Generating Facility Interconnections Electric Rule No. 21 ...

Supplemental Review
03 July 2018
Table of Contents 1. EXECUTIVE SUMMARY........................................................................................................................................................... 3
1.1 Generation Interconnection Request ...................................................................................................................... 3 1.2 Initial Review Summary ........................................................................................................................................... 3 1.3 Supplemental Review Results ................................................................................................................................ 3 1.4 Next Step ................................................................................................................................................................. 3
2. PROJECT INFORMATION ....................................................................................................................................................... 4 2.1 Generating Facility Information ............................................................................................................................... 4 2.2 Base Cases ............................................................................................................................................................. 4 2.3 Interconnection Assumptions .................................................................................................................................. 5 2.4 Distribution System ................................................................................................................................................. 5 2.5 Maps and Diagrams ................................................................................................................................................ 6
2.5.1 Project Vicinity Sketch ................................................................................................................................. 6 2.5.2 Simplified Single Line Diagram ................................................................................................................... 6 2.5.3 Sketch of Required Work ............................................................................................................................ 7
3. SUPPLEMENTAL REVIEW ...................................................................................................................................................... 8 3.1 Screen N – Penetration Test ................................................................................................................................... 8
3.1.1 Substation Penetration ................................................................................................................................ 8 3.1.2 Feeder and Device Penetration .................................................................................................................. 9
3.2 Screen O – Power Quality and Voltage Tests ...................................................................................................... 10 3.2.1 Steady State Voltage................................................................................................................................. 10 3.2.2 Voltage Fluctuation .................................................................................................................................... 10 3.2.3 Voltage Stabilization .................................................................................................................................. 11
3.3 Screen P – Safety and Reliability Tests ................................................................................................................ 12 3.3.1 Protection Settings and Overstressed Equipment .................................................................................... 12 3.3.2 Anti-Islanding ............................................................................................................................................. 12 3.3.3 End of Line Fault Detection ....................................................................................................................... 13 3.3.4 Ground Fault Detection ............................................................................................................................. 13
4. INTERCONNECTIONS FACILITY REQUIREMENTS ......................................................................................................... 15 5. REVENUE METERING AND TELEMETRY .......................................................................................................................... 15 6. PRE-PARALLEL INSPECTION REQUIREMENTS ............................................................................................................. 15 7. COST ESTIMATE .................................................................................................................................................................... 16 8. REQUIREMENTS PRIOR TO PRE-PARALLEL INSPECTION AND OPERATION ......................................................... 17
8.1 PG&E System Work .............................................................................................................................................. 17 8.2 Interconnection Facility Work ................................................................................................................................ 17 8.3 Required Documentation ...................................................................................................................................... 17 Parallel Operation Requirements ................................................................................................................................... 17 8.4 Operating Requirements ....................................................................................................................................... 17
9. APPENDIX A – SIGNAGE REQUIREMENT ......................................................................................................................... 18
SUPPLEMENTAL REVIEW 3 County of El Dorado
1. Executive Summary
1.1 Generation Interconnection Request
TerraVerde Renewable Partners, an Interconnection Customer (IC), has requested a Generating Facility (GF) interconnection for County of El Dorado (Project) to the Pacific Gas and Electric Company (PG&E)’s distribution system for a 2280 kW Photovoltaic generating facility to be located at 200 Industrial Drive, Diamond Springs, CA 95619. The Generating Facility will be connected to PG&E’s Diamond Springs 1107
distribution circuit. Interconnection will be in accordance with CPUC’s Generating Facility
Interconnections, Electric Rule 21. The requested operating date for the Project is TBD. This Project has been assigned the reference number of 1799-RD. In accordance with the PG&E’s Electric Rule 21 Tariff procedures, the Initial Review did not pass all necessary screens. Supplemental Review is required. The Supplemental Review will determine if the IC could continue to qualify for interconnection pursuant to the Fast Track Process.
