Toronto Hydro-Electric System Limited
EB-2011-0144
Exhibit G1
Tab 1
Schedule 2
ORIGINAL
(146 pages)
THESL 2012 GEA PLAN
Plan for Implementing Requirements of Green
Energy and Green Economy Act, 2009
August 1, 2011
TABLE OF CONTENTS
Acronyms & Definitions: ......................................................................................................................... 3
1
Executive Summary ........................................................................................................................... 4
1.1
summary of current system constraints ......................................................................... 4
1.2
Renewable Generation ...................................................................................................... 6
1.3
Smart Grid .......................................................................................................................... 8
2
Current Assessment of System....................................................................................................... 11
2.1 Factors Limiting Renewable Energy Generation Connections ............................................ 12
2.1.1
Short Circuit Capacity ..................................................................................................... 13
2.1.2
HONI Short Circuit Limits ............................................................................................. 13
2.1.3
THESL Short Circuit Limits ............................................................................................ 16
2.1.4
Feeder Thermal Rating and Transformer Thermal Capacity ..................................... 17
2.1.5
Distribution System Continuous Feeder Thermal Rating .......................................... 18
2.1.6
HONI-Owned Transformer Station Thermal Limits .................................................. 19
2.1.7
Protection Constraints ..................................................................................................... 19
2.1.8
Feeder Load Diversity ..................................................................................................... 19
2.1.9
Contingency Load Transfer Scenarios .......................................................................... 20
3
Planned Development to Enable Renewable Generation Connections .................................. 23
3.1
Overview .......................................................................................................................... 23
3.1.1
Forecast for Renewable Generation Connections ........................................................ 25
3.1.2
Selecting Renewable Energy Generation Enabling Projects ...................................... 27
3.2
Generation Connection Projects .................................................................................... 36
4
Smart Grid ......................................................................................................................................... 41
4.1
Smart Grid – Current Assessment................................................................................. 42
4.2
Smart Grid Demonstration Projects .............................................................................. 46
4.3
Smart Grid Studies and Planning Exercises ................................................................ 51
5
GEA Plan Cost and Allocation ....................................................................................................... 52
5.1
GEA Plan Cost Summary ............................................................................................... 52
5.2
GEA Plan Cost Allocation (Direct Benefits) ................................................................. 53
Appendix A: Description of THESL System ...................................................................................... 54
Appendix B: System Capacity vs. Proposed Generation To-Date (203MW) ................................. 57
Appendix C: System Capacity vs. Forecast Generation After 5 Years (450MW) ........................... 64
Appendix D: DG Interconnection Capacity Study (May, 2011 Navigant) ..................................... 71
Appendix E: Potential Renewable Generation Enabling Options ................................................... 72
Appendix F: Energy Storage (> 6 Hours Capacity) ............................................................................ 76
Appendix G: Direct Benefits Calculation............................................................................................. 82
Appendix H: Generation Connection Process & Fees ....................................................................... 83
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ACRONYMS & DEFINITIONS:
CAES
- Compressed Air Energy Storage
CEATI
- Center for Energy Advancement through Technological Innovation
CES
- Community Energy Storage – shorter duration systems < 30 minutes capacity
CHP
- Combined Heat and Power – providing electricity and thermal energy
CIA
- Connection Impact Assessment
DESN
- Dual Element Spot Network – common transformer station design which
provides redundancy for major components
DG
- Distributed Generation – various generation types both non-renewable and
renewable energy which are located close to customer loads
DSC
- Distribution System Code
EDR
- Electrical Distribution Rate – filed regularly with OEB for LDC rate applications
EPRI
- Electric Power Research Institute
ES
