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Columbia Solar (Q148) Facilities Study July 13, 2018

Columbia Solar Plant Interconnect

69 kV Switching Station

Facilities Study Report

Final Version - 7/13/18

Energy Resource Interconnection Service and Network Resource Interconnection Service (Q148)

Prepared by:


Columbia Solar (Q148) Facilities Study July 13, 2018 Page 2 of 25

Table of Contents 1.0 Executive Summary ........................................................................................................................... 3

2.0 Baseline Assumptions ....................................................................................................................... 4

3.0 Required Network Upgrades ............................................................................................................ 6

3.1 Transmission Lines ........................................................................................................................ 6

3.1.1 Work Scope ........................................................................................................................... 6

3.1.2 Clarifications and Assumptions ............................................................................................. 7

3.1.3 Transmission Line Cost Estimate ........................................................................................... 7

3.2 Substation Physical ....................................................................................................................... 8

3.2.1 Work Scope ........................................................................................................................... 8

3.2.2 Major Substation Equipment ................................................................................................ 8

3.2.3 Clarifications and Assumptions ............................................................................................. 9

3.2.4 Cost Estimate ...................................................................................................................... 10

3.3 Protection and Control................................................................................................................ 10

3.3.1 Work Scope ......................................................................................................................... 10

3.3.2 Major P&C Equipment ........................................................................................................ 12

3.3.3 Remote End Substations ..................................................................................................... 12

3.3.4 Clarifications and Assumptions ........................................................................................... 13

3.3.5 Protection and Control Cost Estimate ................................................................................ 14

3.4 Telecommunications ................................................................................................................... 14

3.4.1 Work Scope ......................................................................................................................... 14

3.4.2 Clarifications and Assumptions ........................................................................................... 15

3.4.3 Telecommunications Cost Estimate .................................................................................... 15

4.0 Connection Requirements .............................................................................................................. 16

4.1 General ........................................................................................................................................ 16

4.2 Point of Interconnection ............................................................................................................. 16

4.4 Equipment Ratings and Protection Coordination ....................................................................... 16

4.5 Insulation Requirements ............................................................................................................. 17

4.6 Communications ......................................................................................................................... 17

4.7 Metering ..................................................................................................................................... 17

4.8 Grounding ................................................................................................................................... 17

5.0 Cost Estimate Summary .................................................................................................................. 18

6.0 Milestone Schedule ......................................................................................................................... 19

7.0 Appendices ...................................................................................................................................... 20

8.0 Facilities Study Approval ................................................................................................................. 25



1.0 Executive Summary

The Q148 Solar Plant is a planned Solar PV station, capable of 74.9 MW net output. The facility will be located in Columbia County, Florida (See Appendix A). The point of interconnection will be a new four (4) terminal, four (4) breaker 69kV Columbia Switching Station, initially configured as a ring bus. The switching station will be used to loop in and out Duke Energy Florida’s (DEF) Fort White to High Springs (FH) 69kV line including the Fort White Clay Electric Cooperative Tap creating: Fort White to Columbia, Fort White Clay Electric Cooperative to Columbia and High Springs to Columbia 69kV lines. The fourth terminal will be for connection to the proposed Solar PV station.

The customer has requested this generation facility be studied for Network Resource Interconnection Service (NRIS) and Energy Resource Interconnection Service (ERIS) with a requested Commercial Operating Date (COD) of December 31, 2019.

Duke Energy Florida (DEF) the “Transmission Company” previously completed a System Impact Study (SIS) and issued the report on March 15, 2018, that summarizes the thermal, voltage, short circuit and transient stability impacts associated with the proposed interconnection.

The primary objective of this Facilities Study (FS) is to quantify necessary Transmission Owner network upgrade(s), other direct assigned upgrade(s), and associated upgrade lead times. Therefore, this FS quantifies the cost, work scope, and tentative schedules associated with the design and installation of the required network modifications. This study evaluates and estimates the date that service could be granted based on specific criteria outlined within this report.

The SIS identified potential network upgrades to DEF’s transmission network to accommodate the full capacity of the proposed Solar PV station under NRIS. This included a third Powerline to Holder 230kV line that was found to be required due to an N-1 contingency. This line would connect to a proposed Powerline Substation that was identified previously in another queue study with an in-service date of 2021 which would need to be in-service prior to completion of a NRIS interconnection.

The facilities and costs discussed herein are for DEF upgrades only, and do not include any known or potential affected system upgrades. In the SIS, a Third Party Short Circuit Impact was identified. The short circuit analysis revealed one impact greater than 3% to a third-party (SECI/CEC delivery point) substation. All third-party impacts will be evaluated further in a future FRCC-TTS Reliability Assessment that is performed on Generator Interconnection Service Requests (GISR) and Transmission Service Requests (TSR) that potentially affect the FRCC region.



The short circuit analysis performed in the SIS revealed impacts greater than 3% at several DEF substations. These substations were reviewed, and no equipment was identified as being over-dutied.

The FS includes cost estimates to permit, engineer, procure equipment and materials, construct and place facility upgrades or additions in service to accomplish the requested service.

The facilities needed to accomplish the interconnection have been reviewed and proposed schedules for completion were based on the DEF and the Customer executed Agreement/Contract on March 16, 2018. Schedules were developed utilizing typical project durations experienced by DEF for project engineering, procurement, permitting, construction, and outage requirements. Schedules durations do not include seasonal capacity considerations as well as system configuration constraints such as concurrent line outages.

