___ 3. Other: Manufacturer

_________________________________________

Type:

_________________________________________

E. Rotating AC Alternator Exciter with controlled (thyristor) rectifiers. The regulator power source is fed from the exciter output voltage. ___ 1. General Elextric Alterrex ___ 2. Other: Manufacturer

_________________________________________

Type:

_________________________________________

F. Rotating AC Alternator Exciter with controlled (thyristor) rectifiers. ___ 1. General Elextric Alterrex ___ 2. Other: Manufacturer Type:

_________________________________________ _________________________________________

G. Static Exciter with controlled (thyristor) rectifiers. The regulator power source is busfed from the generator terminal voltage. ___ 1. Canadian General Electric Silcomatic ___ 2. Westinghouse Canada Solid State Thyristor System ___ 3 Westinghouse Type PS Static System, Type WTA, WHS, WTA-300 regulators ___ 4. ASEA Static System ___ 5. Brown Boveri Static System ___ 6. Rayrolle-Parsons Static System ___ 7. GEC-Eliott Static System ___ 8. Toshiba Static System ___ 9. Mitsubishi Static System ___ 10. General Electric Potential Source Static System ___ 11. Hitachi Static System ___ 12. Other: Manufacturer Type

_________________________________________ _________________________________________

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H. Static Exciter with controlled (thyristor) rectifiers. The regulator power source is bus-fed from a combination of generator terminal voltage and current (compound-source controlled rectifiers system. ___ 1. General Elextric SCT-PPT or SCPT System ___ 2. Other: Manufacturer Type:

_________________________________________ _________________________________________

I. Please attach a copy of the instruction manual for your excitation system. Make sure that a block diagram or schematic of the excitation system is included in the manual. The diagram should show the input, output, and all feedback loops of the excitation system. J. If the manufacturer’s data for the excitation system (i.e., time constants, gains, and saturation curves) are available, please attach these also. K. What is the excitation system response ratio (ASA)? L. What is the rated exciter output voltage at full load?

___________ volts

M. What is the maximum exciter output voltage (ceiling voltage)? ___________ volts N. Other comments regarding the excitation system? ___________________________________________________________________________ ___________________________________________________________________________ ___________________________________________________________________________ ___________________________________________________________________________ ___________________________________________________________________________ ___________________________________________________________________________

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Power System Stabilizer Information (supplementary excitation system) (Note: Complete this section only if your machine has PSS control.) A. Manufacturer: ___ 1. General Electric ___ 2. Westinghouse ___ 3. Toshiba ___ 4. PTI ___ 5. Alsthom ___ 6. Other: ____________________________ B. Is your PSS digital or analog?

________________

C. What is the actuating signal (the input signal) for your PSS? _____ Bus frequency ______ Shaft slip _____ Accelerating power ______Other If “Other”, indicate signal ______________________. D. Please attach a copy of the instruction manual for your PSS. The manual should include a block diagram or schematic of the PSS and the correspondence between dial settings and the time constants or PSS gain. E. Please attach a copy of the test report for your PSS. This report should contain the dial settings or time constants and PSS gain. If this report is not available, write the dial settings below: 1.

T1

washout or reset time constant dial setting

_________________

2.

T2

first lead time constant dial setting

_________________

3.

T3

first lag time constant dial setting

_________________

4.

T4

second lead time constant dial setting

_________________

5.

T5

second lag time constant dial setting

_________________

6.

K

PSS gain dial setting

_________________

7.

Vmax

maximum PSS output dial setting

_________________

8.

Vcut

dial setting for which PSS is set to zero when generator terminal voltage deviation is too large

_________________

9.

Other

________________________________________ _________________

10.

Other

________________________________________ _________________

Who installed your PSS? Please give person’s name, company, and location. Name:

_____________________________________________________

Company: _____________________________________________________ City, State: ____________________________________________________ Phone:

(____)_______________________________________________

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F: Other comments regarding the PSS? ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________

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Turbine-Governor Information Please complete Part A for steam, gas or combined-cycle turbines, Part B for hydro turbines, and Part C for both. A.

