Bid Package - Saline Middle School Roof-Integrated Solar Array Installation 2 of 2.pdf

PDF 5 MB Posted Mar 22, 2024

Attached to: ROOF-INTEGRATED SOLAR ARRAY INSTALLATION
Solicitation number: RFP - SAL - 240000001748
Issued by: Washtenaw County, St. Louis City, Michigan

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Written by GovTribe AI · Apr 3, 2024

This document contains information related to the Roof-Integrated Solar Array Installation project in Michigan, involving Washtenaw County and St. Louis City. The project requires the installation of a 540 kW AC (757.35 kW DC) solar array integrated into the roof of the Saline Middle School, including equipment such as photovoltaic modules, inverters, monitoring systems, and switchgear. The project must adhere to NEC 2023 code requirements and includes IEEE 1547-2018 compliant inverter protection settings. The project timeline is estimated at 6-12 months following receipt of full payment.

The pricing terms are not provided, but the document indicates that the project may require a System Impact Study due to the size and location of the system, as well as coordination with existing affected systems. The project is funded by local sources, and any set-asides or incumbent contractors are not specified. The document provides detailed technical requirements, interconnection procedures, and contact information for the utility (DTE Electric) throughout the project lifecycle.

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DTE Electric: Interconnection Agreement: Attachment A: Construction Agreement

EXAMPLE SCOPE

Appendix A: Scope and Estimate

Industrial/Generation Relaying:

To meet the Level # requirements, both an interconnection protective relay must be used and an anti-islanding scheme must be provided.

The relay must be selected from our approved list of relays for interconnection protection, though a SEL 751 is recommended. It must provide three phase over/under voltage and over/under frequency protection for the installation and be separate from dedicated generator protection relays. The relay must have dc power from a separate reliable source; such as a battery or UPS. DTE Electric Relay Engineering will develop the settings for the functions described above.

The customer will be responsible for the purchase, installation, calibration and testing of this new relay and any desired backup relays.

This relay must trip a device open, thus breaking parallel operation of the generators with the DTE Electric system, for adverse conditions or relay failure. It is at the customer’s discretion which device they intend to trip.

Anti-islanding protection must be provided, as required from XXXX to XXXX and from XXXX to XXXX Provision of Communications modules at each location; XXXX, XXXX and XXXX.

These devices will communicate over either a fiber, microwave, radio or Ethernet private communications network.

Customer will install all equipment at the customer owned XXXX end, including all tie ins and conduit routing.

The customer must provide DTE with drawings showing the new relay installation; including One lines, three-lines and schematics to show the complete end to end installation including trips.

These drawings must be approved, prior to any construction. Customer must closely coordinate with DTE for the installation of the DTE equipment required for anti-islanding protection, network communications and SCADA.

An on-site witness test by DTE technicians will need to be accomplished, prior to final operation to ensure protection operates as designed.

Customer will be responsible for configuring the connection to the DTE Interconnection Gateway on site as per DTE provided standards and point mappings

DTE will provide an indoor enclosure containing the following equipment:

XXXXX

Developer will then be responsible to install this enclosure and to provide all auxiliary power, control and communication connections to this enclosure, including connections to the new communications enclosure.

Note: the trip connection must be installed in parallel to the existing trip locations and the old transfer trip scheme can NOT be decommissioned until the new scheme has been installed and fully tested, if applicable. Upon completion of installation of both this box at the customer location and the work at XXXXX and XXXX, DTE Personnel will work with XXXXX to supervise, troubleshoot and commission the new transfer trip scheme.

SCADA:

A DTE SCADA technician will need to visit the site to configure communications and point configurations in the RTU, terminate any new data points, and check in locally and with SOC. For this location where SCADA communications with SOC will be via IP based communications through a medium selected from the telecommunications section below.

Estimated Cost for equipment and configuration at XXXXX site = $$$$$

Substations:

DTE Substation Work:

DTE will remove XXXXX and install XXXXXX at XXXXX and XXXX. DTE will test equipment and commission at XXXXX and XXX.

Estimated Cost for the above DTE Substation work = $$$$$.

Telecommunication

DTE will install and configure one of the following options

• Option 1: Interconnect XXXX to XXXX via XXXXX. ~## mi @ $$$k per mile in accordance with DTE Communications Design.

Cost of Option 1: $$$$

• Option 2: Install XXXXXX. Customer coordination to locate XXXX at XXXXX site will be required.

Cost of Option 2: $$$$ plus $$/year O&M for XXXXX

Total Project Estimate:

Option 1: (Description) $$$$K

Option 2: (Description) $$$$K

Communication Diagram: EXAMPLE

Primary Services / Pert / Commissioning:

Site visits, Functional Testing verifications, and Commission Testing with DTE field service personnel will need to be coordinated.

Additional Configuration, Communications, Protection Settings:

27 - x2 59 - x2 32 – x1 81o – x1 81u – x1

Undervoltage Elements 27 element (3 phase)

Pick Up = 0.88 x Vnm Delay = 2000 ms or 2s This is intending to trip when export voltage falls below 88% Nominal Voltage Per IEEE 1547 Section 4.2.3

27 element (3 phase) Pick Up = 0.5 x Vnm Delay = 167 ms or 10 cycles This is intending to trip when export voltage falls below 50% Nominal Voltage Per IEEE 1547 Section 4.2.3

Overvoltage Elements

59 element (3 phase) Pickup = 1.1 x Vnm Delay = 1000 ms or 1s This is intending to trip when export voltage rises above 110% Nominal Voltage Per IEEE 1547 Section 4.2.3

59 element (3 phase) Pickup = 1.2 x Vnm Delay = 167 ms or 10 cycles This is intending to trip when export voltage rises above 120% Nominal Voltage Per IEEE 1547 Section 4.2.3

Under Frequency

81 element (3 phase) Pickup = 57 Delay = 167 ms or 10 cycles This is intending to trip when export frequency drops below 57 Hz Per IEEE 1547 Section 4.2.4

Over Frequency 81 element (3 phase)

Pickup = 60.5 Delay = 167 ms or 10 cycles This is intending to trip when export frequency rises above 60.5 Hz Per IEEE 1547 Section 4.2.4

Additional Notes:

The trip actuation should include the power element, all over/undervoltage elements, all over/under frequency elements and RELAY FAIL with a logical OR for all of the elements.

Customer should consider the use of an inhibit input for the trip. This could be based on a generator running signal or on the position of the isolating 52 Breaker’s. This would disable the protection in the event that the generator is not in use. **THIS IS NOT A

REQUIREMENT, BUT A RECOMMENDATION. **

All other elements may be set freely by customer for their needs. Please forward a copy of the final settings file for the relay after programming, testing, and verification is complete.

DTE requires trips (27,32,59,81ou) shall be programmed to one dedicated Trip

OUTPUT with a note stating that “DTE Required Output for Limited Sell Back”

Appendix B: Project Schedule

Interconnection Project:

____ DE-####/DE-#### – XXXXXXXXXXX_______

Project Schedule:

All activities will begin after the Fully Executed Construction Agreement and all monies have been received.