Subsequent to the requirements and preparation listed in this document a design review shall take place prior to any facilities construction to maintain compliance with the North American Electric Reliability Corporation (NERC) Reliability Standard FAC-002-1, or its successor. Also, in compliance with the NERC Reliability Standard FAC-002-1, or its successor, a testing and inspection activity will take place prior to the in-service date.

2.0 Baseline Assumptions

The estimated costs and schedule are based on the assumptions identified in this Facilities Study.

The Transmission Company’s (DEF’s) Facilities are based on application of industry standard equipment. All new and rebuilt facilities will be designed and built according to the DEF’s current practice. These facilities will become a part of the DEF network transmission system therefore in addition to having sufficient capacity to accept the proposed Solar PV station generation these facilities must also have the capacity to carry the power flows to upstream loads. As such the total energy handling capability of the proposed interconnection facilities could potentially accommodate energy flows greater than the requested 74.9 MW. However, in the event the Customer decides to designate additional capacity, a new request will be required to evaluate the impacts. Any constraints that may result will be identified as part of the new study request.

Any required outages necessary to support construction of the Interconnect Facilities must be coordinated with the DEF Energy Control Center (“ECC”). If an outage of sufficient duration cannot be obtained to support any of the required construction activities, alternative solutions such as new facilities or temporary facilities may have to be constructed to maintain integrity of the grid. No provisions have been made for temporary work in the estimates provided herein.

The proposed protection schemes to be installed by DEF at the Associated Facilities are intended to protect DEF’s Transmission Network.



Estimates prepared for this FS are considered to be good faith estimates represented in present day dollars as of the date of the study. The estimates do not include upgrade costs for third party facilities. The cost estimates provided use currently available pricing in Duke’s estimating system. The estimated budget has been computed with an expected accuracy of +/-20 %. Costs may fluctuate due to inflation or changes in market price. The estimates are further premised on being able to perform work during normal business hours with minimum overtime or weekend work. The estimates assume no changes in scope or design from that provided in previous studies.

Cost estimates are inclusive of engineering, material (equipment, structures, conductors, OPGW, etc.), survey, geotechnical, access, clearing, siting, environmental, construction and removal.

Cost estimates for the NRIS required third Powerline to Holder 230kV line are from a previous facilities study (Q137 Shady Hills) and will need to be revised if the customer proceeds with NRIS.

DEF will be provided with sufficient easements across the solar facility for the new switching station, 69kV loop and the Fort White – Fort White Clay Electric Cooperative 69kV Tap (see Appendix A) at the location identified in the Q148 Facilities Study Agreement dated March 26, 2018. The Customer will provide the environmental permits (FDEP, USACOE, EPA, County, etc.), storm water permits, endangered species permits, Historical Resources studies, zoning and driveway permits. DEF shall be responsible for complying with the permit conditions, the SWPPP (by DEF) and any other Best Management Practices required by these permits. DEF will be responsible for any construction related permits for the switch yard, transmission lines and storage yard.

A draft Large Generator Interconnection Agreement (LGIA) will be provided to the Interconnection Customer consistent with the final results of this report. The Interconnection Customer will have 30 days to execute the LGIA consistent with the Joint Open Access Transmission Tariff.

The scope of work, durations, clarifications, assumptions and cost estimates apply to the core work associated for both NRIS and ERIS. Additional scope required for NRIS is identified throughout the document as required.



3.0 Required Network Upgrades

3.1 Transmission Lines

The transmission line scope changes of the facilities that are required to support this transmission service are addressed by the following sections.

3.1.1 Work Scope

Columbia 69kV Switching Station

The result of the SIS requires the following upgrades in support of the Columbia Solar interconnection request:

Loop-in 69kV lines from Fort White, Fort White Clay Electric Cooperative Tap and High Springs substations. Cut-in occurs approximately mid-span of Fort White to High Springs Line. Existing lines are on single circuit poles.

▪ Install two (2) steel dead ends in the existing Fort White – High Springs 69 kV line atexisting structure FH-102 and construct a loop in and out of the Northeast andSouthwest Bays of the new Columbia Interconnect Sub. A total of six (6) dead end poleswill be needed to construct the loop.

▪ Install one (1) steel dead end in the existing Fort White – Fort White Clay ElectricCooperative 69 kV Tap at existing structure FH-99-4 and construct 0.2 miles of new lineinto the Northwest Bay of the new Columbia Interconnect Sub. A total of four (4) steelpoles will be needed to construct the tap.

▪ Anticipating 20’ direct embedded foundations utilizing concrete backfill▪ Existing 4/0 HDB Copper and 795 ACSR will be dead-ended on new structures and new

1272 ACSS TW will be installed into the new substation terminals▪ The existing switch at FH-99 will be removed and approximately 0.1 miles of the Fort

White – Fort White Clay Electric Cooperative 69 kV Tap from FH-99 to FH-99-4 will beremoved

This will create Fort White to Columbia, Fort White Clay Electric Cooperative to Columbia and High Springs to Columbia 69 kV lines. (See Appendix A)

NRIS

In addition to the scope required for ERIS, NRIS also requires the addition of a third Powerline to Holder 230kV line due to an N-1 contingency. In addition, the Lecanto to Pine Ridge 115kV line is overloaded which would also be resolved by a third Powerline to Holder 230kV line. This line was identified previously in another queue study (Q137 Shady Hills). As identified in the previous study, the current DEF practice is to utilize 3000A capacity lines with 2627 KCM ACSS/TW/HS Santee conductor.