1.2 Initial Review Summary
The Electric Rule 21 Initial Review Process has determined that the generating facility has failed at least one screen on Initial Review. Pursuant to Section G of the Generator Interconnection Procedure, PG&E cannot determine the interconnection requirements for this project without further study. Here is a summary of the failed screen and the issues related to the screen:
Screen F – Project contributes more than 10% fault current at POI Screen G – Short Circuit Interrupting Capability Issues Screen I – Power will be exported across the PCC Screen J – Generating Facility is greater than 11kVA Screen K – Generating facility is a NEM that is greater than 500kW Screen M –15% Line Section Peak Load Issues
1.3 Supplemental Review Results
PASS
PASS
Project passes supplemental review. Upgrades will be required for interconnection. Please see the full report for details. Estimated cost of upgrades required is $351,856 with an estimated construction time of 6-12 months.
1.4 Next Step
The next step of the Interconnection Process is the Interconnection Agreement. Once you have reviewed the results of this Supplemental Review, please contact your EGI Interconnection Manager to discuss arranging a results meeting and next steps meeting. A table for the summary of estimated costs is in section 7. The Customer may request a Facility Study to be performed to obtain a better estimate of costs. PG&E's Electric Rule 21: http://www.pge.com/tariffs/tm2/pdf/ELEC_RULES_21.pdf
2. Project Information
2.1 Generating Facility Information
The proposed generating facility (GF) will distribute power to the PG&E utility grid using 38-PVI 60TL Inverters. The system has a total rated output of 2280kW. The generation output will be transformed to PG&E’s 12
kV line voltage through PG&E owned transformer(s) with a total rating of 2500kVA. The
transformer(s) will be connected Delta - Wyegnd primary to secondary. The generating facility will operate as Full export of power connected to the PG&E system.
2.2 Base Cases
Bank studies were performed with the following assumptions to determine the effects of the generating facility on the distribution system. They assumed the base cases listed below for normal conditions.
Table 2.A - Base Case Data
Case 1 (Summer Peak) 1
Capability (kW)
13340 10941 736
Diamond Springs 1106
11450 9200 441
11580 8696 650
13340 4219 1471
11450 3361 882
11580 2624 1299
16210 4482 1471
12320 4286 882
14600 3379 1299
1 Peak and Off-Peak load calculation or load estimating for solar generation systems with no battery storage use daytime load from10 am to 4 pm
while all other generation uses absolute maximum or minimum load.
2.3 Interconnection Assumptions
This data is based from the submitted documents and assumed in the study.
Project Name County of El Dorado
Customer-Proposed Commercial Operation Date
Total Output and Power Factor 2280kVA (2280kW @ 100% power factor)
Description of Operation Full export to Diamond Springs 1107.
Interconnection Transformer
Transformer Data
2.4 Distribution System
These are the existing conditions at the time of this study.
Substation / Feeder
Diamond Springs Bank 2 115 kV / 12 kV Diamond Springs 1107
Primary Voltage at POI 12 kV
Primary Line Configuration at POI 3-phase, 3-wire distribution circuit
Maximum Symmetrical Short Circuit near POI @ 12kV
6961.74 (A)
Limiting Conductor
2_ACSR_I 157 369
715_AAC_I 745 2449.43
Upstream Protective Devices
Device # Device Type
FeederID Generation (kW)
None
2.5 Maps and Diagrams
2.5.1 Project Vicinity Sketch
2.5.3 Sketch of Required Work
3. Supplemental Review
3.1 Screen N – Penetration Test
The summer normal rated capacity for PG&E distribution substation transformers and voltage regulators is the highest applicable manufacturer’s nameplate rating. The winter normal rated capacity is 1.2 times the nameplate rating. Substation regulator ratings are based on kVA transformed at maximum tap changer position. The summer normal rated capacity for PG&E overhead distribution conductors in interior parts of the state is based on an ambient temperature of 43°C with a wind speed of two feet per second and a maximum conductor operating temperature of 75°C for aluminum and copper conductors or 80C for ACSR. The winter normal rated capacity is based on an ambient temperature of 16C with a wind speed of two feet per second. The rated normal capacity for switches and circuit breakers on the PG&E distribution system during both summer and winter conditions is the highest applicable manufacturer’s nameplate rating. All single phase equipment on the PG&E distribution system is derated by 5% to account for the effects of phase imbalance. All air insulated equipment including overhead conductors is considered to be single phase for application of this rating. Three phase oil insulated equipment in a common tank and underground cables sharing a single conduit are not derated.