- Energy Storage – longer duration systems > 6 hours capacity
EV
- Electric Vehicles – includes PHEVs or Plug-in Hybrid Electric Vehicles
FIT
- Feed-In Tariff program implemented by OPA to procure renewable energy
GEEA
- Green Energy and Green Economy Act
HONI
- Hydro One Networks Inc. – Ontario’s transmitter and rural distributor
IEC
- International Electrotechnical Commission
IESO
- Independent Electricity System Operator for Ontario
LDC
- Local Distribution Company
LiIon
- Lithium Ion (or Lithium Polymer) storage system
M
- million
NaS
- Sodium Sulphur energy storage system
NIST
- National Institute of Standards and Technology
OEB
- Ontario Energy Board – Ontario’s regulator for transmitters and distributors
OPA
- Ontario Power Authority – Ontario’s procurement agency for electrical capacity
PHEV
- Plug-In Hybrid Electric Vehicles
RE
- Renewable Energy – typically biogas, solar, wind, etc. sourced generation
REI
- Renewable Enabling Improvements – typically protection and control devices
as distinct from expansions (which are typically feeders)
SF6
- Sodium Hexafluoride (used as insulator in breakers)
SG
- Smart Grid – emerging technologies providing adaptive electrical systems
THESL
- Toronto Hydro-Electric System Limited
TS
- Transformer Station, providing 230kV/27.6kV or 115kV/13.8kV conversion
TSC
- Transmission System Code
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1
EXECUTIVE SUMMARY
This five-year GEA Plan is submitted to the Ontario Energy Board (OEB) in parallel with
THESL’s 2012 Electricity Distribution Rate Application (EB-2011-0144). This GEA Plan
proposes a total capital investment of $152M over five years and a total operating expense of
$5M over five years. The result of these investments will enable at least 320 MW of renewable
generation, implement smart grid adaptive technology and improve reliability across Toronto.
Project technologies include shared station upgrades, express feeders, upgraded feeders, in-line
reactors, advanced protection /monitoring/controls, energy storage, generation
dispatch/monitoring centre, smart sensors and electric vehicle infrastructure integration.
THESL expects the grid will undergo a transition from a centralized network with large
generators to a decentralized, user-interactive network with generation close to load centres.
This GEA Plan is developed as part of THESL’s application for rates to be effective in 2012 and
subsequent years. Information provided addresses enabling renewable generation connections,
including energy storage and development of a smart grid, including electric vehicles. This
GEA Plan is coordinated with infrastructure cost recovery THESL is seeking through its
associated EDR application. Emerging technologies are allocated within the GEA Plan while
sustaining infrastructure is allocated within the EDR filing. Specific capital expenditures and
expected operating expenses are defined for the first year, and the general level and type of
investments and expenses anticipated for years 2-5 are provided. OPA and HONI stakeholders
have been consulted via 4 working sessions between February 10, 2011 and May 31, 2011 and
stakeholder feedback is provided separately per OEB directives.
1.1
SUMMARY OF CURRENT SYSTEM CONSTRAINTS
The GEA Plan starts with a review of the current status of the THESL system, and discusses
existing limitations on the ability to connect renewable energy (RE) and distributed generation
(DG) within both the Hydro One Networks Inc. (HONI) transmission system and the THESL
distribution system. It also summarizes work completed or planned to address these
limitations and to prepare for and implement Smart Grid (SG) capabilities.
Various constraints limit THESL’s ability to connect renewable generation; however, the key
constraint, both within HONI transmission and within THESL distribution, is short circuit
capacity. Figure ES-1 shows the areas within Toronto where renewable generation connection
capacity is constrained due to short circuit limits at individual stations directly connected to
THESL feeders and due to constraints on specific HONI transmission facilities, specifically the
Downtown Toronto 115kV and Scarborough East 230kV areas. Figure ES-2 shows areas within
Toronto which are constrained by short circuit limits at individual stations directly connected to
THESL feeders, in absence of HONI 230kV and 115kV transmission constraints noted in Figure
ES-1. The majority of short circuit capacity constraints are within HONI transmission facilities.
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Figure ES-1: Hydro One Short Circuit Capacity Constraints
Figure ES-2: THESL Short Circuit Capacity Constraints (Excl. 230kV, 115kV HONI Constraints)
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HONI is planning breaker upgrades at Leaside Transformer Station (TS) which will improve the
short circuit constraints in 2013. Since investments in THESL system improvements in the area
currently constrained by HONI limitations would not result in an increase in connection
capacity, THESL will first proceed with Horseshoe 230kV area projects (served by Leslie TS and
Richview TS) which address THESL distribution system limits outside of the area affected by
the HONI constraints. Investments to improve connection capacity in the area affected by
HONI constraints will then be scheduled to coincide with the TS improvements being
undertaken by HONI. The specifics of these projects are discussed in the following sections.