## (XXXX) months estimated

Coordination required with Affected systems that may affect schedule:

Operation and coordination with ITC at shared station sites

SCADA – Approximately ## months from receipt of order per the manufacturer. This time includes XXXXXX

Telecom – ## months to design and build XXXXXX.

Substation Design - ## months to XXXXXX.

This estimate timeline will be updated at the completion of design activities.

Commissioning timeline will be dependent on required shutdowns at each site and the coordination required to complete the work. Coordination with customer site will be required for final commissioning and will be scheduled at a mutually agreed upon time after construction completion.

Total time line is ## months following receipt of payment.

________XXXXXXX__________________, (Project Developer), and The DTE Electric Company, as required by the DTE Electric [Project] Construction Agreement for Generator Interconnection To DTE Electric’s Distribution System dated MM/DD/YYYY agree to the above stated Project Schedule for the Interconnection Project.

ATTACHMENT B: COMMISSIONING CHECKLIST

DE-XXXX Project Name Non-Export Test Plan

Project Address

Name of testing organization: __________________________________________________________

Name of Tester: _____________________________________________________________________

Test Date: __________________________________________________________________________

CUSTOMER SCOPE OF WORK TO BE TESTED

• Install SEL-751 relay to implement reverse power (32) function and breaker fail

• Implement inverter protection settings IEEE1547-2018, Including MISO ride through

TESTING

Instruction to tester: Clearly Indicate initials in each PASS/FAIL box

SEL 751 Relay Fail Test:

• Simulate failure of SEL 751 relay

*Customer is recommended to integrate relay fail alarm into internal site alarming.

Comments

SEL 751 Loss of Potential Test

• Simulate loss of potential sensing to SEL-751 relay

PASS FAIL

SEL 751 Fail Alarm Status

SEL 751 Relay trips and locks out Breaker XXXX (Tested breaker name as in drawings)

On loss A phase PT input SEL 751 Relay trips and locks out Breaker XXXX

On loss B phase PT input SEL 751 Relay trips and locks out Breaker XXXX

On loss C phase PT input SEL 751 Relay trips and locks out Breaker XXXX

SEL 751 Relay 32 Function Test:

• Inject current into SEL 751 relay to simulate reverse power condition

SEL 751 Breaker Failure Function Test:

• Inhibit Breaker XXXX status verification back to SEL 751. Initiate trip from SEL 751 to Breaker

XXXX verify ESTOP of all Inverters

Inverter settings verification functionality

• Open Breaker XXXX, Verify Open, Close Breaker XXXX

SEL 751 Relay trips and locks out Breaker XXXX when there is reverse power

All inverters execute ESTOP on breaker fail from SEL 751

When Breaker XXXX Open, verify 0 Voltage on all phases after 2 seconds

On Breaker XXXX close verify inverter Synchronization check

On Breaker XXXX close verify that inverter system does not re-energize prior to 300 seconds

On Breaker XXXX close, and after 300 seconds of de-energization, verify that the inverter system output linearly ramps for no less than 300 seconds before reaching rated output

• Verify the following inverter settings are applied

Voltage Relay Settings

Shall Trip Function Allowable Setting

Voltage (per unit of nominal voltage)

Clearing Time (Seconds)

Overvoltage 1 1.20 0.16

Overvoltage 2 1.10 2.0

Undervoltage 1 0.70 2.0

Undervoltage 2 0.45 0.32

Frequency Relay Settings

Shall Trip Function Allowable Setting

Frequency (Hz) Clearing Time (Seconds)

Overfrequency 1 62.0 0.16

Overfrequency 2 61.2 2.0

Underfrequency 1 58.5 2.0

Underfrequency 2 56.5 0.16

Enter Service Criteria Default Settings

Permit Service Enabled

Applicable Voltage Within Range

Min. Value 0.917 p.u.

Max. Value 1.05 p.u.

Frequency Within Range

Min. Value 59.5 Hz

Max. Value 60.1 Hz

Tester Signature

Date

DE-#### XXXXX Test Plan

XXXXX

Name of testing organization: __________________________________________________________

Name of Tester: _____________________________________________________________________

Test Date: __________________________________________________________________________

CUSTOMER SCOPE OF WORK TO BE TESTED

• Install SEL-751 relay to implement reverse power (32) function and breaker fail

• Implement inverter protection settings IEEE1547-2018, Including MISO ride through

TESTING

Instruction to tester: Clearly Indicate initials in each PASS/FAIL box

SEL 751 Relay Fail Test:

• Simulate failure of SEL 751 relay

*Customer is recommended to integrate relay fail alarm into internal site alarming.

SEL 751 Loss of Potential Test

• Simulate loss of potential sensing to SEL-751 relay

SEL 751 Fail Alarm Status

SEL 751 Relay trips and locks out PB1 breaker

On loss A phase PT input SEL 751 Relay trips and locks out PB1 breaker

On loss B phase PT input SEL 751 Relay trips and locks out PB1 breaker

On loss C phase PT input SEL 751 Relay trips and locks out PB1 breaker

SEL 751 Relay 32 Function Test:

• Inject current into SEL 751 relay to simulate reverse power condition

SEL 751 Breaker Failure Function Test:

• Inhibit PB1 breaker status verification back to SEL 751. Initiate trip from SEL 751 to PB1 Breaker verify ESTOP of all Inverters

Inverter settings verification functionality

• Open PB1 breaker, Verify Open, Close PB1 breaker

SEL 751 Relay trips and locks out PB1 breaker when there is reverse power

All inverters execute ESTOP on breaker fail from SEL 751

When PB1 breaker Open, verify 0 Voltage on all phases after 2 seconds

On PB1 breaker close verify inverter Synchronization check

On PB1 breaker close verify that inverter system does not re-energize prior to 300 seconds

On PB1 breaker close, and after 300 seconds of de-energization, verify that the inverter system output linearly ramps for no less than 300 seconds before reaching rated output

• Verify the following inverter settings are applied

Voltage Relay Settings

Shall Trip Function Allowable Setting

Voltage (per unit of nominal voltage)

Clearing Time (Seconds)

Overvoltage 1 1.20 0.16

Overvoltage 2 1.10 2.0

Undervoltage 1 0.70 2.0

Undervoltage 2 0.45 0.32

Frequency Relay Settings

Shall Trip Function Allowable Setting

Frequency (Hz) Clearing Time (Seconds)

Overfrequency 1 62.0 0.16

Overfrequency 2 61.2 2.0

Underfrequency 1 58.5 2.0

Underfrequency 2 56.5 0.16

Enter Service Criteria Default Settings

Permit Service Enabled

Applicable Voltage Within Range

Min. Value 0.917 p.u.

Max. Value 1.05 p.u.