Steam, gas or combined-cycle turbines:

1.

Steam turbine, Gas turbine, or Combined-cycle

_____________

2.

If steam or combined-cycle, does the turbine system have a reheat process (i.e., both high- and lowpressure turbine)?

_____________

3.

B.

If steam with reheat process, or if combined-cycle, indicate, in the space provided, the percent of full load power produced by each turbine: by low pressure turbine or gas turbine:

_____________ %

by high pressure turbine or steam turbine:

_____________ %

Hydro turbines:

1.

What is the turbine efficiency at rated load?

_____________ %

2.

What is the length of the penstock?

_____________ ft

3.

What is the average cross-sectional area of the penstock

_____________ ft2

4.

What is the typical maximum head (vertical distance from the bottom of the penstock, at the gate, to the water level)?

_____________ ft

5.

Is the water supply run-of-the-river or reservoir?

_____________

6.

What is the water flow rate at the typical maximum head?

_____________ ft3/sec

7.

What is the average energy rate?

_____________ kW-hrs/acreft

8.

What is the estimated yearly energy production?

_____________ kW-hrs

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C.

Complete this section for each machine, independent of the turbine type.

1. Turbine manufacturer

_________________________________

2. Maximum turbine power output

_____________

MW

3. Minimum turbine power output (while on line)

_____________

MW

4. Governor information: a: Droop setting (speed regulation)

_____________

b: Is the governor mechanical-hydraulic or electrohydraulic? (Electro-hydraulic governors have an electronic speed sensor and transducer.)

_____________

c: Please provide below any time constants you have from the manufacturer describing the speed response of the governor. Be sure to identify each time constant.

______________________________________________ ______________________________________________ ______________________________________________

_____________

sec

_____________

sec

_____________

sec

d: Other comments regarding the turbine governor system? ________________________________________________________________ ________________________________________________________________ ________________________________________________________________ ________________________________________________________________ ________________________________________________________________

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Step-Up Transformer Data 1.

Transformer Bank No.

____________

2.

Rated MVA

____________ MVA

3.

Available H.V. Taps

_________ _________ _________ _________ _________ _________

4.

Please indicate present tap settings:

kV kV kV kV kV kV

Available L.V. Taps

_________ _________ _________ _________ _________ _________

kV kV kV kV kV kV

H.V Tap: ___________ kV L.V Tap: ___________ kV

5.

Does transformer have tap changing under load? __________________

6.

Is transformer a regulating-type transformer? If yes, please indicate regulating voltage range and the number of steps. _____________ kV to ______________ kV

7.

Number of steps _________

Please indicate how the transformer windings are connected: H.V. Side:

____

Wye

____

Grounded Wye

____

Delta

L.V. Side:

____

Wye

____

Grounded Wye

____

Delta

8.

Please attach a coy of the transformer test report, if available.

9.

If the transformer test report is not available, please provide the following impedances using the MVA base given in (2) above): RT

per unit resistance

_________ pu

XT

per unit reactance

_________ pu

BT

per unit magnetizing susceptance

_________ pu

GT

per unit core loss conductance

_________ pu

10. Other comments regarding the transformer? _____________________________________________________________________ _____________________________________________________________________ _____________________________________________________________________ _____________________________________________________________________ _____________________________________________________________________ _____________________________________________________________________

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QF Operating Practice Questionnaire for Synchronous Generators Note: The information on this survey is used to improve transmission models used in engineering studies. A. Generation and Plant Load (served by own generation) Pattern: 1. Generator Size:

________________________ MVA

2. Please indicate typical peak generation level (in MW). If generator serves plant load on the same side of the PG&E meter, also indicate typical load level. (Metered power equals peak generation level minus corresponding plant load). a. Peak Generation Level