3.1.1 Substation Penetration
This section evaluates the effects of the worst case scenario which includes the possibility of an (N-1) contingency scenario. The (N-1) contingency scenario is when the feeder with the largest net load is tripped off which reduces the total load on the substation. The following impacts were identified:
Table 3.A – Bank Penetration
CB 1107 4,219 1,471 1,471
CB 1106 3,361 882 Exlude 0
CB 1105 2,624 1,299 1299
1799-RD 0 2280 2280
Analysis of this section has determined that there will be no significant impacts to the system when the project goes online. No mitigation will be needed for this section. No Mitigations
3.1.2 Feeder and Device Penetration
Circuit studies were performed to determine if there are any equipment overloads due to the proposed generating facilities. Also, penetration of some devices may be an issue even if they are not overloaded. Loading was examined with the generator off line and on line for normal operating conditions. This study assumes normal operating conditions and base case data.
Table 3.B - Device Loading
Project OFF Line
PCC 0 0 0
PCC -2269 -2269 -2269
Analysis of this section has determined that there will be overloading on Fuse 12153 when the project goes online. In order to mitigate this issue, the fuse should be replaced with solid blades. Mitigations
Replace Fuse link 12153 with Solid blades, unless project is fed from a different nearby feed.
Pull PG&E Primary approximately 350ft to new service for 1799-RD interconnection.
3.2 Screen O – Power Quality and Voltage Tests
3.2.1 Steady State Voltage
Diamond Springs 1107 has no voltage regulating devices between the substation and the proposed generation site. Bank 2 at Diamond Springs Substation has a Station Load Tap Changer (LTC) that regulates the feeder voltages. The addition of the Project will offset some load measured by the Bank 2 Regulator, possibly causing output voltage to be lower. Analysis was performed to determine if the Project causes any steady state voltage problems where the primary voltage is out of tolerance from Rule 2 Standards. Steady state voltage was examined with the generator off-line and on-line for the different system operating conditions.
Table 3.C - Steady State Voltage
Voltage on 120V Base
MAX MIN PCC MAX MIN PCC MAX MIN PCC
Project Off-Line
1107 126.0 120.8 125.3 125.9 121.7 121.9 125.2 121.1 121.5
1106 126.0 122.7 n/a 124.9 121.4 n/a 124.8 121.0 n/a
1105 126.0 120.6 n/a 127.0 121.7 n/a 127.2 120.9 n/a
Project On-Line
1107 125.7 120.4 125.3 125.9 121.2 122.1 125.2 121.0 121.9
1106 125.3 122.5 n/a 124.8 120.9 n/a 124.3 120.8 n/a
1105 125.3 120.7 n/a 127.1 121.2 n/a 127.2 120.6 n/a
3.2.2 Voltage Fluctuation
In general, voltage flicker with regards to large scale distributed generation installations is defined as the change in the voltage at the Point of Common Coupling (PCC) due to a sudden change in current acting across impedance: PG&E and the California Public Utilities Commission (CPUC) require that voltage flicker on the distribution system be restricted to three volts or less on a 120 volt base. This limit may be increased to five volts if the circuit/substation is very rural or industrial in nature. Studies were performed to determine if the voltage flicker caused by the proposed generating facility exceeds this limit. The voltage flicker due to the Project was calculated by comparing the steady state voltage with generation on-line and the voltage of the circuit immediately after the generator trips off-line but before the voltage regulation equipment can react.