Frequency Within Range

Min. Value 59.5 Hz

Max. Value 60.1 Hz

Power limiting setting: ## KW

Tester Signature

Date

DTE Electric: Parallel Operating Authorization Page 1 of 3

PARALLEL OPERATING AUTHORIZATION

This Parallel Operation Authorization (“Authorization”) is entered into on _{CurrentDate) by _DTE Electric Company_(the “Utility”), _{full_name: Customer Contact Information}_ (the “Applicant”), and (if applicable under Paragraph 5) _{full_name: Customer Contact Information}_ (the “Property Owner”) with project number {ProjectNumber} assigned by Utility.

I. RECITALS

A. Applicant has completed all of the requirements of the Interconnection Agreement entered into on _{InterconnectionAgreeementDate) and is subject to all operating requirements incorporated into the Interconnection Agreement and in R460.958 and subject to R460.978.

B. The Utility has successfully commissioned the Project on {projectCommissioningDate}

C. For purposes of this Authorization, “interconnect” means establishing a connection between a non-utility generating resource (in this case, the “Applicant Facility”) and Utility’s distribution system. “Operate in parallel” means generating electricity from a non-utility resource (in this case, the Applicant Facility) that is connected to Utility’s system. In all cases, terms shall have the meaning as defined in the Standards.

D. Interconnection of the Applicant Facility with Utility’s distribution system is subject to this Authorization, the Application, the Interconnection Procedures, the Standards and utility tariffs approved by the MPSC, as applicable.

E. This Authorization does not address any purchase or sale of electricity between Utility and Applicant nor does it create any agency, partnership, joint venture or other business arrangement between or among Utility, Applicant and/or Property Owner.

DTE Electric: Parallel Operating Authorization Page 2 of 3

II. AGREEMENT

NOW THEREFORE, in consideration of the above recitals, the mutual covenants contained herein and for good and valuable consideration, the Parties agree as follows:

1. Description of Applicant Facility

1.1 The Facility is Authorized to operate under the following ratings, which shall not be changed without a new Interconnection Application:

Approved System Output: {data: Approved Capacity field 2}

(AC) kW

Total DC Nameplate Output: {data: DC Total Nameplate} (DC) kW Total AC Nameplate Output: {data: AC Total Nameplate} (AC) kW Inverter Power Limited Output/Export Capacity:

{data: Inverter Power Limited Output Formula field}

(AC) kW

Photovoltaic/Solar (“PV”) Array Rating: {data: PV System Nameplate Rating Output Formula field}

(DC) kW

Photovoltaic/Solar (“PV”) CEC Rating: {data: PV System CEC Rating Output Formula field}

(AC) kW

Wind Turbine (WT) Rating: {data: "System Rating, Wind field"}

(AC) kW

Hydroelectric Turbine (HT) Rating: {data: "System Rating, Hydro field"}

(AC) kW

Fuel Cell (FC) Rating: {data: "System Rating, Fuel Cell field"}

(AC) kW

Other (specify type and rating): {data: "System Rating, Other field"}

(AC) kW

Storage System DC Output: {data: Storage System DC Rating field}

(DC) kW

Storage System AC Output: {data: Storage Inverter AC Capacity field}

(AC) kW

Stored Energy: {data: Stored Energy Formula field} kWh

Storage System Modes: {data: Storage Backup AND Export field}

Service Type: {data: Electric Service Wiring Configuration} Voltage Level: {data: Generator AC Output Voltage} Equipment Specifications:

PV System: {pv_system_equipment: PV System, minimal}{data: Generator Type Describe- Combo} {data: Generator Type Describe-Other}{data: Inverter not Listed - Number of Modules} {data: Inverter not Listed - Module Manufacturer} {data: Module Model Name} {data: Number of Inverters} {data: Manufacturer} {data: Model Name}

DTE Electric: Parallel Operating Authorization Page 3 of 3

Solar & Storage System Inverters: {data: Are solar and storage system connected behind a single inverter or separate inverters} Energy Storage System: {energy_storage_system_equipment: Energy Storage System, minimal} Battery: {data: Energy Storage System Quantity (units)} {data: Energy Storage System Manufacturer} {data: Energy Storage System Model 2} Inverter: {data: Storage System Inverter Quantity} {data: Storage System Inverter Manufacturer} {data: Storage System Inverter Model}

1.2 Applicant Facility Location:

{address_multiline: Physical Site Service Adress}

1.3 Applicant’s Utility service account number: _{data: DTE Service Account}_

Property Owner’s Utility service account number (if applicable): ____________

UTILITY

By: {Manager Sign} (Duly Authorized Signature)

{full_name: Manager Name} (Print or Type Name)

Title: {data: Manager Title}

Date: {CurrentDate}

APPENDIX G: CONTACT LIST

[PROJECT NAME]

CONTACT LIST

Normal Operations and Emergency Switching

GENERAL

Switching and clearance procedures for DTE Energy Company (‘DTE”) and the Company Name provide important documentation to ensure safe working conditions and orderly and reliable service when work is required on the Interconnection Facilities.

PROCEDURE

1. Emergency Switching Procedure:

Operating Authority for the Company Name will be handled by the following "Priority Contact List."

NAC Contact List Name Facility Contact Number

a. Contact Name 1 (Work) (XXX) XXX-XXXX

b. Contact Name 1 (Cell) (XXX) XXX-XXXX

c. Contact Name 2 (Work) (XXX) XXX-XXXX

d. Contact Name 2 (Cell) (XXX) XXX-XXXX

Operating Authority for DTE will be the System Controller located in Detroit, Michigan.

Contact the DTE Energy SCC Outage Scheduler at [email].

2. Tag Points:

Normal points of separation between the DTE and Systems will be the DTE 277/480 Volt Metering Potential Secondary fuses or knife switch and the Substation Name, high side switching device.

NOTE: DTE work may require the use of DTE Energy Workers Protection Tags and DTE locks on points of separation tag points as can be installed.

3. Scheduled Outage Procedure:

Request initiated by the

Personnel from the Contact List will contact the DTE System Control Scheduler to make the necessary arrangements and to agree on the switching procedures.

Request initiated by DTE.

Scheduling Authority for DTE will be the System Control Scheduler located in Detroit, Michigan.

Contact numbers are either (XXX) XXX - XXXX or (XXX) XXX - XXXX.

The DTE System Control Scheduler will contact the Contact List Personnel to make necessary arrangements and to agree on switching procedures.

NOTE: Each authority will attempt to provide a minimum of 10 workday’s notice on scheduled outage requests. Emergent or imminent equipment failure outages will be handled on an as needed basis.

4. Connection/Reconnect Procedure

Personnel from the Contact List shall contact the DTE Control Center to receive permission prior to connecting generation with DTE Energy system. Generation facilities may not be permitted to connect when the DTE Energy system is in an abnormal condition due to unscheduled outages.

IN WITNESS WHEREOF, the Parties hereto have executed this Agreement as of the Effective Date identified below.