____________________ MW

b. Corresponding Plant Load

____________________ MW

3. Please indicate typical planned seasonal and time period variations as percentage of levels specified in (2) above. Approximate percentages in increments of 25% (0%, 25%, 50%, 75%, 100%). Summer April thru October Time of Day (24-Hr format) 06:00 – 12:00

Generation

Load

12:00 – 18:00 18:00 – 22:00 22:00 – 06:00

185

Winter November thru March Generation

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B. Type of Regulation (complete either Section 1 or 2) 1. Maintain Vltage ______ Typical Voltage Range: _______kV to _______ kV Generator Rated Terminal Voltage

_______ kV

Standard PG&E operation bandwidth is 0.90 lagging (producing vars) to 0.95 leading (absorbing vars). If actual operation (not capability) is typically narrower than these limits, please indicate range. ____________

Lagging (producing vars)

to

Do you ever operate with manual voltage control If yes, what percent of the time?

____________

Leading (bsorbing vars)

_______________ _______________ %

Under what conditions? _______________________________________________________ _______________________________________________________ _______________________________________________________ _______________________________________________________ 2. Maintain Power Factor Typical Machine Power Factor Range _________________________ to _________________________ Is this automatically controlled? __________ If so, approximately how fast can the controller respond to a change in power factor? ______ 0 - seconds ______ 20 seconds – 3 minutes ______ greater than 3 minutes Standard PG&E band width is 95 to 105 % of rated voltage. If actual operation (not capability) is typically narrower than these limits, please indicate range. _________ to ________ % of rated voltage

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C. Governor Control Do you operate with an automatic turbine speed controller (governor)? _______ If yes, do you operate with it blocked? _____ If yes, what percent of the time?

______ %

Under what conditions? _________________________________________________________ _________________________________________________________ _________________________________________________________ D. Other comments regarding operation of your generator? _________________________________________________________________ _________________________________________________________________ _________________________________________________________________ _________________________________________________________________ _________________________________________________________________ _________________________________________________________________

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Appendix O: TRANSMISSION LINE SELECTOR SWITCHES THIS APPENDIX HAS BEEN INTENTIONALLY LEFT BLANK Refer to Appendix D for the following documents relevant to the title of this Appendix: “Requirements for Transmission Line Selector Switches and Associated Cost Responsibilities” PG&E Document Number G0104

Appendix P: ELECTRIC PRIMARY SERVICE REQUIREMENTS THIS APPENDIX HAS BEEN INTENTIONALLY LEFT BLANK Refer to Appendix D for the following documents relevant to the title of this Appendix: “Technical Requirements for Electric Service Interconnection at Primary Distribution Voltages” PG&E Document/Bulletin Number 2004PGM-11

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Appendix Q: GENERATOR AUTOMATIC SYNCHRONIZERS FOR GENERATION ENTITIES Q1.1. OPERATION AND PERFORMANCE REQUIREMENTS Automatic synchronizers assure that a generator attempting to parallel with the utility electric system can do so without causing an electrical disturbance to other customers and facilities (present and future) connected to the same system. In addition, the autosynchronizer device assures that the a generator attempting to parallel with the utility will itself not be damaged due to an improper parallel action. There are four types of synchronizing allowed. 1. Automatic synchronizing: The automatic synchronizer controls the generator voltage and speed to match the system conditions. The Automatic Synchronizer must meet the four operating parameters listed below and must meet PG&Erequired specifications. 2. Automatic synchronizing with a device not accepted by PG&E, supervised by an approved Synchronizing relay: The Synchronizing relay must meet the four operating parameters listed below and must meet PG&E-required specifications. 3. Manual synchronizing with supervision from a Synchronizing relay: The Synchronizing relay must meet the four operating parameters listed below and must meet PG&E-required specifications. 4. Manual synchronizing with Synch check supervision: This option is only allowed for generators less than 1000 KW total. The relay must be acceptable to PG&E and must meet the first two operating parameters in the list of four bullet items below. The following are the operating parameters for an automatic synchronizer and for a synchronizing relay: •

Voltage matching window of ± 10% or less



Phase angle acceptance window of ± 10 degrees or less



Slip frequency acceptance window of 0.1 Hz or less



Breaker closure time compensation 26

A field acceptance test must be performed on each synchronizing device to prove the operation of each function listed above. The test report must be legible and clearly list the actual operating values. 26

When an automatic synchronizing device does not have a comparable feature, a more restricted setting will be required. The phase angle window (±5 degrees) with a one second closing window time shall be used to achieve synchronization within a ±10 degrees phase angle. Supervision by a PG&Eapproved synchronizing device will be required if the relay settings range do not support the desired settings or when the measuring elements are not within specified tolerances.