THESL’s plans for developing adaptive SG capabilities are presented separately within this
GEA Plan in keeping with the direction given by the OEB. It should be noted, however, that the
two activities are in many respects strongly inter-related. SG capabilities, for example, can help
to enable higher levels of renewable connectivity, or reduce the cost of accommodating a given
level of renewable capacity. In developing its plans, THESL follows an integrated planning
process which considers these inter-relationships as well as the interactions between renewable
connections, smart grid enhancements and the on-going work of maintaining and improving
the overall distribution system serving Toronto.
Energy storage systems are being considered as an element of both the renewable generation
and SG plans. Large energy storage (ES) systems, located at the TS level, with capacity to
supply energy for at least six hours will be used to support the integration of RE generation into
the THESL system, provide contingency and manage peak prices. Community Energy Storage
(CES) systems with capacity under 30 minutes, located within specific feeders will be used to
meet different system objectives (e.g., transients) as part of the SG plan. Integration of electric
vehicles is being included in SG plans, given the potential uptake and emerging grid
management issues and potential two-way power flow.
1.2
RENEWABLE GENERATION
The analysis addresses applications from renewable generators for connection in THESL’s service
area; the overall potential for developing renewable generation in THESL’s service area; constraints
within THESL’s distribution system related to the connection of renewable generation; upstream
constraints of HONI, THESL’s transmitter, that affect the ability to accommodate renewable
generation connection in THESL’s service area; and any information received from the OPA regarding
integrated planning for regions of the province or the province as a whole. Consultations are ongoing
with OPA and HONI in assessing available capacity.
This GEA Plan confirms that short circuit limits in central and downtown Toronto can
significantly limit new RE capacity. At present RE sources are constrained to 10 MW in the
Downtown Toronto 115kV area and 10 MW in the Scarborough East 230kV area due to limited
transmission available fault current at HONI’s Leaside Station.
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At this time THESL’s customers have enquired about connecting over 190 MW of inverterbased PV systems and synchronous generation through pre-assessments. THESL has forecasted
that over the next five years there will be 450 MW of renewable generation based on the pace of
proposed connections. This projection is based upon the number of potential connections,
based on current applications, assumptions about government and OPA policies, etc., but as a
result of current restrictions, applicants may not be approaching THESL in areas where project
developers know that system restrictions preclude connections. THESL therefore feels that past
levels of applications may not provide a reasonable basis for forecasting future demand,
particularly in terms of where that demand for renewable connections may arise. As such,
THESL is anticipating between 320MW and 640MW of required capacity upgrades within the
system. THESL recognizes that there is some uncertainty in these forecasts and will update
years 2013 through 2016 as more data become available regarding actual interconnections.
THESL’s proposed approach is designed to remove limitations on its system in order to provide
uniform access to potential RE generation connections across its system. Project technologies
include shared HONI station upgrades, express feeders, upgraded feeders, in-line reactors,
advanced protection /monitoring/controls, long-duration energy storage and a generation
dispatch/monitoring centre. The specific projects proposed to enable renewable generation
connections are shown in Table ES-1 below. These projects are presented in detail in Section 3.
Table ES-1: Enabling Improvements and Associated Cost Estimates
Number
Enabling Option/Method
Estimated Cost
1
HONI Transformer
Replacement
$8,000,000 to $10,000,000 for
replacement of two units
(THESL capital contribution
estimated as 40% of $8M to
10M)
4-5 years
2
New MS
$7,000,000/Installation
3-5 years
3
Express Feeder
$3,000,000/feeder
2-3 years
4
In-line reactor
$100,000/Installation
2-3 years
5
Fault current limiting
devices
$60,000/MW
2-3 years
6
Advanced protection and
control scheme
$150,000/Installation
2-3 years
7
Generator monitoring and
controls
$25,000/Installation
2-3 years
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Construction period
Table ES-1: Enabling Improvements and Associated Cost Estimates
Number
Enabling Option/Method
8
Feeder cut & Tie
9
10
1.3
Estimated Cost
Construction period
$25,000/Installation
1-2 years
Energy Storage (NaS
Battery or CAES)
$15,000,000/Installation
(2MW-6 hour capacity)
1-2 years
Generation Dispatch /
Monitoring Centre
$2,000,000/Installation
1-2 years
SMART GRID
THESL’s approach for Smart Grid (SG) development is aligned with the Green Energy and Green
Economy Act, 2009 (GEEA). THESL is seeking cost recovery for 2012 capital investment for
demonstrating the use of emerging, innovative and energy saving technologies while
promoting an adaptive infrastructure.