3.1.2 Clarifications and Assumptions

▪ It is assumed that the outages/clearances required for construction are compatible withload flow conditions at the time of construction. These projects may require difficult toobtain outages which could delay or increase the cost of this project, if they are notreceived in a timely manner.

▪ It is assumed that the Customer will build the generator lead lines from the proposed

Solar PV station to the Columbia 69kV Switching Station - Point of Interconnection (see

Appendix C)

▪ NRIS only (from Q137 Shady Hills)o The new Powerline to Holder line will be built in the existing Crystal River Plant

to Central Florida right-of-wayo The new Powerline substation is assumed to be in-service, prior to the

construction of the upgrades associated with Q148 and is therefore not included

in the scope of work

3.1.3 Transmission Line Cost Estimate

ERIS

Q148 69kV Fort White to Columbia, High Springs to Columbia, Fort White C.E.C. to Columbia, Solar Station to

Columbia

Estimated Cost ($)

Engineering $91,000

Equipment and Material $303,000

Labor $551,000

Other (includes Indirect Allocations) $204,000 Total $1,149,000

NRIS

NRIS Required Upgrades Estimated Cost ($)

Q148 69kV Fort White to Columbia, High Springs to Columbia, Fort White C.E.C. to Columbia, Solar Station to Columbia

$1,149,000

230kV Line from Powerline Sub to Holder Substation (from Q137 Shady Hills)

$32,054,000

Total $33,203,000



3.2 Substation Physical

3.2.1 Work Scope

The physical scope of work identified in this study is listed below. For all the equipment identified:


▪ A four (4) position 69kV ring bus with associated breakers, switches and bus (See AppendixB)

▪ Four (4) 69kV line positions with associated dead-end towers, motor operated line switches,surge arresters, and potential transformers (PT)

▪ The switching station will be used to loop in and out DEF’s Fort White to High Springs (FH)69kV line including the Fort White Clay Electric Cooperative Tap creating: Fort White toColumbia, Fort White Clay Electric Cooperative to Columbia and High Springs to Columbia69kV lines

o Three (3) of the line positions will be used to loop in/out the Fort White to HighSprings 69kV line including the Fort White Clay Electric Cooperative Tap

o The fourth line position will be for the interconnection of the proposed Solar PVstation

▪ Install 69kV current transformers (CT) & PTs on the proposed Solar PV station 69kV line formetering

▪ New HDS-Small Control Equipment Enclosure (CEE) building (approx. 28’-8” x 44’-0”)▪ Four station service voltage transformers (SSVT), 69kV / 240-120V, 100kVA and associated

69kV switches, fused disconnects, auto transfer switch (flip flop), and AC panels

NRIS

In addition to the new 69kV Columbia Switching Station, NRIS also requires the addition of a new line position at DEF’s Powerline Substation for a third Holder 230kV line and a new line position at DEF’s Holder Substation for a third Powerline 230kV line.

3.2.2 Major Substation Equipment


New yard equipment to be installed for 69kV Columbia Switching Station:

▪ Four (4) Motor Operated Switches 2000A▪ Four (4) 69kV / 240-120V, 100kVA Station service voltage transformers▪ Four (4) 69kV 3000A 40kA Circuit Breakers▪ Ten (10) 69kV 2000A disconnect switches with manual operators▪ Twelve (12) single-phase PT’s for 69kV lines▪ Three (3) single-phase metering class PT’s for 69kV revenue metering



▪ Three (3) single-phase metering class CT’s for 69kV revenue metering▪ Twelve (12) 69kV station class surge arresters

NRIS In addition to the new 69kV Columbia Switching Station, NRIS also requires the scope of work from the Q137 Shady Hills FS at Powerline Substation and Holder Substation including the following equipment:

▪ Powerline Substationo Five (5) 230kV, 3000A, disconnect switches including four (4) breaker switches

and one (1) motor operated line switcho Two (2) 230kV, 3000A, breakerso One (1) 230kV, dead-end towero Three (3) 230kV PT’so Three (3) 230kV surge arresterso 4” IWCB bus & double 1750 AAC jumpers

▪ Holder Substationo Three (3) 230kV, 3000A, disconnect switches including two (2) breaker switches

and one (1) motor operated line switcho Two (2) 230kV, 3000A, breakerso One (1) 230kV, dead-end towero Three (3) 230kV PT’so Three (3) 230kV surge arresterso Complete 230kV ring buso 4” IWCB bus & double 1750 AAC jumpers


▪ This report does not consider possible environmental (wetlands, soil contamination,etc.) mitigation. Testing and environmental assessments are required to identify andquantify environmental costs. These items are outside the scope of this study.