OFFICIAL COMPANY NAME DTE ENERGY COMPANY

By: ___________________________________ By: __________________________

Title: __________________________________ Title: _________________________

Effective Date:

APPENDIX H: INITIAL REVIEW SCREENS

Application Review Screens will be utilized during the application process and are used to inform applicants of an application deficiency or inconsistency or may indicate a critical issue that would prevent compatibility with the DTE Electrical System These screens include review of the one-line and three-line diagrams for compliance with DTE’s SIM and consistency between the site plan, equipment information and application submission materials and a review of the customer information and contact information for accuracy

Design and Safety Screens will be utilized throughout the process if conditions are noted that will introduce safety or design incompatibilities or if other process such as method of service are required before the interconnection can continue.

Additional screens for specific program participation will be contained in program specific procedures.

The initial review screens are all of the following:

i. The entire proposed DER, including all aggregated site generation and point or points of interconnection, must be located within the electric utility’s service territory.

ii. For interconnection of a proposed DER to a radial distribution circuit, the aggregated generation, including the proposed DER, on the circuit may not exceed 15% of the line section annual peak load as most recently measured or calculated if measured data is not available. A line section is that portion DTE’s distribution system connected to a customer bounded by automatic sectionalizing devices or the end of the distribution line. The electric utility shall consider 100% of applicable loading, if available, instead of 15% of line section peak load for level 1 and 2 DER, except in situations where the distribution circuit has high penetration of DER and where addition of the DER creates voltage or operability issues. This screen does not apply to level 1 and level 2 non-export DER applications, except in situations where the distribution circuit has high penetration of DER and addition of the non-export DER creates voltage or operability issues.

iii. For interconnection of a proposed DER to the load side of network protectors, the proposed DER must utilize an inverter-based equipment package and, together with the aggregated other inverter-based DERs, may not exceed the smaller of 5% of a network’s maximum load or 50 kWac. The DER must not provide reverse power flow into the network protector under any conditions.

iv. The proposed DER, in aggregation with other DERs on the distribution circuit, may not contribute more than 10% to the distribution circuit’s maximum fault current at the point on the primary voltage nearest the proposed point of common coupling. This screen does not apply to level 1 applications, except in situations where the addition of the DER would render the protection scheme inoperable and to be modified to be able to continue to operate as designed.

v. The proposed DER, in aggregate with other DERs on the distribution circuit, may not cause any distribution protective devices and equipment or interconnection customer equipment on the system to exceed 87.5% of the short circuit interrupting capability. An interconnection may not be proposed for a circuit that already exceeds 87.5% of the short circuit interrupting capability. Distribution protective devices and equipment include, but are not limited to, substation breakers, fuse cutouts, and line reclosers. This screen does not apply to level 1 applications except in situations where the addition of the DER would require the interrupting equipment to be modified to not improperly operate.

vi. If the type of electrical service provided to the applicant, including line configuration and the transformer winding and connection limits the potential of the DER creating over-voltages on the electric utility’s distribution system due to a loss of ground during the operating time of any anti-islanding function or during any fault condition. Projects implementing 3 phase ganged isolation that operate on ground detection, loss of phase detection, open phase detection or 3V0 protection and isolating may be reviewed to determine if they pass the screening.

Primary Distribution Line Type

Type of Interconnection to Primary Distribution Line

Result

3-phase, 3 wire 3-phase or single phase, phase-to-phase

Pass screen

3-phase, 4 wire 3-phase or single-phase, line-to-neutral

Pass screen

3-phase, 4 wire

3-phase or single phase, phase-to-phase

Fail screen

vii. If the proposed DER is to be interconnected on single-phase shared secondary, the aggregate generation capacity on the shared secondary, including the proposed DER, may not exceed 20 kWac or 65% of the transformer nameplate rating.

viii. If the proposed DER is single-phase and is to be interconnected on a center tap neutral of a 240 volt service, its addition may not create an imbalance between the 2 sides of the 240 volt service of more than 20% of the nameplate rating of the service transformer.

ix. If the proposed DER is single-phase and is to be interconnected to a 3-phase service, its nameplate rating may not exceed 10% of the service transformer nameplate rating.

x. If the proposed DER’s point of common coupling is behind a line voltage regulator, the aggregate DER on the line section plus the proposed DER’s nameplate rating must be less than 250 kWac or the regulator rating, whichever is less. This screen does not include substation voltage regulators.

xi. The total aggregate nameplate of generation at the site including the proposed project shall not exceed 5 MWac on 13.2KV and 1MWac on 4.8KV

xii. The aggregate DER on the line section plus the proposed DER nameplate shall not exceed the day to day thermal limit of any distribution system component that serves the project or exceed the rated fault current limit of DTE equipment.

xiii. The project follows the DTE Service Installation Manual (SIM), Primary Service, Method Of Service (MOS) requirements and meets all requirements of electrical service.

xiv. High voltage resonance screen. If the project is located on a delta ungrounded line, there must not be a single phase protective device upstream of the DER and any capacitors on the same line section.

xv. A three phase project must not have a single phase operating and isolation device at the

POC/PCC

xvi. If the project intends to operate as an islanded microgrid, it must implement a single open break isolation wholly contained within the Applicant’s service, such as an Auto Transfer Switch, implement mechanical interlocks that do not allow parallel operation or implement a hardware breaker controlled by DTE approved relaying. The microgrid must not rely on software based controls to manage power flow at the Point of Common Coupling during island operation. The microgrid must also implement open transition return to grid and follow return to service criteria or have appropriate synchronization relaying and controls approved by DTE for closed transition and provide SCADA points to DTE for required relaying.

xvii. If the application is a subdivided premise in a master planned clustered development where the aggregate DER Capacity of the clustered development exceeds the interconnection level the application has applied for, the application will be evaluated with the context of the development’s aggregate planned DER capacity.

xviii. If the project is located within a section of a circuit that is identified as an area that has an operational jumpering or loop scheme, the addition of the DER does not render the jumpering or loop scheme inoperable due to loading or voltage violations.

APPENDIX I: SUPPLEMENTAL REVIEW SCREENS

The supplemental review screens are all of the following:

Minimum load screen. Where 12 months of line section minimum load data, including onsite load but not station service load served by the proposed DER, are available, can be calculated, can be estimated from existing data, or can be determined from a power flow model, the aggregate DER capacity on the line section must be less than 100% of the minimum load for all line sections bounded by automatic sectionalizing devices upstream of the proposed DER. If minimum load data are not available, or cannot be calculated, estimated, or determined, DTE shall include the reason or reasons that it is unable to calculate, estimate, or determine minimum load in its supplemental review results notification. All of the following must be applied:

(i) The type of generation used by the proposed DER will be considered when calculating, estimating, or determining circuit or line section minimum load relevant for the application of the minimum load screen specified in this subdivision. Solar photovoltaic generation systems with no energy storage must use daytime minimum load. All other generation must use absolute minimum load unless an operating schedule is provided.

