Interconnection System Impact Study Report No: T&S Planning 203-064 November 20, 203 Revision 0 British Columbia Hydro and Power Authority British Columbia Hydro and Power Authority 203. All rights reserved.
ACKNOWLEDGEMENTS This report was prepared and reviewed by T&D, Interconnection Planning and approved by both Interconnection Planning and Transmission Generator Interconnections. British Columbia Hydro and Power Authority, 203. All rights reserved. i
Revision Table Revision Number Date of Revision Revised By British Columbia Hydro and Power Authority, 203. All rights reserved. ii
DISCLAIMER OF WARRANTY, LIMITATION OF LIABILITY This report was prepared by the British Columbia Hydro And Power Authority ( BCH ) or, as the case may be, on behalf of BCH by persons or entities including, without limitation, persons or entities who are or were employees, agents, consultants, contractors, subcontractors, professional advisers or representatives of, or to, BCH (individually and collectively, BCH Personnel ). This report is to be read in the context of the methodology, procedures and techniques used, BCH s or BCH s Personnel s assumptions, and the circumstances and constraints under which BCH s mandate to prepare this report was performed. This report is written solely for the purpose expressly stated in this report, and for the sole and exclusive benefit of the person or entity who directly engaged BCH to prepare this report. Accordingly, this report is suitable only for such purpose, and is subject to any changes arising after the date of this report. This report is meant to be read as a whole, and accordingly no section or part of it should be read or relied upon out of context. Unless otherwise expressly agreed by BCH:. any assumption, data or information (whether embodied in tangible or electronic form) supplied by, or gathered from, any source (including, without limitation, any consultant, contractor or subcontractor, testing laboratory and equipment suppliers, etc.) upon which BCH s opinion or conclusion as set out in this report is based (individually and collectively, Information ) has not been verified by BCH or BCH s Personnel; BCH makes no representation as to its accuracy or completeness and disclaims all liability with respect to the Information; 2. except as expressly set out in this report, all terms, conditions, warranties, representations and statements (whether express, implied, written, oral, collateral, statutory or otherwise) are excluded to the maximum extent permitted by law and, to the extent they cannot be excluded, BCH disclaims all liability in relation to them to the maximum extent permitted by law; 3. BCH does not represent or warrant the accuracy, completeness, merchantability, fitness for purpose or usefulness of this report, or any information contained in this report, for use or consideration by any person or entity. In addition BCH does not accept any liability arising out of reliance by a person or entity on this report, or any information contained in this report, or for any errors or omissions in this report. Any use, reliance or publication by any person or entity of this report or any part of it is at their own risk; and 4. In no event will BCH or BCH s Personnel be liable to any recipient of this report for any damage, loss, cost, expense, injury or other liability that arises out of or in connection with this report including, without limitation, any indirect, special, incidental, punitive or consequential loss, liability or damage of any kind. British Columbia Hydro and Power Authority, 203. All rights reserved. iii
COPYRIGHT NOTICE Copyright and all other intellectual property rights in, and to, this report are the property of, and are expressly reserved to, BCH. Without the prior written approval of BCH, no part of this report may be reproduced, used or distributed in any manner or form whatsoever. British Columbia Hydro and Power Authority, 203. All rights reserved. iv