▪ The ability to utilize standard and typical foundations is assumed▪ This report assumes the ability to acquire a suitable site adjacent to the existing DEF

Fort White to High Springs 69kV right-of-way for the proposed 69kV Columbia SwitchingStation

▪ It is assumed that the Customer will provide a suitable area of sufficient size at no costadjacent to the proposed 69kV Columbia Switching Station that can be utilized as amaterial storage yard

▪ It is assumed that the Customer will provide a suitable driveway and access road fromthe existing road (Fry Road) to the proposed 69kV Columbia Switching Station site

▪ Costs associated with upgrades to remote end ground grids (if required) are notincluded

▪ DEF will have full access and rights to the property to perform due diligence uponexecution of Interconnection Agreement.



3.2.4 Cost Estimate

ERIS

Q148 Columbia Switching Station Estimated Cost ($)

Engineering $475,000

Equipment and Material $1,515,000

Labor $2,964,000

Other (includes Indirect Allocations) $1,025,000 Total $5,979,000

NRIS


Q148 Columbia Switching Station $5,979,000

Holder Substation (from Q137 Shady Hills FC)

$2,347,000

Powerline Substation (from Q137 Shady Hills FC)

$1,662,000

Total $9,988,000

3.3 Protection and Control

3.3.1 Work Scope

This project includes a complete Protection and Control package for the new 69kV Columbia Switching Station interconnections to existing DEF’s Fort White (111), Fort White Clay Electric Cooperation Tap (6851) and High Springs (67) substations using a ring bus configuration with four (4) breakers and four (4) line positions including one (1) position for connection to the proposed Solar PV station (by others).

Protection system addition or upgrades shall be implemented with full redundancy. New breakers will utilize a breaker control relay and a breaker failure relay, with current supervision, from a bushing current transformer on the breaker. Should a breaker fail to trip within the allowable time setting, the associated breaker failure trip relay and associated lockout relay will trip and lock out adjacent breakers and remote breakers via breaker failure transfer trip.

The transmission line protective relay schemes continuously monitor conditions of the transmission lines and are designed to detect and isolate the faults with appropriate speed and minimum disturbance to the system. The transmission lines will be protected by redundant Line Protection 1 and Line Protection 2 current differential relays designed to clear a fault on the line. The schemes will use relay-to-relay communications utilizing fiber optic cable.




Items listed in the following table are the collective number of devices required for the 69kV Columbia Switching Station.

Total Qty

Device Function

4 SEL-311L Line Protection 1


1 SEL-735 Power Quality Meter

4 86-LOR/ER Breaker Failure Transfer Trip Lockout (Elec Reset)

4 SEL-351S MOS Control

4 SEL-351S Breaker Control

4 SEL-451 Breaker Failure

4 86-LOR Breaker Failure Lockout

NRIS

In addition to the new 69kV Columbia Switching Station, NRIS also requires the following protection & control scope of work at Powerline Substation and Holder Substation based on the Q137 Shady Hills FS for the Powerline to Holder 230kV line:

Total Qty

Device Function



1 86-LOR/ER Breaker Failure Transfer Trip Lockout (Elec Reset)

1 SEL-351S MOS Control

2 SEL-351S Breaker Control

2 SEL-451 Breaker Failure

2 86-LOR Breaker Failure Lockout

*Items listed in the previous table are collectively referred to as “P&C linepackage” in subsequent scope items



3.3.2 Major P&C Equipment

69kV Columbia Switching Station

▪ New Control Equipment Enclosure HDS/Small size 28’-8”x 44’-0” outer dimension▪ One (1) Battery Bank #1 (approx. size 200AH) and associated battery charger (approx.

size 25AH)▪ Relay panels

o 69kV High Springs Line LP1, BKR 8081 CTRL & MOS 8085 CTRLo 69kV High Springs Line LP2, BKR 8081 BFo 69kV Solar PV Station Meteringo 69kV Solar PV Station LP1, BKR 8088 CTRL & MOS 8089 CTRLo 69kV Solar PV Station LP2, BKR 8088 BF, Power Quality Metero 69kV Fort White Line LP1, BKR 8084 CTRL & MOS 8074 CTRLo 69kV Fort White Line LP2, BKR 8084 BFo 69kV Fort White Clay Electric Cooperative Tap Line LP2, BKR 8072 BFo 69kV Fort White Clay Electric Cooperative Tap Line LP1, BKR 8072 CTRL & MOS

8070 CTRLo Securityo P&C TSCADAo P&C Non-CONTROL CLOCKo IT/Telecom #2o IT/Telecom #1

3.3.3 Remote End Substations

There are three existing remote end substations associated with the interconnection including

Fort White (111), Fort White Clay Electric Cooperation Tap (6851) and High Springs (67)

substations.

Fort White Substation

The existing protection schemes at Fort White for the High Springs 69kV line will be upgraded

by the end of 2018 to include Line Current Differential protection under a separate, in-process

project. Upon commissioning of the 69kV Columbia Switching Station, the relay settings for the

Fort White to High Springs 69kV line will be modified to accommodate what will become the

Fort White to Columbia Switching Station 69kV line.



High Springs Substation

The existing protection schemes at High Sprints for the Fort White 69kV line will be upgraded

by the end of 2018 to include Line Current Differential protection. Upon commissioning of the

69kV Columbia Switching Station, the relay settings for the High Springs to Fort White 69kV line

will be modified to accommodate what will become the High Springs to Columbia Switching

Station 69kV line.

Clay Electric Co-op Substation

Upon commissioning of the 69kV Columbia Switching Station, the incoming line name change

to Clay Electric Co-op will need to be communicated and updated on their system.