(ii) When this screen is being applied to a DER that serves some station service load, only the net injection of electric energy into the electric utility’s distribution system may be considered as part of the aggregate generation.

(iii) The electric utility shall not consider as part of the aggregate generation, for purposes of this supplemental screen, DER capacity known to be already reflected in the minimum load data.

Voltage and power quality screen. In aggregate with existing generation on the line section, all of the following conditions must be met:

(i) The voltage regulation on the line section can be maintained in compliance with relevant requirements under all system conditions.

(ii) The voltage fluctuation is within acceptable limits as defined by the IEEE Standard 1453-

2015, IEEE Recommended Practice for the Analysis of Fluctuating Installations on Power Systems.

ii.

Safety and reliability screen. The location of the proposed DER and the DER capacity on the line section may not create impacts to safety or reliability that require application of the study track to address. DTE shall consider all of the following when determining potential impacts to safety and reliability in applying this screen:

(i) Whether the line section has significant minimum loading levels dominated by a small number of customers, such as several large commercial customers.

(ii) Whether the loading along the line section is uniform.

(iii) Whether the proposed DER is located less than 0.5 electrical circuit miles for less than 5 kV or less than 2.5 electrical circuit miles for greater than 5 kV from the substation. In addition, the day to day rating of the line section from the substation to the point of common coupling.

(iv) If the proposed interconnection will connect to a power line or feeder cable

(v) Whether the proposed DER incorporates a time delay function to prevent reconnection of the DER to the distribution system until distribution system voltage and frequency are within normal limits for a prescribed time.

(vi) Whether operational flexibility is reduced by the proposed DER, such that transfer of the line section or sections of the DER to a neighboring distribution circuit or substation may trigger overloads, power quality issues, or voltage issues.

(vii) Whether the proposed DER employs equipment or systems certified by a recognized standards organization to address technical issues including, but not limited to, islanding, reverse power flow, or voltage quality.

(viii) Whether the proposed project will increase existing power quality issues on the circuit.

(ix) Whether voltage regulators, or load tap changers are adversely impacted or risk being damaged by reverse power flow from over excitation, excessive operation or improper regulation behavior leading to their failure or power quality and voltage impacts to other customers.

(x) Whether the service at the premise is able to operate safely with the additional generation provided by the project.

(xi) Whether the service or transformer could experience a overload or out of range voltage when there are other existing projects on the same service transformer.

(xii) Whether there is a risk of islanding screen to determine if additional protection, communications or operating devices are required to prevent unintentional islanding

APPENDIX J: PRE-APPLICATION REPORT FORM

PRE-APPLICATION REPORT

Date of Assessment XX/XX/XXXX

DISCLAIMER: The information in this report is based on existing data lookups and correlation of that data. No System Impact studies, or detailed engineering analysis have been done to create this report. This report does not guarantee the accuracy of any of the information provided herein. Identification by DTE Electric of substation and feeder does not guarantee, after application of the relevant review process, that DTE Electric will use the distribution facilities identified in the application report to connect to the project. An application report request does not obligate DTE Electric to conduct a study or other analysis of the proposed generator in the event that data is not readily available. If DTE Electric cannot complete some, or all, of the report due to lack of available data, DTE

Electric shall provide the applicant with this report that includes the data that is available. The provision of information on capacity does not imply that an interconnection may be completed with or without impacts since there are many variables studied as part of the interconnection review process, and data provided in the application report may become outdated at the time of the submission of the complete application for System Impact and/or Facilities studies. Notwithstanding the foregoing, DTE Electric shall, in good faith, include data in the application report that represents the best available information at the time of reporting.

Project Information

Known issues in the area

Will this site initially require a System Impact Study for subtransmission based on size and location and existing system configuration?

(Y/N/NA)

Has this area been identified as having a prior affected system?

(Y/N/NA)

Power quality Issue on the proposed PCC (Y/N/NA)

Developer Name Project Name Application Number

Developer Provided Site Address Developer Provided Coordinates

Generator KW / KVA Prime Mover / Energy Source

System Information

Label, name, or identifier of the distribution circuit on which the proposed point of common coupling is located

Feeder Voltage

(kV)

Distance to Station or Total Circuit Length for network circuits (miles)

Voltage at POI (kV)

Number of sources Substation nominal distribution voltage

Nominal distribution circuit voltage at PCC

Is the proposed generator expected to exceed minimum load on the circuit?

Is the PCC behind Voltage Regulator or Substation Transformer LTC?

Number of phases available at the primary voltage level at the proposed point of common coupling (if a single phase, distance from the 3-phase circuit)

The point of common coupling is located on a (spot network, area network, grid network, radial supply, or secondary network)

With the proposed project, does the existing and applied generation exceed the nameplate of the substation or station transformer?

Distance to three phase of appropriate voltage (Gen to POI) (miles)

Source Type Serving POI

(radial/network)

Existing and in progress MW

Total capacity of substation bus, bank or circuit Applicable Minimum load (MW)

Limiting Line rating (A)

Available capacity of substation bus, bank or circuit

(MW)

Number of industrial substations coincident

Existing generation on Circuit (MW) Applied for but not yet constructed MW Source (MW)

Pending Interconnection that may impact this project

APPENDIX K: VOLTAGE RANGES

Voltage Class Nominal Voltage (V) Secondary 120/240

120/208

277/480

Distribution

4,800 8,320

13,200

Sub transmission

24,000

41,570 (40KV)

APPENDIX L: INSURANCE REQUIREMENTS

APPENDIX M: COMPANY HOLIDAYS

New Year’s Day (observed)

Martin Luther King Day

Good Friday

Memorial Day

Independence Day

Labor Day

Thanksgiving

Day after Thanksgiving

Christmas Eve (observed)

Christmas Day (observed)

New Year’s Eve (observed)