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Note: The synchronizing relay activates a close signal output contact, or functionally equivalent feature, which in turn allows the breaker to close after all of the above conditions are met. Auto synchronizers and synchronizing relays must meet the following specifications: •

The device must be utility grade for use in utility type environment and applications o The minimum and maximum operating temperatures are in the range of -40° to 70° C o Must meet Current Transformer (CT) and Potential Transformer (PT) circuit burden carrying requirements o Must be certified to meet IEEE Std C37.90-2005 dielectric testing requirements o Must be certified to meet IEEE Std C37.90.1-2002 Surge Withstand Capability (SWC) and Fast Transient testing o Must be certified to meet the Radio Frequency Interference (RFI) withstand capability in accordance with IEEE Std C37.90.2-2004 o Must meet Power Frequency Magnetic Field Immunity (IEEE Std 1308-1994 and IEC 61000-4-8 ed2.0) o Must meet UL Standard and FCC test requirements as necessary o Must be certified for output contact Load Break Capability – through an inductive network (UL-1054 and IEEE Std C37.90-2005) o Airborne Arcing Noise susceptibility (IEEE Std C62.41.2-2002, IEEE Std C62.452002, and ISO/IEC 14536). o Must be certified for DC Hipot Test or Megger with no leakage or breakdown of the components. (IEC 61000-4-11 and 60255-11). o Electrostatic Discharge Immunity (IEEE Std C37.90.3-2001) o Must be certified to meet IEC 60255-21-1 Class 1 Vibration test (sinusoidal) or equivalent tests. IEC 60255-21-2 Class 1 Shock and bump or equivalent tests.

Auto synchronizers and synchronizing relays that are on PG&E’s list of approved devices already meet these specifications. If the generator selects a synchronizing device that is not on PG&E’s approved list, the Generation Entity or its representatives will be required to arrange for the device to be tested by a certified testing company. An InterNational Electric Testing Association (NETA) certified testing company must provide the test results to PG&E for approval 27. The tests should be designed to confirm that the synchronizing device would only close, or permit closing of a circuit breaker within the tolerances given in the operating parameters above. The generator will also provide to PG&E a copy of the detailed manufacturer’s instruction manuals.

27

Some of the companies that manufacture high voltage test equipment may also provide equivalent testing services.

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In addition, the device should be checked for the following: •

Confirm voltage sensitivity and setting accuracy within ± 1%



Confirm phase angle sensitivity and setting accuracy within ± 1%



Confirm slip frequency response and setting accuracy within ± 1%



Confirm breaker close time compensation accuracy within ± 1%

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Appendix R: GENERATOR PROTECTIVE RELAY REQUIREMENTS R.1. Requirements For third party generator interconnections, PG&E requires that the generator relays have the following features or setting elements: •

Overvoltage (59) 28 - On larger generators this is only required on the high side of the generator step-up transformer



Undervoltage (27)



Reverse Power (32) {for no-sale generators only}



Voltage-Restrained Overcurrent (51V) or Distance Backup (21P)



Underfrequency (81L)



Overfrequency (81H)

One multifunction three-phase relay that provides all of the above function is not acceptable. Redundant relaying will be required. Refer to Section G2.2 of this handbook for more information. The relays must be capable of being set to meet the parameters specified in Section G2. In addition, these relays must meet the following specifications: •