Table 3.D - Calculated Fluctuation
0.90 1.18 0.89 0.79 0.59 0.30
0.93 1.06 0.80 0.71 0.53 0.27
0.95 0.96 0.72 0.64 0.48 0.24
0.99 0.64 0.48 0.43 0.32 0.16 Unity 1.00 0.37 0.28 0.25 0.19 0.09
-0.99 0.09 0.07 0.06 0.05 0.02
-0.95 0.25 0.19 0.17 0.13 0.06
-0.93 0.37 0.28 0.25 0.18 0.09
-0.90 0.51 0.39 0.34 0.26 0.13
Power
Factor
MVA
L a g g i n g
L e a d i n g
3.2.3 Voltage Stabilization
Voltage stabilization is required when ineffectively grounded generators can expose line equipment to overvoltage conditions during ground faults. This is only a concern on 4-wire distribution circuits. Equipment ratings are sized for line-neutral voltages. This is an issue during ground faults when the generator is still online after the PG&E source trips. Since the ineffectively grounded generator cannot carry the ground connection to the fault, the ground voltage will be elevated to the line potential. Equipment on the other phases will then get exposed to line to line voltage which is approximately 1.7 times higher. Voltage stabilization will not be an issue. The project is connecting to a 3-wire system. No mitigation is required for this section. No Mitigations
3.3 Screen P – Safety and Reliability Tests
The major protection items are identified are detailed below. These would be required to be installed by PG&E as Special Facilities for the Interconnection Customer’s proposed generation. Per Section G2.1 of the PG&E Transmission Interconnection Handbook, PG&E 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. Refer to PG&E’s Generation Interconnection handbook for full requirements. DIH: http://www.pge.com/b2b/newgenerator/distributedgeneration/interconnectionhandbook/ TIH: http://www.pge.com/mybusiness/customerservice/nonpgeutility/electrictransmission/tariffs/handbook/
3.3.1 Protection Settings and Overstressed Equipment
Short circuit studies were performed to determine the effect of the Project on short-circuits fault duties and impact on the existing distribution system. Some fault conditions will cause the PG&E fault contribution to lower due to the presence of the generator. If the contributions are decreased significantly, PG&E protective devices may not see faults. Other fault conditions can increase the total fault duty at the fault location due to the presence of the generator. This can cause overstress conditions to certain equipment. The fault duties were calculated before and after the Generating Facility Interconnection to determine the impact it will have on the system.
Table 3.E - Short Circuit Contribution
Fault Contribution (Primary Amps)
Bus Fault
1799-RD 0 0 0 40 61 122
Total Fault Duty 8873 7852 9075 8912 7915 9197
PCC Fault
1799-RD 0 0 0 28 61 123
Total Fault Duty 3926 4978 5751 3971 5049 5874
End of Line Fault
1799-RD 0 0 0 10 26 52
Total Fault Duty 1603 2516 2906 1606 2531 2928
Analysis of this section has determined that fuse cutout 6611 may be overstressed. Field verification of cutout type is needed, and replacement is needed it is indeed a part 24. The fuse cutout is currently overstressed prior to this project coming online, therefore the cutout replacement will not be a customer responsibility. Mitigations
Replace fuse cutout 6611 with part 44H if it is currently a part 24 as indicated.
3.3.2 Anti-Islanding
It is required that the generator trip off line within 2 seconds for the formation of an Unintended Island between the proposed generator and the automatic sectionalizing devices. When the ability of the
generator to trip within this time is in question, certain mitigation could be required such as reclose block, primary ground fault detection, visibility, and in some cases direct transfer trip. Reclose Blocking is needed on any PG&E automatic reclosing devices upstream of the generator if the aggregate nameplate capacity of the generation exceeds thresholds of the peak load of that automatic reclosing device. Automatic reclosing devices on the PG&E distribution system are limited to line reclosers and feeder breakers. The purpose of reclose blocking is to reduce the safety risks to the customer, the public, and PG&E employees which could result from the PG&E reclosing into out-of-phase conditions. Distribution direct transfer trip schemes can be waived if they meet certain thresholds. If adequate fault detection cannot be accomplished by conventional relaying schemes, then a direct transfer trip scheme may be required. An acceptable communication channel is required for the direct transfer trip scheme.