EXECUTIVE SUMMARY the Interconnection Customer (IC), proposes to deliver electric energy from its Parsnip Substation (PRS) to BCH with the Conifex Mackenzie Combined Heat and Power Project. This project consists of one gas turbine/generator at PRS located in the Mackenzie area of British Columbia. The Point of Interconnection (POI) is outside the PRS fence on the BCH s line between PRS and BCH s Morfee station (MFE). The maximum power injection at the POI is 9.6 MW. The proposed Commercial Operation Date (COD) is September st, 204. This report documents the evaluation of the system impact of interconnecting the proposed generating facilities and identifies the required system modifications to obtain acceptable system performance with the interconnection of the subject project. To interconnect the IC s project and its facilities to the BCH Transmission System, this System Impact Study (SIS) has identified the following conclusions: Acceptable equipment loading conditions in the Transmission System were observed under system normal and single contingencies; Acceptable voltage conditions in the Transmission System were observed in the power flow and transient stability studies under system normal and single contingencies; The L368 and L373 line protection settings at MFE will need to be modified; Out of step protection will be required and should be provided by the IC to trip the unit when it becomes unstable; No intentional islanded operation has been arranged for the local area. Anti-islanding protection will be required to prevent the IC s plants from supplying power to potential local loads in this area if an islanded condition does occur; A non-binding good faith cost estimate for the Interconnection Network Upgrades is $ 72 k. The estimated time to complete the Interconnection Network Upgrades is 6 months after project approval. The work required within the IC facilities is not part of Interconnection Network Upgrades. The Interconnection Facilities Study report will provide greater details of the Interconnection Network Upgrade requirements and estimated construction timeline for the interconnection project. British Columbia Hydro and Power Authority, 203. All rights reserved. v
TABLE OF CONTENTS ACKNOWLEDGEMENTS... I REVISION TABLE... II DISCLAIMER OF WARRANTY, LIMITATION OF LIABILITY... III COPYRIGHT NOTICE... IV EXECUTIVE SUMMARY... V.0 INTRODUCTION... 2.0 PURPOSE OF STUDY... 2 3.0 TERMS OF REFERENCE... 2 4.0 ASSUMPTIONS... 3 5.0 SYSTEM STUDIES AND RESULTS... 3 5. STEADY STATE POWER FLOWS... 3 5.2 TRANSIENT STABILITY STUDY... 4 5.3 ANALYTICAL STUDIES... 5 5.4 FAULT ANALYSIS... 5 5.5 TRANSMISSION LINE UPGRADES... 6 5.6 BCH STATION UPGRADES OR ADDITIONS... 6 5.7 PROTECTION & CONTROL AND TELECOMMUNICATIONS... 6 5.8 ISLANDING... 6 5.9 BLACK START CAPABILITY... 6 5.0 OTHER ISSUES... 6 5. COST ESTIMATE AND SCHEDULE... 7 6.0 REVENUE METERING... 7 7.0 CONCLUSIONS & DISCUSSION... 7 APPENDIX A AREA SINGLE LINE DIAGRAM WITH THE IC PROJECT... 9 APPENDIX B MODELS AND DATA... 0 APPENDIX C REVENUE METERING... British Columbia Hydro and Power Authority, 203. All rights reserved. vi
.0 INTRODUCTION The project reviewed in this Interconnection System Impact Study (SIS) is as described in Table below: Table : Summary of Project Information Project Name Conifex Mackenzie Combined Heat and Power Project Interconnection Customer Point of Interconnection (POI) On L368 outside the Parsnip (PRS) substation fence IC Proposed COD Sep st, 204 Type of Interconnection Service NRIS ERIS Maximum Power Injection (MW) 9.6 (Summer) 9.6 (Winter) Number of Generator Units Plant Fuel Gas the Interconnection Customer (IC), proposes to deliver electric energy from its existing Parsnip Substation (PRS) to BC Hydro (BCH) with the Conifex Mackenzie Combined Heat and Power project. The maximum power injection to the BCH system is 9.6 MW. The proposed Commercial Operation Date (COD) is September st, 204. Conifex Mackenzie Combined Heat and Power project is comprised of one synchronous generating unit (CTG-) rated at 2.5 MVA with 0.8 lagging and 0.95 leading power factors. The PRS substation is connected to the BCH system via a 38 kv line L368, and the proposed POI is outside the PRS fence on this line. There is an existing generator STG- of 40.47 MVA connected at PRS which was developed in the Conifex Power Generation Project. The System Impact Study for the Conifex Power Generation Project has been conducted and finished with 33 MW maximum power injection in 202. The study is documented in the study report: TGI-20-I002-SIS Restudy-R. The total power injection at PRS will be increased from 33 MW to 42.6 MW with the addition of the Conifex Mackenzie Combined Heat and Power Project. PRS is a 38/3.8 kv customer owned and operated substation, supplied from the BC Hydro owned Morfee Substation (MFE) via L368. MFE is supplied radially from Kennedy Substation (KDS) via L373. BCH operating authority of L368 ceases at the PRS station perimeter. A sketch of the project interconnection is shown in Fig. The area single line diagram with the IC project can be found in Appendix A. British Columbia Hydro and Power Authority, 203. All rights reserved. of 2