THESL has followed the GEEA definition of SG as the ‚application of advanced information
exchange systems and equipment that when utilized together improve the flexibility, security, reliability,
efficiency and safety of the integrated power system and distribution systems, particularly for the
purposes of,
Enabling the increased use of renewable energy sources and technology, including generation
facilities connected to the distribution system;
Expanding opportunities to provide demand response, price information and load control to
electricity customers;
Accommodating the use of emerging, innovative and energy-saving technologies and system
control applications; or
Supporting other objectives that may be prescribed by regulation.‚
THESL’s smart grid approach is also coordinated with the following activities to help ensure SG
efforts are not duplicated across the industry:
Ministry of Energy Directive (Nov. 23, 2010) advocating Customer Control, Power
System Flexibility and Adaptive Infrastructure
Ontario Smart Grid Forum – industry forum for visioning Ontario’s electricity system
Feed-in Tariff (FIT) – comprehensive program expected to substantially increase the
deployment of renewable generation in Ontario
City of Toronto’s ‚Change is in the Air: Clean Air, Climate Change, and Sustainable Energy
Action Plan‛ – municipal government policy that includes becoming the renewable
energy capital of Canada
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City of Toronto Electric Vehicle Working Group, Toronto Atmospheric Fund: Targets for
the introduction of Electric Vehicles (EV) including the EV300 initiative and City of
Toronto response to provincial goal that one in 20 vehicles be electric by 2020
The key objectives for THESL’s adaptive SG are:
Manage risks associated with ageing and congested infrastructure
Provide enhanced visibility and control throughout the network
Monitor and manage power quality levels and system losses
Improve effectiveness of utility operations including outage management
Provide customers with streamlined processes for the connection of renewable
generation
Support microgrids, community energy storage, and conservation and demand
management efforts which reduce emissions
Enable electric vehicle transportation infrastructure
THESL envisions SG investments adding value by offering new and effective forms of
communications to customers and enabling new customer service models with information,
options and controls to manage their energy use and energy cost. Project technologies include
energy storage, smart sensors and electric vehicle infrastructure integration and are presented
in detail in Section 4.
The investments which enable RE generation and develop the SG are shown in Table ES-2
(Capital Expenditures), Table ES-3 (Cost Allocation) and Table ES-4 (Operating Expenses).
Under the GEA Plan, THESL is seeking capital investment of $152M over five years and
operating expenses of $5M over five years. The result of these investments will enable
renewable generation, implement smart grid adaptive technology and improve reliability across
Toronto.
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Table ES-2: 2012 – 2016 GEA Plan Capital Expenditures (Totals may not match per rounding)
Capital
Expenditures
2012
2013
2014
2015
2016
Subtotals
Enabling
Renewables
$25.1M
$32.9M
$32.9M
$20.3M
$20.3M
$131.6M
Developing
Smart Grid
$3.5M
$4.0M
$4.0M
$4.5M
$4.5M
$20.5M
Subtotals
$28.6M
$36.9M
$36.9M
$24.8M
$24.8M
$152.1M
Table ES-3: 2012 – 2016 GEA Plan Cost Allocation (Direct Benefits)
Capital
Expenditures
2012
2013
2014
2015
2016
Subtotals
Gross Cost
$28.6M
$36.9M
$36.9M
$24.8M
$24.8M
$152.1M
Less Generator
Contribution
$0.0M
$0.0M
$0.0M
$0.0M
$0.0M
$0.0M
Less Provincial
Recovery
$22.0M
$28.3M
$28.3M
$17.6M
$17.6M
$113.9M
THESL Cost (Net)
$6.6M
$8.6M
$8.6M
$7.2M
$7.2M
$38.2M
Table ES-4: 2012 – 2016 GEA Plan Operating Expenditures
Operating
Expenses
2012
2013
2014
2015
2016
Subtotals
Enabling
Renewables
$0.2M
$0.2M
$0.2M
$0.2M
$0.2M
$1.0M
Developing
Smart Grid
$0.6M
$0.85M
$0.85M
$0.85M
$0.85M
$4.0M
Subtotals
$0.8M
$1.05M
$1.05M
$1.05M
$1.05M
$5.0M
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2
CURRENT ASSESSMENT OF SYSTEM
Overview:
An overview of the history and topology of the current THESL distribution system is provided
in Appendix A. THESL’s distribution system is a relatively mature system operating in an
intensively developed urban area. Introducing new generation capacity in this context
represents a number of unique challenges compared with other Ontario LDCs.