Table 3.F - Anti-Islanding
Bk 2 30100 3652 0 2280 5932 19.7% 62.4%
1107 OCB 4219 1471 0 2280 3751 88.9% 64.5%
Fuse 12153 21 0 0 2280 2280 10857.1% 0.0% Analysis of this section has determined generation is over 50% minimum load on all upstream devices during minimum load conditions. Due to the project size and having a fault current contribution ratio of over 10%, a ground fault sensing bank will be required at the project site to help isolate the project during ground faults. Furthermore, a SCADA enabled device will be required at the POI. Mitigations
Ground fault sensing bank required at project site.
PG&E SCADA enabled device required a POI
3.3.3 End of Line Fault Detection
Generators are required to see end of line faults on the PG&E system. During steady state conditions when a generator has not tripped yet, fault conditions appear lower than normal rated output. Voltage restraint overcurrent (51V) elements must be used to lower the overcurrent pickup value since it would normally be set above the nominal current level. It will lower the pickup value in a 1 to 1 relationship to the per unit value of voltage at the generator. When a voltage restraint scheme will not work then a voltage constraint (51C) scheme will be used. This scheme will have a pickup always set lower than the minimum expected fault current. The generator won’t actually trip until it sees an under voltage condition of less than 80% for more than 1.5 seconds with the overcurrent pickup activated. If this scheme does not work, then the project will require direct transfer trip to ensure the generator trips offline for end of line fault conditions. The inverter-based interconnections typically do not contribute enough fault current to the phase faults on the PG&E circuit and it will not be possible for current-based fault detection schemes to detect the phase fault and operate. Therefore, in case of three-phase or line-to-line faults on the PG&E feeder the anti- islanding scheme on the Project’s inverters will trip the respective inverter off line within a maximum two seconds after the feeder circuit breaker or line recloser opens in order to clear the fault. This scheme is considered to be acceptable for the phase fault detection if the required upgrades in Section 3.3.2 are completed. No Mitigations
3.3.4 Ground Fault Detection
Most interconnection transformers will have a delta in either the primary or secondary side due to PG&E requirements. This delta will isolate the generation from ground faults on the PG&E system. This means that normal ground fault detection in the interconnection equipment will not be effective. The conditions
of this project will be evaluate to determine if a supplemental ground fault detection scheme on the primary will be required. PG&E’s distribution system at the POI is a three-wire distribution circuit and does not have a current carrying neutral. Therefore, the generating facility should be connected to the distribution system using an effectively ungrounded connection system that does not contribute zero sequence current to the PG&E distribution system. The primary of the interconnection transformer for this solar generating station is considered to be a delta winding as per the submitted information. In order to detect any ground fault on the circuit, redundant ground overvoltage relays (ANSI Device 59N) are required to detect ground faults on the utility side of the Point of Common Coupling (PCC). The 59N relay function can be provided using a ground wye / broken delta ground fault sensing bank. This must be installed in or adjacent to the station switchgear with (59G) voltage relays and a 13 ohms parallel resistor with proper wattage across the open corner of the secondary delta. Fuses are permitted on the primary side of the potential transformers but not in the transformer secondary.
Figure 3.A - Delta Primary on 3-Wire System
Table 3.G – 59N Voltage Sensing Validation
Sub EOL PCC Sub EOL PCC
V0 at POI (pu) 0.35 0.17 0.55 1.00 1.00 1.00
59N Fault Test PGE ON / DG ON PGE OFF / DG ON
Project to install ground fault sensing bank and set relay to 20V pickup based on a 100:1 PT ratio. If a different PT ratio is used, the pickup setting will need to be adjusted accordingly.