Figure : The Project Interconnection Diagram 2.0 PURPOSE OF STUDY The purpose of this SIS is to assess the impact of the proposed interconnection on the BCH Transmission System. This study will identify constraints and Network Upgrades required for interconnecting the proposed generating project in compliance with the North American Electric Reliability Corporation (NERC) and Western Electricity Coordinating Council (WECC) reliability standards and the BCH transmission planning criteria. 3.0 TERMS OF REFERENCE This study investigates and addresses the overloading, voltage deviation and stability issues of the transmission network in the Mackenzie area as a result of the proposed interconnection. Studied topics include equipment thermal loading and rating requirements, system transient stability and voltage stability, transient over-voltages, protection coordination, operating flexibility and telecom requirements. BCH planning methodology and criteria are used in the studies. The SIS does not investigate operating restrictions and other factors for possible second contingency outages. Subsequent Interconnection Facilities study and BCH s internal network studies will determine British Columbia Hydro and Power Authority, 203. All rights reserved. 2 of 2
the requirements for reinforcements or operating restrictions/instructions for those kinds of events. Any use of firm or non-firm transmission delivery will require further analysis specific to the transmission service that may be requested later and will be reviewed in a separate study. Determination of any upgrades on the IC s facilities is beyond the SIS scope. The work necessary to implement the network improvements identified in this SIS report will be described in greater detail in the Interconnection Facilities Study report for this project. 4.0 ASSUMPTIONS The power flow conditions studied include generation, transmission facilities, and load forecasts representing the queue position applicable to this project. Applicable seasonal conditions and the appropriate study years for the study horizon are also incorporated. The 204 heavy winter, 205 light summer and heavy summer load flow base cases were selected for this study. The study is carried out based on the model, data and information submitted by the IC in July 203. The BCH 204 and 205 system configurations with various load/ generation patterns were used in the study. 5.0 SYSTEM STUDIES AND RESULTS Power flow, short circuit and transient stability studies were carried out to evaluate the impact of the proposed interconnection. Studies were also performed to determine the protection, control and communication requirements and to evaluate possible over-voltage issues. 5. Steady State Power Flows Pre-outage power flows were prepared to assess the impact of the proposed interconnection using defined generation conditions with three basic system load conditions:. 204 heavy winter (HW) load; 2. 205 heavy summer (HS) load; 3. 205 light summer (LS) load. A series of pre-outage power flows is prepared and single contingency studies have been conducted to check if the pre-contingency and post contingency performance including bus voltage and facility loading meet the NERC Mandatory Reliability Standards (MRS) and WECC/ BCH transmission planning criteria under different HW/ LS load conditions. There is no transmission equipment over-loading problem and no voltage violation conditions for the proposed maximum power injection from the IC. A summary of the study results is shown in Table 2. British Columbia Hydro and Power Authority, 203. All rights reserved. 3 of 2