Relay must be utility grade for use in utility type environment and applications o The minimum and maximum operating temperatures are in the range of -40° to 70° C o Must meet Current Transformer (CT) and Potential Transformer (PT) circuit burden carrying requirements o Current transformers must have nominal secondary current of 5A and all relays must have 5A nominal AC input current o Must be certified to meet IEEE Std C37.90-2005 dielectric testing requirements o Must be certified to meet IEEE Std C37.90.1-2002 Surge Withstand Capability (SWC) and Fast Transient testing o Must be certified to meet Radio Frequency Interference (RFI) withstand capability in accordance with IEEE Std C37.90.2-2004 o Must meet Power Frequency Magnetic Field Immunity (IEEE Std 1308-1994 and IEC 61000-4-8 ed2.0) o Must meet UL and FCC test requirements as necessary

28

Numbers in parenthesis are device numbers for respective functions and are based on the ANSI/IEEE C37.2-1970 standard.

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PG&E Transmission Interconnection Handbook

o Must be certified for output contact Load Break Capability tests – through an inductive network (UL-1054 and IEEE Std C37.90-2005) o Airborne Arcing Noise susceptibility (IEEE Std C62.41.2-2002, IEEE Std C62.452002, and ISO/IEC 14536) o Must be certified for DC Hipot Test or Megger with no leakage or breakdown of the components (IEC 61000-4-11 and 60255-11). o Electrostatic Discharge Immunity (IEEE Std C37.90.3-2001) o Must be certified to meet IEC 60255-21-1 Class 1 Vibration test (sinusoidal) or equivalent tests. IEC 60255-21-2 Class 1 Shock and bump or equivalent tests. Relays on PG&E’s list of approved relays already meet these specifications. If the generator selects a relay that is not on PG&E’s approved list, the Generation Entity or its representative will be required to arrange for the device to be tested by a certified testing company. An InterNational Electric Testing Association (NETA) certified testing company must provide the test results to PG&E for approval 29. The generator will also provide to PG&E a copy of the detailed manufacturers’ instruction manuals. The tests should be designed to confirm the following 30: •

The contact outputs (programmable or fixed) shall be immune to 4 to 6 ms transient spikes at 60% of the station DC voltage.



The relay must be D.C.-voltage operated



Relay must perform under DC transients



Confirm voltage pickup to drop out for overvoltage and undervoltage elements to be within tolarance.



Confirm current sensitivity within ± 10%. as required in Section G5.1.5 of the PG&E Interconnection Handbook.



Confirm frequency response within ± 1%



The relay shall have the following self-diagnostic alarms (solid state & microprocessor only). Any Self-Test, Non-Volatile Memory, EPROM data error, Watchdog error, Program error, Battery fail (if applicable), Firmware error, Unit-outof-calibration (measuring elements are not within tolerance), DSP interrupt error.



Pickup and dropout ratios of the protection setting elements within 1% or better accuracy of the measuring elements.

In addition, the generator should address the following: •

Description of the operating principals of the relay, including voltage input sensitivity and range, frequency setting elements and setting ranges.

29

Some of the companies that manufacture high voltage test equipment may also provide equivalent testing services. 30 A copy of the detailed manufacturers’ instruction manuals shall be provided to PG&E for all non PG&E approved protective devices and automatic controls.

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If the relay is on the generator side of the step up transformer, understanding of relay performance and function become more involved. For example, would external phase shift be required to the relay voltage inputs for conditions where transformer windings of the step-up transformer are not in phase, or would the relay makes the phase shift adjustment internally; similar to the SLY92 type device?



For relays requiring external voltage input adjustments, how the under and overvoltage relay elements of the relay are set, detect, and operate correctly when the same overvoltage measuring element is used for overvoltage and the generator backup protection?



For relays making voltage input adjustments internally, how are the under and overvoltage relay elements of the relay set and operate?



The relay flexibility and sensitivity, in terms of range and function of elements, to be able to set for all applications with different generator and step-up transformer characteristics and / or under different system conditions.