4. Interconnections Facility Requirements
A portion of the work detailed here may need to be completed by PG&E. The scope of the work required onsite will include the following: Gang-Operated Disconnect Switch
A visible, lockable disconnect switch is required between the Generating Facilities and the PG&E system for the safety of PG&E personnel. The switch must be gang operated and have a visible open point (air gap, visible either through a viewing window or an operable door). PG&E operating personnel must be able to independently operate the switch and lock it in the open position. This switch will be the PG&E operable disconnect point for the Generating Facility and will constitute the Point of Common Coupling between the Project and the PG&E utility grid.
Closing Supervision
The switchgear must incorporate closing supervision schemes to prevent the main breakers from closing if the Generating Facility is on line and is out of synchronism with the PG&E system. The following schemes are acceptable:
Generator Unit Interlocks: the close circuit for the breaker is supervised by status inputs from each generator so that it cannot close unless all the generators are off line.
5. Revenue Metering and Telemetry
Per PG&E Rule 21, J.5: If the nameplate rating of the Generating Facility is 1 MW or greater, telemetering
equipment at the Net Generator Output Metering location may be required at the Producer's expense.
A PG&E RTU is required for SCADA/EMS telemetry for PG&E’s visibility. Since the generation capacity of the Project is less than 10MW, the SCADA communication scheme on the recloser at the PCC will meet the telemetry requirement. However, additional telemetry may be required to support the DTT scheme, if required.
The IC is to provide the leased line, space, raceway, interface wires, and AC and DC power as
required.
The IC is responsible for the installation of the necessary conduits and substructures in order for
PG&E to provide the new 12 kV primary metered service to this site. One six-inch conduit plus
one spare will be required to accommodate the new 600 Al MCM underground cable. Detailed
instructions on the process will be provided.
The generating facility nameplate will be at least 1MW. A PG&E SCADA recloser will be required to monitor the export of the generating facility at the point of interconnection.
6. Pre-parallel Inspection Requirements
Please note upon notification of the generator(s) readiness for the pre-parallel inspection, it can take up to 30 days for the pre-parallel inspection due to available resources. The following items must be completed prior to the scheduling of the inspection:
o All required agreements executed. o There must be an accessible, visible and lockable disconnect switch. (This must be shown on
the single line drawing. Include manufacturer name and model number.) o Breakers should be shunt trip from a battery in accordance with the attached criteria. (This
requirement must be shown in the three line drawings. Include manufacturer name, size and model number.)
o A copy of the final signed building permit from the local authority having jurisdiction over the installation of the co-generation system is provided.
o If required, all electric work by PG&E completed. o If required, gas service/meter (PG&E owned) installation completed.
Once the inspection is scheduled, our Station Test Department requires the following information be provided a minimum of 15 days prior to the inspection:
o Single line and three line relay drawings approved. (An electronic version is preferred.) o The G5-1 Form completed and returned electronically. (Will be provided) o Basic Info Requirement Form completed and returned electronically. (Will be provided) o Field "bench test" of relays approved. (An electronic version is preferred.) o Battery Discharge Test Report and Commissioning Test Checklist. (Form will be provided)
7. Cost Estimate
The following estimated costs include interconnection and/or system upgrades required to interconnect the Project to PG&E’s distribution system, but do not include all in-plant facilities. The cost of work to be done by PG&E is shown below.
Table 7.A - Estimated Costs
Diamond Springs Substation
None $0 $0
Replace Fuse cutout 6611 if needed $10,000
Subtotal $5,000 $10,000
Generating Facility
$10,000
Extend Mainline to project site @220/ft for 350ft $77,000
PG&E Secondary Revenue Metering $5,000
Ground Fault sensing bank $45,000
PG&E SCADA Recloser at POI $85,000
Subtotal $269,856
Total Project Cost (excludes COO) $351,856 $20,000
ITCC (24%) $84,445 n/a
Option 2: One-Time COO in lieu of Monthly COO (Total*0.53%*14.20*12) $317,768 n/a
2 Not subject to ITCC on contribution. ITCC is exempt for wholesale generators that meet the IRS Safe Harbor Provisions. PG&E currently does not require the Interconnection Customer to provide security to cover the potential tax liability on the Interconnection Facilities, Distribution Upgrades, and Network Upgrades per the IRS Safe Harbor Provisions (IRS Notice 88-129). PG&E reserves the right to require, on a nondiscriminatory basis, the Interconnection Customer to provide such security, in a form reasonably acceptable to PG&E as indicated in Article 11 of the SGIA, an amount up to the cost consequences of any current tax liability. Upon request and within sixty (60) Calendar Days’ notice, the Interconnection Customer shall provide PG&E such ITCC security or ITCC payment in the event that Safe Harbor Provisions have not been met, in the form requested by PG&E.