Table 2: Power Flow results (Pre-outage condition: 9.6 MW Injections from Conifex Mackenzie interconnection and 33 MW Injection from Confifex Power Generation project) System Load Condition 204 HW 205 HS 205 LS System Configuration System Normal Loss of L366 Loss of 2L39 System Normal Loss of L366 Loss of 2L39 System Normal Loss of L366 Loss of 2L39 TBN 38 kv Bus Voltages (in per unit) MFE 38 kv KDS 38 kv KDS 230 kv Power flow (in MW) L373 at MFE KDS T 230 kv.0.03.024.055 0.6 60.8 -.02.02.054 28. 33.7.02.03.026.058 0.6 5.4.055.007.0.053 7.6 53 -.07.07.05 3.7 29.6.006.008.02.055 7.7 0.5.037.032.032.076 32. 34.7 -.039.032.076 36.8 30..039.039.036.08 32. 30.4 Note: HW, HS and LS stand for heavy winter, heavy summer and light summer, respectively. 5.2 Transient Stability Study A series of transient stability studies under selected system operating conditions has been performed. The model of the generating project was based on the IC s data submission plus any additional assumptions where the IC s data was incomplete or inappropriate. The IC s dynamic models and parameters are shown in Appendix B. No transient instability has been observed due to the addition of the IC s project based on the studied scenarios and contingencies. A summary of the system stability studies for 205 light summer load conditions is shown in Table 3. Out of step protection is required and should be provided by the IC to trip the generator. The IC must also be able to detect and trip its slipping generator. The expected slip center location is inside the IC s plant. British Columbia Hydro and Power Authority, 203. All rights reserved. 4 of 2
Table 3: Transient Stability Results (Pre-outage condition: 205 light summer load conditions with 9.6 MW Injections from Conifex Mackenzie interconnection and 33 MW Injection from Confifex Power Generation project) Case Outage 3 Fault Location Fault Clearing Time (Cycles) Max Rotor Swing (Deg.) Close End Far End STG- CTG- Minimum Transient Voltage (p.u.) Comments 2 3 4 5 6 7 8 5L7 ( (KDS KDS 5C3W) 2L39 (KDS MML) 2L39 (KDS MML) 2L320 (KDS KMI) 2L320 (KDS KMI) L366 (MFE-TBN) L366 (MFE-TBN) MFE T 38/25kV 9 FFI RT 0 MFE 25 kv Feeder Close to KDS Close to KDS Close to MML Close to KDS Close to KMI Close to MFE Close to TBN MFE 38 kv FFI T Side nearest BCH KDS 4 KDS 5 KDS 8 KDS 5 KDS 8 MFE 0 MFE 0 MFE 38 8 FFI 38 0 KDS5C3W 4 8 6 N/A 0 5 N/A 4 3 N/A 0 2 N/A 0 2 N/A 78 5 N/A 60 2 N/A >00 26 N/A 89 5 25 kv 8 N/A 9 6 > 0.95 @ PRS 38kV > 0.95 @ PRS 38kV > 0.95 @ PRS 38kV > 0.95 @ PRS 38kV > 0.95 @ PRS 38kV 0.94 @ PRS 38kV > 0.95 @ PRS 38kV 0.85 @ PRS 38kV 0.92 @ PRS 38kV > 0.95 @ PRS 38kV Acceptable Acceptable Acceptable Acceptable Acceptable Acceptable Acceptable Unacceptable Acceptable Acceptable Note: The loss of synchronism of Conifex Power Generation unit STG- observed for three phase faults on MFE T was identified / addressed in the previous Conifex Power Generation project interconnection study by an Out-of-step protection to trip STG-. 5.3 Analytical Studies No unacceptable temporary or transient over-voltage issues were identified. 5.4 Fault Analysis The short circuit analysis for the System Impact Study is based upon the latest BCH system model, which includes project equipment and impedances provided by the IC. The model included higher queued projects and planned system reinforcements but excluded lower queued projects. Thevenin British Columbia Hydro and Power Authority, 203. All rights reserved. 5 of 2
impedances, including the ultimate fault levels at POI, are not included in this report but will be made available to the IC upon request. BCH will work with the IC to provide accurate data as required during the project design phase. 5.5 Transmission Line Upgrades There are no line overload conditions identified in the BCH system. It is the IC s responsibility to ensure the IC s lines will be adequate to deliver the maximum injected power into the BCH system. 5.6 BCH Station Upgrades or Additions There are no BCH station upgrades or additions identified for the IC s project. 5.7 Protection & Control and Telecommunications BCH is responsible for the work at MFE to revise L368 and L373 line protection settings. The IC should provide the required telemetry and status information via a Distributed Network Protocol 3 (DNP3) IED, in accordance with BCH s 60 kv to 500 kv Technical Interconnection Requirements for Power Generators (TIR). Necessary updates and modifications will be needed at the BCH s control centers. 