Relay functionality as a result of loss of voltage, when used as distance backup. For example: •

Would the relay disable all tripping or just some elements?



Would there be a backup relay element to provide temporary line protection when the relay is set to disabled, as a result of loss of voltage?



How will concerns about the loss of potential (LOP) logic be addressed since we depend on one relay for multiple functions?



How much protection is lost? Is the relay set to trip on LOP or block on LOP?



How is the loss of voltage detected and alarmed, when the relay is used as voltage restraint overcurrent relay?



The Loss of Potential (Device 60) function in both relays is designed to detect blown fuses and open potential circuits.

Both phase distance and the voltage restraint overcurrent relay features will need to be evaluated for features such as: •

Does the distance element have provisions for offset mho characteristics?



How each relay would operate for the Delta-Wye configured step-up transformer, relative to the location of the voltage devices?



Is a Y-T bank required with either of the two relays used as voltage restraint overcurrent?



Would the loss of voltage input to either relay allow the relay to operate as overcurrent relay? etc.

It is the generators responsibility to not only set the relays but to understand the relays and settings that they are applying. They must be prepared to explain the settings and internal relay logic and operating principles to PG&E if they chose to use products that are not on our approved list. 194

PG&E Transmission Interconnection Handbook

Appendix S: PROTECTION ALTERNATIVES FOR VARIOUS GENERATOR CONFIGURATIONS S1. Standard Interconnection Methods with Typical Circuit Configuration for Single or Multiple Units Note: The protection requirements and station configurations will depend on the voltage class and the size and number of generation units.

S1.1. Generator “Connected” Into a Ring Bus Sta "A"

Sta "B" N.C. RING BUS

PG&E Owned Customer Owned

To Generation Facilities

S1.2. Generator “Connected” Into a Breaker-and A-Half (BAAH) Bus

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S1.3. Bus Fault Clearing Transmission Line Sta "A"

Sta "B"

(Optical Fiber or Microwave) "NEW" Generator

1. Can clear bus faults--Sta “A” and the “NEW” generator can be protected by two differentially connected relays for pilot protection, using digital communication equipment and medium31. 2. Cannot clear for bus faults--When the “NEW” generator cannot clear BUS Faults substation Sta “A” a DTT signal must be sent to clear the faults at the “NEW” generator site. The DTT feature may be incorporated as a function within the respective current differential relaying schemes, provided the relay and medium selected support DTT.

S2. Interconnection Methods with Special Circuit Configurations for Single Unit S2.1. Alternative--Generator “Tapping” To Existing Transmission Line between Two Terminals, considered only at voltages below 230kV

1. Can clear faults--If the “NEW” generator can clear faults on its interconnecting transmission line, additional communications-based protection to trip the “NEW” generator may not need to install at Sta “A” or Sta “B”. 2. Cannot clear faults--If the “NEW” generator cannot clear faults on its interconnecting transmission line, Sta “A”, Sta “B”, or both Sta “A” and Sta “B” will be required to be equipped with Transfer Trip (TT) equipment to send Direct Transfer Trip (DTT) signal(s) to clear for faults on the interconnecting transmission line. Notes:

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PG&E Transmission Interconnection Handbook

a. Application of DTT is independent of line protection 31. b. The DTT transfer trip receiver signal must be wired to trip the generator breaker. 3. When the line is protected by current differential relays or phase comparison type relay systems, the DTT may be incorporated as part of the line protection. (see S2.6)

S2.3. Generator “Tapping” closely outside the Substation Between Two Existing Terminals

The following applies:

31



Connect ground grids between Sta “A” and “NEW” generator together.



Combine Current Transformer (CT) inputs from Sta “A” breaker and the “NEW” generator breaker to line relays at Sta “A”.



Line relays trip both Sta “A” breaker and either the “NEW” generator line breaker terminal, or in the absence of the line breaker, will be wired to trip the generator breaker via a auxiliary relays. The auxiliary relays must be suitable for tripping and lockout applications.



PG&E reclose block is supervised by line voltage or generator’s breaker status.