8. Requirements Prior to Pre-parallel Inspection and Operation
8.1 PG&E System Work
The following is the required work on the PG&E System prior to the pre-parallel inspection: 1. Extend mainline approximately 850ft to project location (to be completed under new business by
service planning) 2. Pull primary ~350ft to project site. Possibly using proposed conduits. 3. Replace Fuse 12153 with solid blades 4. Upgrade fuse cutouts 6611 to part 44H.
8.2 Interconnection Facility Work
The following is the required work for the interconnection facilities prior to the pre-parallel inspection:
1. Secondary Service must be established. Secondary service requirements can be found in the PG&E Green Book or provided by the PG&E Service Planning Department
2. Install new PG&E 2500kVA transformer for service 3. Applicant is to provide an approved PG&E switch that is accessible, lockable, and gang-operated
beyond the meter at the PCC 4. Install ground fault sensing bank 5. Install PG&E SCADA enabled device at POI
8.3 Required Documentation
The following is the required work prior to the pre-parallel inspection: 1. Applicant to provide a complete set of layout drawings and elevations of the switchgear including
dimensioned drawings of the PG&E revenue metering section showing the current transformer and potential transformer mountings
2. Applicant to provide manufacturers’ specification sheets for the breaker, primary disconnect switch, batteries and charger, generator step-up transformer, current transformers and potential transformers
3. Applicant to provide relay settings for primary switchgear 4. Applicant to provide updated Single and 3-line wiring diagrams 5. Applicant to provide AC/DC schematic diagram 6. Applicant to provide a copy of Form G5-1 relay settings and the bench test report of the relays
before PG&E will schedule a pre-parallel inspection of the generating facility (Primary Service requirement)
Parallel Operation Requirements
In order to release this project for parallel operation with the PG&E distribution system, the following tasks are required:
1. Approval of the customer’s 3-line wiring diagrams, control and relay diagrams 2. Approval of relay settings 3. Approval of operation and control sequence descriptions (function description) 4. Approval of customer’s required relay test reports and Form G5-1 5. Pre-parallel inspection 6. Execution of the operating agreement 7. All the required upgrades are completed
8.4 Operating Requirements
TerraVerde Renewable Partners ability to operate the generating facilities at the 200 Industrial Drive, Diamond Springs, CA 95619 is guaranteed only when the PG&E system is in the normal operating configuration and all required protection and regulation equipment is operational. PG&E reserves the right to require the County of El Dorado generators to separate from the PG&E system if required for safety or system stability during an abnormal condition. In particular, the County of El Dorado generator will not be
allowed to operate in parallel with PG&E if the PG&E circuit source feeding the plant is switched to a source configuration different from what was studied in this report.
9. Appendix A – Signage Requirement
Signage Required at AC Disconnect Location
PG&E LOCKABLE VISIBLE
SWITCH
Note: Sign will be permanent and will have a white background with 1½ inch red lettering. This sign should be attached to the Disconnect itself; copies should be attached to any gates or doors which will be used by PG&E personnel to access the disconnect switch.
WARNING GENERATOR INSTALLED ON PREMISES
POSSIBLE DANGER OF
DISCONNECT SWITCH IS LOCATED

Generating Facility Interconnections Electric Rule No. 21 ...

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