5.8 Islanding Islanded operation is not arranged for this project to serve other customers. Power quality protection will be required at the IC site to detect abnormal system conditions such as under/over voltage and under/over frequency and subsequently isolate the IC s facilities from the BCH system. The settings of these protective relays must conform to existing BCH practice for generating plants so that the generator will not trip for normal ranges of voltages and frequencies. 5.9 Black Start Capability BCH does not require the proposed project to have black start (self-start) capability. However, if the IC desires their facilities to be energized from the BCH system, the IC is required to apply for an Electricity Supply Agreement.. 5.0 Other issues British Columbia Hydro and Power Authority, 203. All rights reserved. 6 of 2
None. 5. Cost Estimate and Schedule A non-binding good faith cost estimate for the Interconnection Network Upgrades is $ 72 k. Any work required in the IC s site is not a part of Network Upgrades. The estimated time to complete the Interconnection Network Upgrades is 6 months after project approval. The Interconnection Facilities Study report will provide greater details of the Interconnection Network Upgrade requirements and estimated construction timeline for the interconnection project. 6.0 REVENUE METERING Remotely read point of metering is required. The Point of Metering (POM) should be located on the high side of the generator transformer, T-. The IC should supply and install three voltage transformers (VTs) and three current transformers (CTs) approved by Measurement Canada and suitable for their generation/load. Revenue class meters approved and sealed by Measurement Canada (MC) will be installed at the IC generating site. The location of the Point of Metering (POM) is subject to approval by the BCH Revenue Metering Department. Planning, design, installation and commissioning of metering should be coordinated between the IC and BCH. Responsibilities and charges between the IC and BCH shall be in accordance with Sections 0. and 0.2 of BCH Requirements for Remotely Read Load Profile Revenue Metering. All meters will be supplied and maintained by BCH. Main and backup meters will use the same current transformers (CTs) and voltage transformers (VTs) secondaries and shall not share the secondary with any other equipment. The meter will be leased to the IC by BCH. The IC will supply MC approved CTs and VTs, dedicated communication line for the POM and additional equipment as shown in Appendix E. A communications line is required for remote reading of the main and backup meters. The IC will provide a line and a connector that should be installed inside the meter cabinet. Alternative technologies may be used and cellular communication appears to be acceptable. However these must be discussed and pre-approved by BCH before equipment purchase. A non-binding good faith cost estimate for Revenue Metering is $ 44 k, which is not included in the total cost for the Interconnection network upgrades. 7.0 CONCLUSIONS & DISCUSSION In order to interconnect the subject project to the BCH Transmission System at the POI, this SIS has identified the following issues and requirements: Acceptable equipment loading conditions in the Transmission System were observed in the power flow analysis for the subject project under system normal and single contingencies; British Columbia Hydro and Power Authority, 203. All rights reserved. 7 of 2
Acceptable voltage conditions in the Transmission System was observed in the power flow and transient stability studies under system normal and single contingencies; Revision of L368 and L373 line protection settings at MFE; Out of step protection is required and should be provided by the IC to trip the slipping generator; No intentional islanded operation has been arranged for the local area. Anti-islanding protection will be required to prevent the IC s plants from supplying power to potential local loads in this area if an islanded condition does occur. British Columbia Hydro and Power Authority, 203. All rights reserved. 8 of 2