Drain 12H

RTU 26H

Drain 12H

Drain 5H

Vent 37H

Drain 12H

Vent 13H

Vent 16H

Pipe 8H

Pipe 7H

Vent 10H

Drain 5H

RTU 55H

P5 8H

Vent 10H

Vent 9H

Vent 38H

Drain 10H

Vent 10H

Vent 10H Vent 10H

Vent 35H

Vent 46H

Vent 10H

Vent 30H

Pipes 8H

Vent 31H

Vent 36H

Vent 10H

Electrical 52H

Vent 20H

Drain 5H

Vent 10H

Vent 8H

Satellite H

Vent 36H Vent 16H

Vent 50H Vent 10H

Vent 9H

Drain 11H

Vent 10H

Drain 12H

Edges 13H

Edges 13H Edges 20H

Edges 15H

Vent 10H

Drain 11H

Electrical 50H

Vent 10H

Vent 26H

Vent 30H

Vent 36H

Vent 10H

Vent 25H

Vent 8H

Vent 10H

Drain 11H

Vent 44H

Vent 10H

Vent 33H

Drain 11H

Vent 35H

Drain 11H Vent 18H

Drain 5H

Vent 26H

Vent 18H

Vent 35H

Vent 10H

Drain 11H

Electrical 53H

Vent 10H

Drain 11H

Vent 37H

Vent 10H

Drain 11H

Drain 5H

Drain 11H

Vent 10H

RTU 33H

Drain 11H Drain 5H

Drain 11H

Vent 10H

RTU 65H

Drain 5H

Vent 15H

Drain 5H

Drain 11H

Vent 36H

Vent 11H Vent 11H

Vent 8H

Vent 10H

Drain 11H

Vent 35H

Vent 39H

Vent 10H

Drain 11H

Drain 5H

RTU 32H

Vent 26H

Electrical 50H Vent 33H

Drain 5H

Drain 11H

Vent 35H

Drain 11H

Drain 11HVent 8H

Drain 10H

Vent 40H

Vent 38H

Drain 11H

Vent 10H

Vent 27H

Vent 35H

Vent 8H

Drain 11H

RTU 150H

Edges 22H

Edges 15H

Edges 21H

Edges 12H

Vent 32H

Vent 34H

Vent 32H

Drain 6H

Edges 5H

Edges 8H

Drain 6H

Edges 10H

Edges 3H Edges 3H

Edges 3H

Edges 3H Edges 3H

Edges 3H

Edges 3H Edges 3H

Edges 3H

Edges 15H

Edges 21H

Edges 15H

Edges 19H Edges 21H

Edges 20H

Edges 19H

Edges 16H

Edges 15H

Edges 21H

Edges 21HEdges 15H

Edges 15H

Edges 20H

Edges 20H Edges 15H

Edges 15H Edges 20H

Edges 20H

Edges 22H

Vent 28H

Vent 36H

Vent 37H

Vent 28H

Vent 12H

Vent 17H

RTU 53H

RTU 40H

RTU 44H

RTU 42H

RTU 44H

Electrical 20H

Edges 3H Edges 3H

Edges 3H

Edges 3H Edges 3H

Edges 3H

Edges 174H

Edges 180H

Edges 256H

Drain 5H

Edges 9H

Edges 2H

Vent 26H

Vent 35H

Vent 36H

Vent 35H

Electrical 50H

Drain 11H

Vent 35H

Vent 44H

Vent 30H

Drain 11H

Vent 11H

Electrical 25H

RTU 33H

Electrical 20H

Edges 40H

Edges 41H

Vent 10H

Vent 35H

Vent 35H Vent 30H

Vent 44H

Vent 27H

Vent 34H

Edges 42H

RTU 72H

RTU 48H

Vent 44H

Vent 40H

Vent 35H

Vent 10H

Drain 11H

Vent 41H

Vent 10H

Vent 30H

Drain 11H

Vent 40H

Vent 35H

Vent 10H

Vent 34H

Vent 35H

Vent 43H

Vent 30H

Vent 36H

Vent 30H

Drain 12H

Vent 45H

Vent 30H

Vent 51H

Vent 27H

RTU 114H

RTU 21H

RTU 28H

Electrical 9H

Edges 84H

Edges 86H

Edges 84H

Pipe 7H

Pipe 7H Pipe 7H

Pipe 7H

Edges 3H

Edges 3HEdges 19H

Edges 19H

Edges 20H

Edges 20H Edges 3H

Edges 3H

Drain 5H

Vent 10H

Vent 30H

Vent 86H

Vent 80H

Jvent 40H

Jvent 40H Jvent 40H

Jvent 40H

Jvent 67H

RTU 75H

RTU 17H

Access Egress 15H

RTU 75H

Pipes 8H

Pipes 17H

Edges 77H

Edges 79H

Vent 14H

Electrical 15H

Edges 3H

Edges 3H Edges 3H

Edges 3H

Access 40H

Vent 32H

COLE MCEKNZIE

2024-03-15

ARCH Expand D (36.00 X 24.00 Inches)

E-101

SALINE MIDDLE

SCHOOL

SHEET NAME

BASE PROJECT

METER SITE PLAN

SHEET NUMBER

REVDATEDESCRIPTION

REVISIONS

RIGHTS RESERVED.

EOR:

SHEET SIZE:

DATE:

DRAWN BY:

DEVELOPED BY:

PROJECT

CUSTOMER

SALINE

SCHOOLS

LOCATION

7190 N MAPLE RD,

SALINE, MI 48176

SEAL AND SIGNATURE:

PRELIMINARY DESIGN 10/26/2023 0

#1"=40'-0"

SCALE:

(OR)

1"=20'-0"20'10'020'SCOPE OF WORK

SITE DETAILS

AC RATING (kW) 540kW DC RATING (kW) 757.35kW

STRING QUANTITY 81

POWER FACTOR 1.00

INTERCONNECT VOLTAGE 480V

UTILITY DTE

SERVICE NUMBER

ACCOUNT NUMBER

METER NUMBER

CODE EDITION NEC 2023

ESTIMATED ANNUAL

PRODUCTION

EQUIPMENT LIST

ITEM MAKE/MODEL/SPEC QUANTITY

MODULES ZNSHINE ZXM7-SHDB144-550 1377

INVERTERS CPS SCA60KTL 9

MONITORING CPS 1

METER SPECIFIED BY DTE 1

PANELBOARD (1) 1000A MLO 3P, 4W, W/ (9) 100ACB (1) 15A CBS 1

DISCONNECT 480/277V 3Ø 4W, 1000 AF, 1000AT

NEMA 3R ,22kA

BOS WIRE, CONDUIT, TERMINATIONS, GROUNDING MATERIALS --

WITH

LEGEND

INVERTER

CIRCUIT

BREAKER

FUSE

GROUND

AC CONDCTOR

COMMUNICATIONS

DEMARCATION

PV MODULE 1. ALL EQUIPMENT SHALL BE PROPERLY BONDED AND GROUNDED AS REQUIRED BY NEC AND MANUFACTURER SPECIFICATIONS.