NRIS

▪ In addition to the new 69kV Columbia Switching Station and associated remote ends,NRIS also requires the following protection & control scope of work at PowerlineSubstation and Holder Substation based on the Q137 Shady Hills FS for the Powerline toHolder 230kV line:

o One (1) P&C line package at the Holder Substation location▪ 230kV Powerline Line LP1, BKR CTRL & MOS CTRL▪ 230kV Powerline Line LP2, BF

o One (1) P&C line package at the Powerline Substation location▪ 230kV Holder LP1, BKR CTRL & MOS CTRL▪ 230kV Holder LP2, BF


▪ The standard 69kV line protection includes primary & backup SEL-311L and SEL-411Lrelaying, breaker failure tripping is provided using SEL-451

▪ The project generating units will meet all applicable NERC Standards▪ NRIS only

o The standard 230kV line protection includes primary & backup SEL-311L and SEL-

411L relaying, breaker failure tripping is provided using SEL-451

o The new Powerline substation is assumed to be in-service, prior to the

construction of the upgrades associated with Q148 and is therefore not included

in the scope of work



3.3.5 Protection and Control Cost Estimate

ERIS

Q148 69kV Columbia Switching Station and Associated Remote Ends Protection and Control Cost

Estimated Cost ($)

Engineering $509,000


Labor $1,095,000

Other (includes Indirect Allocations) $478,000 Total $2,611,000

NRIS


Q148 69kV Columbia Switching Station and Associated Remote Ends

$2,611,000

Holder Substation (from Q137 Shady Hills FC)

$250,000

Powerline Substation (from Q137 Shady Hills FC)

$250,000

Total $3,111,000

3.4 Telecommunications

3.4.1 Work Scope

This project requires fiber to be installed to the proposed Columbia Switching Station for tele-protection and SCADA. ADSS will be installed from a splice point on the existing DEF FO 230kV line (Fort White to Ginnie Springs) to the Columbia Switching Station. Approximately 28,900 feet will be underground build and then connected to the new Columbia Switching Station. The Columbia Switching Station to Fort White 69kV line will include Direct Fiber and J-MUX forms of communication. The 69kV Columbia Switching Station to High Springs 69kV line will utilize J-MUX communication.

Procure and install as required the necessary equipment to support J-MUX and Direct Fiber at the Columbia Switching Station, this includes:

▪ One (1) GE JungleMUX device▪ One (1) Fiber Patch Panel▪ One (1) 2010 Connected Grid Router▪ Three (3) 2520 Connected Grid Switches▪ One (1) Positron Power



NRIS

In addition to the new 69kV Columbia Switching Station, NRIS also requires the following telecommunications scope of work at Powerline Substation and Holder Substation based on the Q137 Shady Hills FS for the Powerline to Holder 230kV line:

▪ Installation of fiber from the dead-end tower into the control house at Holder andPowerline

▪ Perform OPGW to ADSS transition splicing at the terminals at both substations▪ Perform OPGW line splicing at 5 locations along the line


▪ There is DC available to power the Telecom equipment▪ For the OPGW builds, splices will be performed where necessary along the routes

3.4.3 Telecommunications Cost Estimate

ERIS

Q148 69kV Columbia Switching Station Estimated Cost ($)

Engineering $62,000


Labor $180,000

Other (includes Indirect Allocations) $72,000 Total $600,000

NRIS


Q148 Columbia Solar Station Switch Yard $600,000

230 kV Line from Powerline Sub to Holder Substation

$192,000

Total $792,000



4.0 Connection Requirements

4.1 General

This Facilities Study document is intended to provide a basic scope definition of facilities on which the Transmission Company has based its facilities study and cost estimates. It shall serve as the basis for the facilities that the Transmission Company proposes to design, build, and operate in connection with interconnection of Customer generation in the Columbia County, FL area. DEF requires the installation of a Customer owned circuit breaker to be located at the high side of the Generator Step-Up Transformer (GSU).

4.2 Point of Interconnection

The point of interconnection (POI) will be the “face of steel” on the dead-end tower inside the proposed DEF 69kV Columbia Switching Station. The Customer will install and own the jumpers from the strain bus connection dead-end insulators to the 69kV disconnect switch in the 69kV Columbia Switching Station (See Appendix C). The Customer shall install a Phasor Measurement Unit (PMU) at the Point of Interconnection (POI), according to DEF’s Facility Connection Requirements.

The Customer will own, maintain and install all facilities from this point back to the proposed Solar PV Station including the strain bus.

4.3 Short-Circuit Withstand Capability

DEF assumes no responsibility for appropriately sizing the short circuit withstands capability of any equipment installed on the Customer’s Side of the POI. DEF will provide upon request the maximum available short circuit current based on its current models. The Customer will need to exercise extreme care in appropriately sizing its equipment while providing for reasonable margin for future increases in available short circuit current. The Transmission Company bears no responsibility in the sizing decision.

4.4 Equipment Ratings and Protection Coordination

Prior to finalizing the specification for the equipment necessary to interconnect to the power grid, the Customer shall consult with DEF to establish the required ratings necessary to reliably interconnect and provide the expected Voltage and VAR support as defined in the Interconnection and Operating Agreement. Specific parameters shall include but are not limited to available transformer taps and short circuit withstands capabilities.

Customer shall also coordinate their relay protection schemes to be in compliance with the DEF requirements.