Conifex Mackenzie Combined Heat and Power Project APPENDIX A Area Single Line Diagram with the IC Project PRS 3G PRS 38 Conifex Makenzie-Combined Heat and Power Project PRS 3G2 PRS 25-3 MFE 38 MFE 25V MFE 25 KDS 500 PCN 500 L368 KDS 230 5L3 KDS 38 T KDY 5C3W PRS 25- T4 5L7 FFI 38 FFI RT L373 T3 2L320 KMI 230 MML 230 MML 25T FCC 3 FCC 38 TBN 38 2L39 MML 25T2 TBN 3 L366 British Columbia Hydro and Power Authority, 203. All rights reserved. 9 of 2
APPENDIX B Models and Data General Information: Applicant Name: Project Name: Conifex Mackenzie Combined Heat and Power Project Power Flow Data: Generator (CTG-): Rated MW = 0 MW, Rated MVA = 2.5 MVA, X"d = 0.63, pf = 0.8 lagging/0.95 leading Transformer (2T3 and T-): 2T3: 38 kv YG/25 kv YG/3.8 kv D, load, ±6 x 0.63%, Natural cooled rating = 5.5 MVA, Stage cooling = 20 MVA, Maximum rating = 28 MVA, Z=0.36% T-: 25 kv YG/3.8 kv D, off-load, ±2 x 2.5%, Natural cooled rating = 8.4 MVA, Maximum rating = 4. MVA, Z=6.5% Customer Owned Transmission Line: 25 kv, Line length = 2.59 km (700 feet of 477 MCM ACSR and 6800 feet of 336 MCM ACSR O/H), R = 0.07 p.u., X = 0.8 p.u. Charging = 0.00006 p.u. Dynamic Data: GENROU --- CTG- (2.5 MVA, 3.8 kv base) T'd0 T''d0 T q0 T''q0 H DAMP Xd Xq X'd X'q X''d Xl S.0 S.2 8.66 0.044 0.87 0.08.86 0.68 0.86 0.98 0.86 0.63 0.084 0.279 0.958 ESAC8B --- CTG- Exciter T R K P K I K D T D K A T A V RMAX V RMIN T E K E E S E E 2 S E2 0.0 30 25 5 0.0.0 0 8.3 0.0 0.222.0 4.26 0.2 5.69 0.457 British Columbia Hydro and Power Authority, 203. All rights reserved. 0 of 2
APPENDIX C Revenue Metering Revenue class meters approved and sealed by Measurement Canada (MC) shall be installed on the output of the generator. As per federal regulations, the meter should be periodically removed and reverified in a MC authorized laboratory. The CTs and VTs used on the metering scheme shall also be of a model/type approved by Measurement Canada. The location of the Point-of-Metering (POM) is subject to approval by BC Hydro s Revenue Metering department. The planning, design, installation and commissioning of the point of metering should be coordinated between the power generator and BC Hydro s Revenue Metering Department. The responsibilities and charges between the Interconnection Customer and BC Hydro shall be in accordance with Section 0 (0. and 0.2) of BC Hydro s Requirements for Remotely Read Load Profile Revenue Metering. For a complete list of tasks, see table on pages 23-25: https://www.bchydro.com/content/dam/bchydro/documents/requirements_for_remotely_read_load_ profile_metering_jun2004.pdf All meters will be supplied and maintained by BC Hydro. Main and backup meters will use the same CTs and VTs secondaries and shall not share the secondary with any other equipment. The main meter will be leased to the Interconnection Customer by BC Hydro. The revenue class instrument transformers (CTs and VTs units) will be supplied by the Interconnection Customer and must be a MC approved model. A list of approved models is available at the MC website under Notice of Approval Database Section. The remote read load profile revenue metering equipment should be in accordance with BC Hydro Requirements for Remotely Read Load Profile Revenue Metering. The latest version of this document is published at BC Hydro webpage under Forms and Guides. Main and backup bi-directional load profile interval meters are required to measure the power received and the power delivered by BC Hydro (BCH) during each 30 minute time period. The meters will be programmed for 5 minute intervals and will be remotely read each day by the BCH Enhanced Billing Group using MV-90 software. The POM requires a dedicated communications line that is provided by the Customer. This line should be available on the meter cabinet and it is for revenue metering use only. The communication line provided could be a protected landline or a wireless alternative approved by BC Hydro. The landline should be installed in accordance with IEEE Standard 487 Guide for the Protection of Wire-Line Communication Facilities Serving Electric Power Stations. If there is digital cellular phone coverage for data (IP), due to IT security reasons, BC Hydro will supply the wireless communications