PG&E breaker failure relay trips the generator breaker directly via an auxiliary relay.



This configuration may require DTT from Sta “B”.



See S2.5 and S2.6

Refer to Appendix F for communication-assisted protection and associated requirements.

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PG&E Transmission Interconnection Handbook

S2.4. Generator “Connected Close” Outside the Substation with a Dedicated Line

The following applies: •

Connect ground grids together between Sta “A” and the “NEW” generator station (not required if fiber optic network is used)



Install new line differential relays at Sta “A”.



Connect CT inputs from Sta “A” breaker and “NEW” generator’s breaker to line differential relay.



Line differential relay trip Sta “A” breaker and the “NEW” generator breaker via auxiliary relays.



Direct trip “NEW” generator breaker via an auxiliary relay for Sta “A” breaker failure.



See S2.5 and S2.6

S2.5. Requirements for S2.3 and S2.4 Alternatives

32



A Ground Grid study 32 is required for both Stations “A” and “B” and the “NEW” generator to determine conductor size and routing.



Each generating site needs to conform to the IEEE Std 80-2000 for grounding requirements.



Transient Studies are required to determine the amount of exposure to PG&E and the respective “NEW” generating facility equipment prior to PG&E performing a detailed feasibility evaluation and specifying the equipment specification. Exposure in this instance refers to the susceptibility of PG&E’s system to excessive transient voltage dip, frequency deviation, or voltage deviation.



Interposing relays are required for tripping and status circuits between Sta “A” and the “NEW” generating facility and to isolate the DC control batteries.

PG&E may be contacted for a list of consultants who can provide this type of service.

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PG&E Transmission Interconnection Handbook



The Generation Entity must be aware that common ground grid could result in additional exposure to transients caused by switching and faults at Sta “A”. Operating procedures and protection needs to be in place to address bypassing of breaker at Sta “A” for maintenance or other clearances. Otherwise the “NEW” generating facility will need to be cleared.

S2.6. Additional Items for Consideration •

Design and operating standards are not available for alternatives S2.3 and S2.4.



For alternatives S2.2 and S2.3, NERC redundancy requirements should be followed as appropriate for the voltage level.



Alternatives S2.1 and S2.3 are not recommended if existing line protection uses a power line carrier. Two concerns are: o Signal will be degraded unless wave trap is installed at the new generation facility. o Risk of over-tripping for faults in “NEW” generator facility



Economic analysis is recommended to compare alternatives S2.1 and S2.3, or S2.2 and S2.4.



When simulating “End-of-Line” faults, generator unit steady state synchronous impedance shall be considered.

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PG&E Transmission Interconnection Handbook

Appendix T: BATTERY REQUIREMENTS FOR INTERCONNECTION TO PG&E SYSTEM The purpose of this document is to ensure safety and reliability of Pacific Gas and Electric Company and its customers who will or plan to interconnect to PG&E system. The requirements made here will ensure that the system operates as designed. It is required that the following documentation be provided to PG&E for review and approval by Substation Engineering Department: 1. Type of utility grade Battery (Flooded lead acid or NiCd). Monoblock (multiples cells in a jar) batteries from C&D, EnerSys, BAE, or other approved vendors will be acceptable (car and deep cycle marine batteries are not acceptable). Battery rack must be designed to withstand loading based on IEEE 693. See table on page T-4 for approved battery make and models. 2. Detailed information of load including continuous and momentary. No minimum load requirement-Smallest flooded acid may be the limitation. 3. Battery sizing calculation based on IEEE Std 485-1997 (IEEE recommended Practice for Sizing Large Lead Storage Batteries for Generating Stations and Substations) or IEEE Std 1115-2000 (IEEE Recommended Practice for Sizing Nickel-Cadmium Batteries for Stationary Applications) and minimum 8 hours discharge rate using manufacturer software (to ensure proper discharge curve is used) using aging factor of 1.25 and design margin of 1.1 to be clearly shown on the calculation. Charger sizing calculation based on battery size with recharge time of 12 hours assuming charger will support the continuous load and recharging of the battery at the same time. 4. When battery is installed, proof of discharge testing (3 hour load testing is typical) to ensure battery has the capacity to support the load and trip, per IEEE Std 450-2010 (Voltage measurements should be taken every 15 minutes throughout the testing). 5. Document showing what kind of maintenance will be done (Monthly, Quarterly, and Yearly, etc.) 6. Monitoring of minimum battery low voltage by separate voltage relay or through charger and provide critical alarm to SCADA or monitoring system. Because of serious reliability, safety and reduced life concerns with sealed (also called Valve Regulated Lead Acid – VRLA) batteries industry-wide, PG&E has stopped the use of sealed batteries in substation or any switchgear installations or interconnection using these batteries. Flooded lead acid (calcium, antimony) and Nickel-Cadmium (NiCd) are the only batteries acceptable in these installations. Switchgear compartments typically see very high temperatures, and if sealed batteries are used they will dry out in less than a few years causing safety and reliability concerns along with not having the capability to trip breakers. A side by side comparison of IEEE Std. 450-2002 Section 5.2.3 (IEEE Recommended Practice for Maintenance, Testing and Replacement of Vented lead acid batteries for Stationary applications –also