2. MAIN DISCONNECT SWITCH SHALL BE 24/7 UTILITY ACCESSIBLE.

SITE DETAILS

AC RATING (kW) 540kW DC RATING (kW) 757.35kW

STRING QUANTITY 81

POWER FACTOR 1.00

INTERCONNECT VOLTAGE 480V

UTILITY DTE

SERVICE NUMBER

ACCOUNT NUMBER

METER NUMBER

CODE EDITION NEC 2023

ESTIMATED ANNUAL

PRODUCTION

INVERTER TRIP SETTINGS (IEEE1547)

DEVICE PICKUP DESCRIPTION NOTE(S)

27-1 139V UNDERVOLTAGE

RELAY27-2 244V

59-1 304V OVERVOLTAGE

RELAY59-2 332V

81U-1 56.5HZ

OVER/UNDER

FREQUENCY

81U-2 58.5HZ

810-1 61.0HZ

810 62.0HZ

MONITORING

ENCLOSURE

DC CONDUCTOR

SWITCH

TRANSFORMER

NOTES

EXISTING EQUIPMENT

CURRENT

TRANSFORMER

M METER SOCKET

GROUND

9 STRINGS

INVERTER 1

CPS 60kW

9 STRINGS

INVERTER 2

CPS 60kW

CB2 - 100A

480V, 3P

CB1 - 100A

480V, 3P

CPS FLEX

GATEWAY DATA

CARD INSTALLED

INSIDE INVERTER

4 WIRING BOX.

WITH CELL MODEM

AC DISCONNECT 1

480/277V 3Ø 4W, 1000 AF, 1000 AT

NEMA 3R ,22kA

COLLECTION PANELBOARD

480/277V 3Ø 3W, 1000A BUS, MAIN LUG

NEMA 3R ,22kA

TO PANEL

EXISTING SWITCHGEAR

480/277V 3Ø 3W, 1600A BUS, NEMA 3R ,22kA

EXISTING METER

UTILITY OWNED

GRID CONNECTION

9 STRINGS

INVERTER 3

CPS 60kW

9 STRINGS

INVERTER 4

CPS 60kW

CB4 - 100A

480V, 3P

CB3 - 100A

480V, 3P

TO PANEL

N G

EXISTING UTILITY

OWNED TRANSFORMER

9 STRINGS

INVERTER 5

CPS 60kW

CB5 - 100A

480V, 3P

TO PANEL

9 STRINGS

INVERTER 6

CPS 60kW

9 STRINGS

INVERTER 7

CPS 60kW

CB7 - 100A

480V, 3P

CB6 - 100A

480V, 3P

TO PANEL

9 STRINGS

INVERTER 8

CPS 60kW

CB8 - 100A

480V, 3P

TO PANEL

9 STRINGS

PV ARRAY 9 - 84.15kW

(153) ZNSHINE 550W

(9) STRINGS OF 17

INVERTER 9

CPS 60kW

CB9 - 100A

480V, 3P

TO PANEL

POCC

NEC COMPLIANT LINE

SIDE TAP

FLA = 649.8A

FAULT CURRENT FROM

INVERTER = 779.76A

EXISTING

LOADS

1600A MAIN

BREAKER

PV ARRAY 8 - 84.15kW

(153) ZNSHINE 550W

(9) STRINGS OF 17

PV ARRAY 7 - 84.15kW

(153) ZNSHINE 550W

(9) STRINGS OF 17

PV ARRAY 6 - 84.15kW

(153) ZNSHINE 550W

(9) STRINGS OF 17

PV ARRAY 5 - 84.15kW

(153) ZNSHINE 550W

(9) STRINGS OF 17

PV ARRAY 4 - 84.15kW

(153) ZNSHINE 550W

(9) STRINGS OF 17

PV ARRAY 3 - 84.15kW

(153) ZNSHINE 550W

(9) STRINGS OF 17

PV ARRAY 2 - 84.15kW

(153) ZNSHINE 550W

(9) STRINGS OF 17

PV ARRAY 1 - 84.15kW

(153) ZNSHINE 550W

(9) STRINGS OF 17

EQUIPMENT LIST

ITEM MAKE/MODEL/SPEC QUANTITY

MODULES ZNSHINE ZXM7-SHDB144-550 1377

INVERTERS CPS SCA60KTL 9

MONITORING CPS 1

METER SPECIFIED BY DTE 1

PANELBOARD (1) 1000A MLO 3P, 4W, W/ (9) 100ACB (1) 15A CBS 1

DISCONNECT 480/277V 3Ø 4W, 1000 AF, 1000AT

NEMA 3R ,22kA

BOS WIRE, CONDUIT, TERMINATIONS, GROUNDING MATERIALS --

NEW DG METER

UTILITY OWNED

BASE PROJECT

SINGLE LINE

DIAGRAM

COLE MCEKNZIE

2024-03-15

ARCH Expand D (36.00 X 24.00 Inches)

E-601

SALINE MIDDLE

SCHOOL

7190 N MAPLE RD,

SALINE, MI 48176

SHEET NAME

SHEET NUMBER

CUSTOMER

REVDATEDESCRIPTION

REVISIONS

EOR:

LOCATION

SHEET SIZE:

DATE:

DRAWN BY:

DEVELOPED BY:

PROJECT

SEAL AND SIGNATURE:

PRELIMINARY DESIGN 10/26/2023 0

AMERESCO

RIGHTS RESERVED.