With the enablement of the GEEA, generation sources including biogas, solar photovoltaic (PV)
and wind power generation have been introduced to the distribution system for RE generation.
The conventional approach of large, distant generating stations linked by transmission systems
to distribution systems must adapt to accommodate RE sources which are typically located
close to distribution loads. Figure 1 below illustrates at a high level the emergence of RE
sources on the distribution system. THESL’s GEA Plan aims to identify enablement options to
connect the renewable energy systems as per OEB guidelines and DSC rules.
Figure 1 - Emerging Renewable Energy and DG Integration with Electrical Grid
There are various constraints limiting THESL’s ability to connect renewable generation,
including fault current, thermal limits, minimal flows and the ability to transfer loads between
feeders in the event of a contingency. The primary constraint for renewable energy generation,
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however, is short circuit capacity. At present, the ability to connect new renewable generation
is limited by constraints both within the HONI transmission system and within the THESL
distribution system, as will be discussed later in this section. Figure 3 shows the areas within
Toronto where renewable generation connection capacity is constrained due to short circuit
capacity. The top map in Figure 3 shows areas where short circuit capacity is limited at
individual stations directly connected to THESL feeders and due to constraints on specific
HONI 115kV transmission facilities. The second map in Figure 3 shows areas within Toronto
which where capacity is constrained by short circuit limits at individual stations directly
connected to THESL feeders. A comparison of the two Figures shows that the majority of the
constrained area is limited by HONI short circuit capacity constraints.
HONI is planning improvements at Leaside TS and Hearn TS which will remove the short
circuit constraints. THESL anticipates completion of this work by the end of 2013. Since
investments in THESL system improvements in the area constrained by HONI limitations
would not result in an increase in connection capacity, THESL proposes to first proceed with
projects to address limits within its own distribution system outside of the area affected by the
HONI constraints (Leslie and Richview areas). Investments to improve connection capacity in
the area affected by HONI constraints will then be scheduled to coincide with the TS
improvements being undertaken by HONI. The specifics of these projects are discussed in the
following sections.
2.1 FACTORS LIMITING RENEWABLE ENERGY GENERATION CONNECTIONS
THESL has identified a number of constraints within its system that have an impact on the
investment and interconnection-related decisions of certain of its downstream customers. These
constraints also limit THESL’s ability to connect RE generation into its system. In HONI’s
recent rate filing (EB-2010-0002), transmission constraints at both its Manby and Leaside
Transformer Stations (TS) were identified, each having an impact on THESL’s ability to approve
requests for DG interconnection. A synopsis of system constraints includes the following:
Short circuit capacity constraints per TSC limits;
Thermal Capacity on Station Transformers that limits reverse power flow;
Minimum bus load requirements to limit reverse power flow; and,
Short circuit capacity constraints due to transmission breaker capacity.
Technical constraints also exist within THESL’s distribution system downstream of the TS.
However, as this GEA Plan demonstrates, most technical limitations within the distribution
system are subsumed by those imposed at the HONI transmission station bus level.
For large generation or aggregated generation connections, another constraint includes the
feeder continuous load thermal ratings.
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While both short circuit capacity and reverse power flow limits are constraints within the
transmission and distribution systems, they reflect the technical limits of existing transformer
stations or issues that exist upstream on the transmitter’s system, i.e., circuit breaker capacity
constraints at Leaside and Manby TSs.
Constraints at HONI’s Leaside and Manby 230/115kV transformer stations have imposed
limitations on both short circuit and thermal capacity within the THESL distribution system,
and impact THESL’s ability to interconnect new generation in the 13.8kV downtown system.