4.5 Insulation Requirements

DEF’s standard requirements for equipment installed on the 69kV systems shall meet the following minimum Basic Insulation Level (BIL).

69kV BIL Basic Insulation Level (BIL) *350kV

* 550kV BIL required for Station Post Insulators and Airbreaks

4.6 Communications

The Customer will provide 48 fiber optic- cable (OPGW or ADSS) including a splice interface cabinet from the proposed Solar PV Plant to the POI as described in Section 4.2

4.7 Metering

Metering shall comply with Duke Energy Florida’s “Transmission Interconnection/Generation/Revenue Metering”, Rev. 11/7/2017. See Appendix D.

4.8 Grounding

Grounding of the Customer’s interconnect facilities shall comply with the requirements Duke’s STDP-STD-TRM-00098 rev. 000 “Standard Ground Grid System.” See Appendix E.



5.0 Cost Estimate Summary

ERIS

The ERIS option requires the installation of a 69kV Columbia Switching Station with a 4-terminal configuration including the associated transmission line work. Located in Columbia County, Florida, the station will be built at the interconnection point adjacent to the existing DEF Fort White and High Springs (FH) 69kV line. The ERIS estimated cost breakdown of the 69kV Columbia Switching Station is located below in the following table and is based on LGIA execution as identified in Section 2.0 Baseline Assumptions.

Q148 Columbia Switching Station

Engineering Material Labor Other (includes Indirect Allocations)

Total ERIS Estimate

Transmission Line $91,000 $303,000 $551,000 $204,000 $1,149,000

Switching Station Physical

$475,000 $1,515,000 $2,964,000 $1,025,000 $5,979,000

Protection and Control $509,000 $529,000 $1,095,000 $478,000 $2,611,000

Telecommunications $62,000 $286,000 $180,000 $72,000 $600,000

TOTAL $ 1,137,000 $2,633,000 $4,790,000 $1,779,000 $10,339,000

NRIS

The NRIS option includes the scope identified above under ERIS in addition to the necessary build of the third Powerline to Holder 230kV line, which currently is assigned to the Shady Hills (Q137) project. Per the Q137 Shady Hills LGIA, the project is expected to be completed by November 30, 2021. Substantial acceleration of this schedule is unlikely. If the In-Service Date (ISD) for this Q148 Facilities Study is after the Q137 Shady Hills ISD, no additional network upgrades beyond the scope identified for ERIS are required for Q148 to proceed with NRIS. The table below shows the NRIS estimated cost of the required facilities and builds necessary if completed prior to Q137 Shady Hills. If the planned Q148 ISD is after the Q137 ISD, the estimated cost for NRIS will be the same as the estimated cost for ERIS.

Project Total NRIS Estimate ($)

69kV Columbia Switching Station (from this facilities study) $10,339,000

Powerline to Holder 230kV Line and Substations (potentially required for NRIS, costs from Q137 Shady Hills)

$36,755,000

TOTAL ESTIMATE $47,094,000



6.0 Milestone Schedule

ERIS

The table below identifies completion timeframes for major activities for this project with an

expected ISD of 24 months from LGIA execution as identified in Section 2.0 Baseline

Assumptions.

Activity Date

Interconnection Agreement Executed LGIA

Initiate Request for Proposal LGIA + 2 weeks

Contract Award LGIA + 24 weeks

Permitting LGIA + 55 weeks

Line Engineering LGIA + 44 weeks

Civil Engineering LGIA + 60 weeks

Substation Physical Engineering LGIA + 60 weeks

Protection and Control Engineering LGIA + 64 weeks

Line Construction LGIA + 92 weeks

Civil/Control Equipment Enclosure Construction LGIA + 103 weeks

Substation Physical Construction LGIA + 100 weeks

Protection and Control Construction LGIA + 102 weeks

Ready for Backfeed LGIA + 96 weeks

In-Service LGIA + 104 weeks

Schedule durations may be impacted by outage availability and time of the year the work is

planned.

NRIS

Schedule for NRIS is dependent on the planned ISD for the 3rd Powerline to Holder 230kV

circuit, related to the Q137 Shady Hills project as identified in Section 5.0 Cost Estimate

Summary.



7.0 Appendices

Appendix A Location Map



Appendix B Switching Station Proposed Three-Line



Appendix C Point of Interconnection



Appendix D Metering Standard

(Attached)



Appendix E Grounding Standard

(Attached)



8.0 Facilities Study Approval This Facilities Study for the Columbia Solar Plant Interconnection reports on the Energy Resource Interconnection Service (ERIS) and Network Resource Interconnection Service (NRIS) required for a new Solar PV Plant to be located in Columbia County, FL.

Approval Signatures:

Ray De Souza Ed Scott Director, Transmission Engineering Director, Transmission Planning

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on

Inte

rco

nnec

tion

/Gen

era

tion

/Rev

en

ue M

ete

ring

Cre

ate

d b

y:

Jose

ph

L.

Sta

rnes

, M

ete

r E

ng

inee

rin

g a

nd

Su

ppo

rt

Ap

pro

ved

by:

Au

gu

st 1

6, 2

01

7

Rev

ise

d:

Nov

em

ber

7, 2

017

Du

ke E

ner

gy

Flo

rida

En

gr.