Drain 12H

RTU 26H

Drain 12H

Drain 5H

Vent 37H

Drain 12H

Vent 13H

Vent 16H

Pipe 8H

Pipe 7H

Vent 10H

Drain 5H

RTU 55H

P5 8H

Vent 10H

Vent 9H

Vent 38H

Drain 10H

Vent 10H

Vent 10H Vent 10H

Vent 35H

Vent 46H

Vent 10H

Vent 30H

Pipes 8H

Vent 31H

Vent 36H

Vent 10H

Electrical 52H

Vent 20H

Drain 5H

Vent 10H

Vent 8H

Satellite H

Vent 36H Vent 16H

Vent 50H Vent 10H

Vent 9H

Drain 11H

Vent 10H

Drain 12H

Edges 13H

Edges 13H Edges 20H

Edges 15H

Vent 10H

Drain 11H

Electrical 50H

Vent 10H

Vent 26H

Vent 30H

Vent 36H

Vent 10H

Vent 25H

Vent 8H

Vent 10H

Drain 11H

Vent 44H

Vent 10H

Vent 33H

Drain 11H

Vent 35H

Drain 11H Vent 18H

Drain 5H

Vent 26H

Vent 18H

Vent 35H

Vent 10H

Drain 11H

Electrical 53H

Vent 10H

Drain 11H

Vent 37H

Vent 10H

Drain 11H

Drain 5H

Drain 11H

Vent 10H

RTU 33H

Drain 11H Drain 5H

Drain 11H

Vent 10H

RTU 65H

Drain 5H

Vent 15H

Drain 5H

Drain 11H

Vent 36H

Vent 11H Vent 11H

Vent 8H

Vent 10H

Drain 11H

Vent 35H

Vent 39H

Vent 10H

Drain 11H

Drain 5H

RTU 32H

Vent 26H

Electrical 50H Vent 33H

Drain 5H

Drain 11H

Vent 35H

Drain 11H

Drain 11HVent 8H

Drain 10H

Vent 40H

Vent 38H

Drain 11H

Vent 10H

Vent 27H

Vent 35H

Vent 8H

Drain 11H

RTU 150H

Edges 22H

Edges 15H

Edges 21H

Edges 12H

Vent 32H

Vent 34H

Vent 32H

Drain 6H

Edges 5H

Edges 8H

Drain 6H

Edges 10H

Edges 3H Edges 3H

Edges 3H

Edges 3H Edges 3H

Edges 3H

Edges 3H Edges 3H

Edges 3H

Edges 15H

Edges 21H

Edges 15H

Edges 19H Edges 21H

Edges 20H

Edges 19H

Edges 16H

Edges 15H

Edges 21H

Edges 21HEdges 15H

Edges 15H

Edges 20H

Edges 20H Edges 15H

Edges 15H Edges 20H

Edges 20H

Edges 22H

Vent 28H

Vent 36H

Vent 37H

Vent 28H

Vent 12H

Vent 17H

RTU 53H

RTU 40H

RTU 44H

RTU 42H

RTU 44H

Electrical 20H

Edges 3H Edges 3H

Edges 3H

Edges 3H Edges 3H

Edges 3H

Edges 174H

Edges 180H

Edges 256H

Drain 5H

Edges 9H

Edges 2H

Vent 26H

Vent 35H

Vent 36H

Vent 35H

Electrical 50H

Drain 11H

Vent 35H

Vent 44H

Vent 30H

Drain 11H

Vent 11H

Electrical 25H

RTU 33H

Electrical 20H

Edges 40H

Edges 41H

Vent 10H

Vent 35H

Vent 35H Vent 30H

Vent 44H

Vent 27H

Vent 34H

Edges 42H

RTU 72H

RTU 48H

Vent 44H

Vent 40H

Vent 35H

Vent 10H

Drain 11H

Vent 41H

Vent 10H

Vent 30H

Drain 11H

Vent 40H

Vent 35H

Vent 10H

Vent 34H

Vent 35H

Vent 43H

Vent 30H

Vent 36H

Vent 30H

Drain 12H

Vent 45H

Vent 30H

Vent 51H

Vent 27H

RTU 114H

RTU 21H

RTU 28H

Electrical 9H

Edges 84H

Edges 86H

Edges 84H

Pipe 7H

Pipe 7H Pipe 7H

Pipe 7H

Edges 3H

Edges 3HEdges 19H

Edges 19H

Edges 20H

Edges 20H Edges 3H

Edges 3H

Drain 5H

Vent 10H

Vent 30H

Vent 86H

Vent 80H

Jvent 40H

Jvent 40H Jvent 40H

Jvent 40H

Jvent 67H

RTU 75H

RTU 17H

Access Egress 15H

RTU 75H

Pipes 8H

Pipes 17H

Edges 77H

Edges 79H

Vent 14H

Electrical 15H

Edges 3H

Edges 3H Edges 3H

Edges 3H

Access 40H

Vent 32H

COLE MCEKNZIE

2024-03-15

ARCH Expand D (36.00 X 24.00 Inches)

E-102

SALINE MIDDLE

SCHOOL

SHEET NAME

ALT 1 SITE

PLAN

SHEET NUMBER

REVDATEDESCRIPTION

REVISIONS

RIGHTS RESERVED.

EOR:

SHEET SIZE:

DATE:

DRAWN BY:

DEVELOPED BY:

PROJECT

CUSTOMER

SALINE

SCHOOLS

LOCATION

7190 N MAPLE RD,

SALINE, MI 48176

SEAL AND SIGNATURE:

PRELIMINARY DESIGN 10/26/2023 0

#1"=40'-0"

SCALE:

(OR)

1"=20'-0"20'10'020'SCOPE OF WORK

SITE DETAILS

AC RATING (kW) 480kW DC RATING (kW) 673.2kW

STRING QUANTITY 72

POWER FACTOR 1.00

INTERCONNECT VOLTAGE 480V

UTILITY DTE

SERVICE NUMBER

ACCOUNT NUMBER

METER NUMBER

CODE EDITION NEC 2023

ESTIMATED ANNUAL

PRODUCTION

EQUIPMENT LIST

ITEM MAKE/MODEL/SPEC QUANTITY

MODULES ZNSHINE ZXM7-SHDB144-550 1224

INVERTERS CPS SCA60KTL 8

PLANT CONTOLLER COMP-AP 1

PT CABINET AS NEEDED BY COMP-AP SPECS 1

PANELBOARD (1) 800A 480/277V MLO 3P, 4W W/ (8) 100A CBs 1

DISCONNECT 480/277V 3Ø 4W, 800 AF, 800AT

NEMA 3R ,22kA

BOS WIRE, CONDUIT, TERMINATIONS, GROUNDING MATERIALS --

LEGEND

INVERTER

CIRCUIT

BREAKER

FUSE

GROUND

AC CONDCTOR

COMMUNICATIONS

DEMARCATION

PV MODULE 1. ALL EQUIPMENT SHALL BE PROPERLY BONDED AND GROUNDED AS REQUIRED BY NEC AND MANUFACTURER SPECIFICATIONS.

2. MAIN DISCONNECT SWITCH SHALL BE 24/7 UTILITY ACCESSIBLE.

SITE DETAILS

AC RATING (kW) 480kW DC RATING (kW) 673.2kW

STRING QUANTITY 72

POWER FACTOR 1.00

INTERCONNECT VOLTAGE 480V

UTILITY DTE

SERVICE NUMBER

ACCOUNT NUMBER

METER NUMBER

CODE EDITION NEC 2023

ESTIMATED ANNUAL

PRODUCTION

INVERTER TRIP SETTINGS (IEEE1547)

DEVICE PICKUP DESCRIPTION NOTE(S)

27-1 139V UNDERVOLTAGE

RELAY27-2 244V

59-1 304V OVERVOLTAGE

RELAY59-2 332V

81U-1 56.5HZ

OVER/UNDER

FREQUENCY

81U-2 58.5HZ

810-1 61.0HZ

810 62.0HZ

MONITORING

ENCLOSURE

DC CONDUCTOR

SWITCH

TRANSFORMER

NOTES

EXISTING EQUIPMENT

CURRENT

TRANSFORMER

M METER SOCKET

GROUND

9 STRINGS

INVERTER 1

CPS 60kW

9 STRINGS

INVERTER 2

CPS 60kW

CB2 - 100A

480V, 3P

CB1 - 100A

480V, 3P

COMP-AP PLANT

CONTROLLER TO THROTTLE

INVERTERS TO ENSURE NO

ENERGY IS EXPORTED TO

GRID

AC DISCONNECT 1

480/277V 3Ø 4W, 800 AF, 800 AT

NEMA 3R ,22kA

COLLECTION PANELBOARD

480/277V 3Ø 3W, 800A BUS, MAIN LUG

NEMA 3R ,22kA

TO PANEL

EXISTING SWITCHGEAR

480/277V 3Ø 3W, 1600A BUS, NEMA 3R ,22kA

EXISTING METER

UTILITY OWNED

GRID CONNECTION

9 STRINGS

INVERTER 3

CPS 60kW

9 STRINGS

INVERTER 4

CPS 60kW

CB4 - 100A

480V, 3P

CB3 - 100A

480V, 3P

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File details come from the government source that posted it. Updated Apr 3, 2024.