These sections present operating, capacity and performance factors that can limit generation
connections on related HONI transmission stations and THESL’s distribution system. THESL’s
analysis excludes factors that could impact bulk transmission operations or planning, or IESO
control area generation performance.
2.1.1
SHORT CIRCUIT CAPACITY
Short circuit limits on both the THESL and HONI systems are important factors in the
determination of how much DG can be installed on THESL’s distribution system. Prior capacity
studies (Navigant DG Report, April, 2011, included as Appendix D) confirm short circuit limits
on station equipment to be one of the primary limiting factors on the amount of DG that can be
installed in certain areas of the THESL system, particularly in downtown Toronto. Station
equipment – often in the same location – is owned partly by HONI, and partly by THESL.
Typically, HONI owns and operates all equipment from the low voltage side of station power
transformers up to and including higher voltage transmission equipment. THESL typically
owns lower voltage station circuit breakers and switchgear line. Recent studies of the potential
for DG in Toronto and recent applications for FIT connection underscore the impact of short
circuit capacity on allowable DG penetration. This GEA Plan confirms that short circuit limits
in central and downtown Toronto can significantly limit renewable energy sources. At present,
renewable energy sources are constrained to 10 MW in the Downtown Toronto 115kV area and
10 MW in the Scarborough East 230kV area due to limited transmission available fault current
at HONI’s Leaside Station as illustrated in Figure 2 below.
2.1.2
HONI SHORT CIRCUIT LIMITS
HONI short circuit limits in the Toronto area are well documented. Figure 2 illustrates the three major
HONI in-City stations equipped with devices that are nearing fault current limits. This equipment is
mostly circuit breakers and ancillary equipment rated for 40kA (40,000 amps). The Transmission
System Code specifies that for the 115 kV system the standard is 50kA. Amongst the three
stations, Leaside is most susceptible to short circuit violations, including those caused by incremental
fault current contributions from new DG. In EB-2010-0002, HONI received approval to upgrade Leaside
and replace the breakers with higher rated equipment by the end of 2013.
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Figure 2: Downtown Short Circuits Limits
4
Short circuit levels near
station equipment capability
(~40, 000 A) at Hearn,
Manby and Leaside
Transformer Stations
Source: Electricity Service
to Central and
Downtown Toronto,
Ontario Power Authority,
September 25, 2008
THESL is affected by transmission constraints imposed by HONI which constraints limit the
amount of the DG that can be connected. Due to short circuit constraints at Leaside and Hearn
115 kV switchyards, Hydro One has restricted the amount of renewable DG that can be
connected in the Leaside 115 kV area and the Cherrywood TS to Leaside TS 230 kV area to a
total of 10 MW each until such time as the upgrade work is complete.
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Figure 3: Short Circuit Limits in HONI and THESL Systems
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Table 1: THESL TS areas and applicable HONI Constraints
Transmission
Stations Affected by Constraints
Supply System
Station
Region
Capacity
230 kV Richview To
Rexdale, Woodbridge, Richview,
Local station
Horseshoe 230kV
Cherrywood
Manby, Horner, Finch, Bathurst,
limits apply; No
Supply
Fairchild, Leslie, Agincourt,
Major Trans.
Cavanagh, Malvern
Constraint
230 kV Leaside to
Ellesmere, Scarborough, Warden,
10 MW-230kV
Scarborough East
Cherrywood
Sheppard, Bermondsey, Leaside
cumulative
230 kV Supply
Constraint
115 kV Leaside and
Runnymede, Fairbank, Wiltshire,
10 MW-115 kV
Downtown
Manby
Dufferin, Duplex, Highlevel,
cumulative
Toronto 115kV
Strachan, Glengrove, Cecil,
Constraint
Supply
Terauley, Windsor/John,
Esplanade, Charles, Leaside,
Gerrard, Basin, Carlaw, Main
2.1.3
THESL SHORT CIRCUIT LIMITS
The primary limiting element for short circuit capacity is substation equipment (where fault
current levels are highest), mostly, substation low-side breakers. Fault studies conducted by
THESL confirm that stations serving 27.6kV primary distribution have significantly greater
spare short circuit capacity than downtown stations serving 13.8kV distribution.