Doc

: T

ran

smis

sio

n In

terc

onn

ectio

n-G

ene

ratio

n M

ete

ring

Da

te:

Aug

ust

16

, 20

17

Pag

e 2

of

6

1.

SC

OP

E

1.1

Th

is

docu

men

t re

fers

to th

e D

uke

En

erg

y F

lorid

a r

equ

irem

en

ts f

or t

ran

smis

sio

n le

vel I

nte

rco

nne

ctio

n/G

ene

ratio

n/R

eve

nue

M

ete

ring

be

twee

n D

uke

Ene

rgy

Flo

rida

an

d an

y in

terc

on

nect

ion

an

d/o

r re

venu

e b

ase

d cu

stom

er/

util

ity b

ein

g se

rved

at

tran

smis

sion

vo

ltage

leve

ls 6

9kV

an

d ab

ove

.

1.2

S

ectio

ns

2 t

hro

ugh

7 a

dd

ress

the

ge

ne

ral i

nte

rco

nne

ctio

n re

qu

irem

ents

. 2

. L

OC

AT

ION

2.1

W

hen

a D

uke

Ene

rgy

Flo

rida

line

ter

min

al h

as

been

det

erm

ine

d to

be

wh

ere

inte

rcon

nec

t m

ete

rin

g is

to b

e in

sta

lled

, th

ere

will

b

e a

me

ter

pa

cka

ge w

ith p

rim

ary

an

d b

ack

up m

ete

rs.

Typ

ical

ly t

he

me

ter

pa

cka

ge s

hall

be in

sta

lled

in a

su

bst

atio

n c

ontr

ol

hou

se p

an

el.

3

. C

UR

RE

NT

IN

PU

T T

O M

ET

ER

ING

3.1

P

rimar

y M

ete

ring

CT

s

3.1

.1

Pri

ma

ry M

ete

ring

CT

s sh

all

be

hig

h a

ccu

racy

ext

end

ed

ra

nge

(H

AE

R)

curr

en

t t

ran

sfo

rme

rs w

ith a

ra

tio w

hic

h w

ill in

clu

de

the

con

tinu

ous

ratin

g of

the

conn

ect

ed d

evi

ces

at t

he

hig

hest

em

erg

enc

y ra

ting

of

the

ass

ocia

ted

ele

men

t.

3.1

.2M

inim

um

acc

ura

cy c

lass

: 0

.15

@ B

urd

en 1

.8

3.1

.3

Acc

ura

cy R

ang

e: *

*1%

- 2

00%

of

rate

d ra

tio (

20

400

0 a

mpe

res

usi

ng a

20

00:5

rat

io w

ith a

ra

ting

fact

or =

2.0

as

an

e

xam

ple

) .

CT

s w

ith 5

% -

200

% o

f ra

ted

rat

io is

als

o a

cce

pta

ble

.

3.2

N

o bu

rde

n o

ther

tha

n th

e m

ete

r sh

all

be c

onn

ect

ed

in th

e m

ete

ring

CT

cir

cuits

.

3

.3C

T r

atio

3.3

.1

CT

rat

io s

ha

ll b

e e

ither

100

0:5

or 2

00

0:5

de

pen

din

g on

the

lim

itin

g e

lem

ent

fact

or.

Th

e r

atio

sha

ll be

as

sma

ll as

po

ssib

le

to p

rovi

de t

he r

equi

red

acc

ura

cy a

t lo

w lo

ads

.

3.3

.2

CT

rat

io s

ho

uld

als

o be

larg

e e

nou

gh th

at t

he

se

con

dary

cu

rre

nt

is le

ss t

han

the

co

ntin

uo

us

ratin

g of

the

conn

ect

ed

d

evic

es

at

the

hig

he

st e

me

rgen

cy r

atin

g o

f th

e a

sso

cia

ted

ele

me

nt.

3.3

.3T

he

the

rma

l ra

ting

fact

or

sha

ll b

e 2

.0 a

t 3

0 d

egr

ee

s C

. T

he t

herm

al r

atin

g s

ha

ll be

se

lect

ed

such

tha

t th

e se

lect

ed

CT

3.3

.4

En

gine

erin

g sh

all

req

uire

the

man

ufa

ctu

rers

to p

rovi

de te

st d

ata

for

met

erin

g C

Ts,

and

sh

all f

orw

ard

th

is d

ata

to

Me

terin

g

Ser

vice

s.

En

gr.

Doc

: T

ran

smis

sio

n In

terc

onn

ectio

n-G

ene

ratio

n M

ete

ring

Da

te:

Aug

ust

16

, 20

17

Pag

e 3

of

6

4.

VO

LT

AG

E I

NP

UT

TO

ME

TE

RIN

G

4.1

A

PT

or

CC

VT

with

thr

ee (

3) s

eco

nda

ry w

ind

ings

is r

equ

ired

fo

r th

e p

rima

ry a

nd

ba

ckup

inte

rcon

nec

tion

me

teri

ng.

Th

e

e

r a

t WX

Y &

Z b

urd

en.

4.2

T

he

prim

ary

an

d b

acku

p m

ete

rs s

ha

ll b

e c

on

nect

ed

to th

e 1

20 v

olt

win

din

gs.

4.3

E

ngin

ee

ring

sha

ll re

quire

the

man

ufa

ctu

rers

to p

rovi

de t

est

da

ta fo

r m

ete

ring

PT

s o

r C

CV

Ts,

and

sh

all

forw

ard

th

is d

ata

to

M

ete

r O

pera

tion

s.