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PG&E Transmission Interconnection Handbook

referred as Flooded batteries) and IEEE Std 1188-1996 Section 5.2.2 Subsections a, b & c. (IEEE Recommended Practice for Maintenance, Testing and Replacement of Valve-regulated batteries for Stationary application- also referred as VRLA) clearly demonstrates that VRLA requires Quarterly ohmic resistance testing compared to yearly ohmic testing for flooded batteries. Experience industry wide indicates problem with doing ohmic tests on VRLA because of the design of battery and trying to make connections to the terminals and interconnecting hardware. Even if ohmic resistance reading is not done on flooded battery, the failure modes can be detected by other means whereas with VRLA eliminating this test could cause dryout condition and ultimately catastrophic failure. In hot environment VRLA would require charger compensation as well as monitoring which is expensive and still not proven to be adequate. In the telecommunication industry there are presently trials under way for system wide replacements of VRLA with Flooded or NiCd batteries. PG&E recommends use of NiCd batteries in switchgear cubicle because of better performance under extreme temperatures. Flooded batteries can also be used in switchgear. Additional reasoning for not using VRLA in substation as pointed out by IEEE Battery working group Chairman in the recent paper published in IEEE. “Summarizing the issue for VRLA batteries”, there is a considerable risk involved in installing a single VRLA string in a substation. If parallel strings are installed, to operate reliably, they must be redundant, either by design or by a sufficient degree of conservatism in the sizing calculation. In building in redundancy, however, the main aim of reducing battery costs is compromised. Despite the early claims of maintenance-free operation, VRLA batteries require considerable surveillance and testing to maintain a high degree of reliability, IEEE Std 1188-1996 [2] recommends quarterly internal ohmic measurements and annual discharge testing of VRLA. These measures are largely ignored by the telephone operating companies because of their low loads and use of parallel strings, as detailed above. In substation operation, however, these practices are doubly important because of the higher currents involved”.

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PG&E Transmission Interconnection Handbook

PG&E Approved Interconnection Batteries33,34 Type Manufacturer Model Line Vented or C&D DCU Flooded Lead DJ Acid (VLA) JC KCR LCY LCR Alcad LSe SGL/SGH SD/SDH BAE OGi OPzS Enersys OPzS Powersafe CC Powersafe EC Powersafe FC Powersafe GC Powersafe Plante’ SBS STT SR Hoppecke GrOE OSP OPzS GNB MCX/MCT/H1T NCX/NCN/NCT PDQ/ T-Bloc Nickel Cadmium Alcad LE (Ni-Cad) M H SBS KP

33 34

List is not exclusive, other battery manufactures and model lines must be submitted for review Multiple cells per jar or block types of any models above are acceptable

202

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