Most THESL equipment that is susceptible to short circuit capacity restrictions is located within
the low voltage side of stations where it owns and operates equipment. Most THESL station
equipment subject to short circuit limits is comprised of older 13.8kV stations in downtown
Toronto; in contrast, a higher margin of available short circuit capacity exists on the 27.6kV
system.
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THESL stations comply with short circuit requirements outlined in the TSC. For 13.8 kV
stations, the metal-clad switchgear and breakers meet the TSC requirement of 21kA or 500 MVA
class rating. In the 27.6 kV system, the breakers satisfy the 17 kA or 800 MVA class rating.
When assessing proposed generation connections a reserve margin of 5% is maintained on the
short circuit rating. This provides Hydro One the required margin for potential station
transformer replacement. It has been observed that for stations configured in the dual winding
Bermondsey type scheme, typically a considerable short circuit margin exists. In stations
configured as simple DESNs or Jones type scheme, however, the existing station fault levels
have surpassed the reserve margin and encroached on the short circuit class rating of 500 MVA
and 800 MVA for 13.8KV and 27.6KV, respectively. OEB requires a list of constrained feeders
which THESL provides as its respective bus (feeder point). The busses with short circuit
constraints, listed in Table 2 below, prevent the connection of generation at this time.
Table 2: Station Busses with No Available Short Circuit Capacity (HONI List of Station Capacity, June
30th, 2011 update)
Station
Bus (Feeder Point)
Bridgman
A5A6H Bus Total
Carlaw
A4A5 Bus Total
B1B2 Bus Total
B3B4 Bus Total
Cecil
A1A2 Bus
Fairbank
YZ Bus
Gerrard
A1A2 Bus
Leslie
BY Bus Total
Richview
BY Bus Total
Wiltshire
B1B2 Bus Total
A1A2 Bus Total
A3A4 Bus Total
Woodbridge
2.1.4
BY Bus Total
FEEDER THERMAL RATING AND TRANSFORMER THERMAL CAPACITY
Thermal capacity in both the transmission and distribution systems is largely based on the
physical properties of various types of equipment including the actual cables from which
feeders are constructed and the windings and internal and external equipment from which
primary transformers are built. As current flows through a conductive element the resistance of
that element produces a certain amount of heat which that element must be able to safely
withstand. Further, lines and equipment that deliver electric power typically are rated to
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withstand a threshold level of current when line faults or short circuit conditions exist; this is
commonly referred to as fault duty or capacity. Lines and equipment typically are capable of
carrying very high levels of current for a short time interval, that is, the time typically required
for protective devices to electrically isolate and interrupt a fault before it damages equipment.
Transmission system assets including lines and transformer stations (up to and including the
low-side of the station power transformer) are owned by HONI. Distribution system assets
such as distribution feeders (overhead lines and underground cable), distribution transformers
and metering are owned by THESL. THESL distribution assets include transformer station low
voltage bus and breakers in the central and downtown Toronto, 115 kV areas, and feeder
breakers in the North York area. HONI owns station low voltage breakers in all other areas.
Thermal capacity on the station bus presents a notable constraint for renewable energy
connections. Thermal capacity represents the estimated nameplate amount of generation that
can be connected to the bus. THESL criteria are consistent with HONI methodology which
limits the amount of generation on a bus before exceeding reverse power flow limits to the
station transformer. To satisfy this criterion THESL reviews minimum bus load for each of its
35 transformer stations and ensures proposed renewable generation connections are within this
limit.
Where DG installation at the distribution level exceeds the continuous rating of lines, cables or
station equipment, mitigation of these impacts or construction of dedicated lines may be
needed. While typically the maximum DG sizes are limited to 10 MVA and 20 MVA on 13.8kV
and 27.6kV feeders, respectively, the combined output of several feeders from a common bus
may cause thermal loading violations. Further, large amounts of DG on feeder laterals also can
cause violations, as could cumulative DG output when DG from independent feeders are
combined (i.e., via feeder tie points) during maintenance or outage events.
2.1.5
DISTRIBUTION SYSTEM CONTINUOUS FEEDER THERMAL RATING
The continuous thermal rating of feeders within the distribution system refers to the safe
operation of feeders under continuous full load conditions. Feeders operating within the
distribution system operate at one of three voltages (4.16 kV, 13.8 kV, and 27.6 kV) as described
previously. Correspondingly, within each voltage class, feeders are rated at a continuous load
level to withstand the heat produced during the distribution of a given amount of power.