4.4

P

rimar

y M

ete

ring

4.4

.1

4.4

.2

No

bu

rde

n o

ther

th

an th

e m

ete

r sh

all

be c

onne

cte

d in

this

me

teri

ng s

eco

ndar

y P

T c

ircu

it.

5.

ME

TE

R

5.1

T

he

Flo

rida

Me

ter

Dep

artm

ent

sha

ll p

rovi

de a

nd

ma

inta

in th

e p

rim

ary

an

d b

acku

p m

ete

rs.

5.2

A

fou

r-q

ua

dra

nt, b

i-d

irect

ion

al,

thre

e e

lem

en

t rev

en

ue

cla

ss m

ete

r sh

all b

e us

ed f

or

the

pri

ma

ry a

nd

ba

cku

p m

ete

r. T

he

me

ter

sha

ll be

ca

pa

ble

of p

rod

ucin

g th

e fo

llow

ing

out

pu

ts:

a.

Kw

h (

De

live

red

/Re

ceiv

ed)

b.

Kva

rh (

De

live

red/

Re

ceiv

ed)

c.

Inst

anta

neo

us th

ree

ph

ase

wat

ts

d.

Inst

anta

neou

s th

ree

ph

ase

va

rs

e.

Inst

anta

neou

s si

ngl

e p

hase

vo

ltsf.

In

stan

tane

ous

sin

gle

pha

se a

mp

s

5.3

T

he

me

ter

sha

ll be

pro

vid

ed

with

Eth

erne

t an

d R

S-2

32/4

85

com

mu

nic

atio

n p

ort

s a

nd s

hall

sup

port

DN

P-3

.0 p

roto

col.

5.4

T

he

me

ter

sha

ll ha

ve th

e c

apa

bili

ty o

f co

nne

ctin

g to

the

sta

tion

serv

ice

au

xilia

ry 1

20 v

olt

AC

pow

er

sou

rce

.

6.

ME

TE

R O

UT

PU

T

6.1

Prim

ary

an

d B

acku

p M

ete

ring

6.1

.1

Th

e P

rimar

y a

nd

Bac

kup

met

ers

ou

tput

s sh

all b

e co

nn

ect

ed to

the

Sub

stat

ion

RT

U v

ia th

e E

the

rne

t co

mm

un

ica

tion

po

rt.

En

gr.

Doc

: T

ran

smis

sio

n In

terc

onn

ectio

n-G

ene

ratio

n M

ete

ring

Da

te:

Aug

ust

16

, 20

17

Pag

e 4

of

6

7.

ME

TE

R IN

ST

AL

LA

TIO

N P

AC

KA

GE

7.1

C

ontr

ol H

ou

se P

ane

l (S

ee F

igur

e 1

)

7.1

.1

Kem

co P

late

(R

U J

EM

-1)

7.1

.2

2 J

EM

ST

AR

II

swit

chbo

ard

met

ers

wit

h ca

se

Pri

mar

y/B

acku

p (S

uppl

ied

by M

eter

Dep

artm

ent)

7.1

.3

2

FT

-1 F

lexi

10

pol

e t

est

switc

h (c

urre

nt/

volta

ge)

(S

ub

stat

ion

sup

plie

d)

7.1

.4

1 F

T-1

Fle

xi 1

0 po

le T

est s

wit

ch (

volt

age

only

) (S

ubst

atio

n su

ppli

ed)

7.1

.5

1 3

pos

ition

sel

ecto

r sw

itch

(Sub

stat

ion

supp

lied

)

7.1

.6

If th

e m

eter

is lo

cate

d on

the

dist

ribu

tion

side

(25

KV

and

bel

ow)

of th

e po

wer

tran

sfor

mer

, the

CT

s an

d PT

s w

ill b

e su

ppl

ied

by

the

Met

er D

epar

tmen

t.

7.2

Sub

sta

tion

yar

d M

ete

r C

ab

ine

t(S

ee

Fig

ure

2)

7.2

.1

1

40

x40x

15 A

lum

inu

m M

ete

r C

ab

ine

t 7

.2.1

.1

All

Me

ters

an

d c

om

pone

nts

in

sid

e th

e m

ete

r ca

bin

et i

s su

pplie

d b

y th

e M

ete

r D

epa

rtm

en

t (in

clu

din

g t

he

40x

40x

15 c

abin

et)

7.2

.2.1

If

the

me

ter

is lo

cate

d o

n th

e d

istr

ibut

ion

sid

e (2

5 K

V a

nd b

elo

w)

of

the

po

we

r tr

ans

form

er,

the

CT

s an

d P

Ts

will

be

su

pp

lied

by

the

Met

er D

epa

rtm

ent

.

7.3

En

gr.

Doc

: T

ran

smis

sio

n In

terc

onn

ectio

n-G

ene

ratio

n M

ete

ring

Da

te:

Aug

ust

16

, 20

17

Pag

e 5

of

6

Fig

ure

1

En

gr.

Doc

: T

ran

smis

sio

n In

terc

onn

ectio

n-G

ene

ratio

n M

ete

ring

Da

te:

Aug

ust

16

, 20

17

Pag

e 6

of

6

Fig

ure

2

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