equipment at an incremental cost to the Interconnection Customer. A 3--element metering scheme with 3 CTs and 3 VTs connected L-N (Grd) will be used when the POM is located on the BC Hydro side of the power transformer. If the POM is located on the low side of the power transformer (Power Generator side of the power transformer) and the Power Generator (PG) installation is a three phase, three wire, delta connection, or a three phase, four wire, WYE with a resistance or impedance grounded neutral (treated as a DELTA connection), a 2-element metering scheme with 2 CTs and 2 VTs connected L-L will be used instead. For generation applications, all instrument transformer compartment doors shall be key interlocked with a BC Hydro side disconnect device and an Interconnection Customer side disconnect device(s). The key interlocks shall prevent opening instrument transformer compartment door(s) unless all disconnect devices are visibly open. Where the POM is on the Interconnection Customer side of the power transformer, the BC Hydro side disconnect device shall be on the BC Hydro side of the power transformer to insure that no-load losses. If the impedance and losses between the POM and the Point of Delivery or Receipt (PODR) are significant, the meters will be programmed to account for the line and/or transformer losses between British Columbia Hydro and Power Authority, 203. All rights reserved. of 2
the POM and PODR. The Interconnection Customer shall provide the line parameters data and the power transformer testing report data signed and stamped by a professional engineer. Where two or more Interconnection Customers or one Interconnection Customer with more than one generating station/generator share a private power line to connect to the BCH system, a main POM located in the Point-of-Interconnection (POI) will be required, as well as an individual POM on each one of the generating stations/generators. During the planning phase, BC Hydro s Revenue Metering Department should be contacted to discuss costs and specifics of the project. The Interconnection Customer should prepare and submit drawings showing the single line diagram (SLD), station lay-out and informing the proposed metering scheme, the length of the secondary cables needed (between CT/VT and the meter cabinet), meter cabinet location, CTs and VTs location, model/maker, connections, and MC Approval numbers, as well as any other related documentation. Information required in the design stage includes:. Length of secondary cables 2. CT and VT models and approvals from Measurement Canada and if they come with a second set of secondaries 3. Single Line Diagram showing CTs, VTs, cabinets, all generating stations connecting to the POI 4. Identify whether revenue metering cabinets are indoors or outdoors - implication on whether cabinets need to be insulated 5. Communication medium contemplated to relay revenue metering data 6. 3-line diagram of the interconnection of the revenue metering CT & VT 7. Scaled Site Plan showing the relative location of the meter cabinet to the CT & VT (drawing showing the footprint for the sub) 8. Private power line parameters data and/or the power transformer testing data signed and stamped by a professional engineer 9. A set of manufacture switchgear drawings showing the installation of the revenue metering CT & VT (ensure the installation of the metering CT & VT complies with section 5.4 of BCH Requirements for Remotely Read Load Profile Revenue Metering, published at BCH website) 0. A simplified version of the lockout access steps to the revenue metering CT & VT (if already available). Verification of dedicated 20V AC 5A circuit for the meter cabinet - as per section 6.4 of BCH requirements 2. Contact name/phone on site for equipment/material delivery. 3. Royal Mailing Address for the site (normal mailing address) 4. Interconnection Customer Billing Information 5. A copy of Measurement Canada issued Certificate of Registration for the Interconnection Customer 6. Operational Site Access for BC Hydro Meter Tech (for metering installation, maintenance, etc.) The BC Hydro s Revenue Metering department can be contacted at: metering.revenue@bchydro.com. British Columbia Hydro and Power Authority, 203. All rights reserved. 2 of 2