Each of the 4.16 kV, 13.8 kV, and 27.6 kV networks has feeders rated to operate no higher than 4
MW, 10 MW, and 20 MW, respectively. Within the distribution system, these feeder thermal
rating levels represent a theoretical ceiling on the level of DG that can be safely interconnected.
18
EXHIBIT G1
2.1.6
HONI-OWNED TRANSFORMER STATION THERMAL LIMITS
The thermal capacity of HONI-owned transformer stations is based largely on the ability of the
station’s power transformer and ancillary equipment to withstand a pre-determined level of
reverse power flow. Reverse power limits are based on the configuration of the transformer, its
vintage, and primary winding system. Thermal capacity limits at transformer stations
connected to the THESL system are also affected by upstream issues, which are beyond
THESL’s control and responsibility. Accordingly, HONI calculates thermal capacity limits at
each transformer. Initial discussions with HONI indicated that many transformers, particularly
those located in stations described as the ‚Bermondsey‛ design, have strict reverse power limits
that prohibit the flow of reverse power. As discussed earlier, HONI presently owns all power
transformers in each of its stations serving THESL except for Cavanagh TS, and all transmission
lines, cable and ancillary equipment located upstream from the high-side of the transformer.
2.1.7
PROTECTION CONSTRAINTS
Large amounts of DG have the potential to impact protection coordination. For larger DG,
advanced and more effective protection and control systems may be needed to enable
interconnection. Further, on secondary network systems, reverse power relay settings can
significantly limit DG penetration, particularly for rotating DG installations which have higher
fault contributions than inverter based DG.
2.1.8
FEEDER LOAD DIVERSITY
THESL’s distribution system varies by geography, voltage level, and network configuration as
detailed previously. Its customers also vary by class, have unique load profiles, and are
comprised of a mix of residential, commercial/institutional, and industrial customers. THESL
distribution feeders range from serving a single commercial or industrial customer, in the case
of a spot network, to serving a diverse mix of customers via one of the other feeder
configurations. A typical daily feeder load profile is shown in Figure 4, with minimum load
occurring overnight.
Feeder load diversity lends itself well to the connection of renewable energy connection based
on solar PV. Coincidentally, the feeder load follows a similar pattern as PV sources which
increase output throughout the day time hours. Using advanced grid monitoring systems, large
aggregate power from PV sources may be controlled in a way to maintain forward power on
the station bus. While it is anticipated that there will be short periods of time when such scaling
back may be required, for the most part, solar PV will be peaking at similar periods as THESL’s
grid.
19
EXHIBIT G1
Figure 4: Typical Daily Load Profile
1.20
Actual Windsor TS Hourly Load Profile (Bus A3A4)
Normalized Load/Generation
1.00
0.80
0.60
0.40
Min load occurs at
4:30AM
0.20
0.00
1
2
3
4
5
6
7
8
9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
2.1.9
CONTINGENCY LOAD TRANSFER SCENARIOS
Similar to other LDCs, THESL occasionally will transfer load from one feeder onto an adjacent
feeder, mostly for line or station maintenance. Whenever possible, routine maintenance is
performed where loads are low. Load transfers are also made when station or feeder outages
occur, in which case unfaulted line segments are transferred to adjacent feeders to minimize the
time and duration of outages to THESL customers. As DG may be connected to both feeders, it
is highly likely that a single feeder may carry much larger amounts of DG when the lines are
reconfigured for maintenance or outage restoration. The impact of the larger amounts of DG –
even temporarily – has potential voltage or thermal loading violations. Further, if the feeder
transfer is from an adjacent station, fault current limits may be exceeded as well. For planning
purposes, THESL takes a conservative approach in assessing the ability of a given feeder to
accept additional renewable generation.
Summary of Constraints
The projected growth of DG connections is limited by the available bus short circuit capacity in
the distribution and transmission systems as well as the thermal limits. As discussed earlier,
there are three significant constraints on the THESL Distribution System, namely Transmission
Capacity, Short Circuit Capacity and Thermal Constraints.
20
EXHIBIT G1
In order to determine the system enabling options, a detailed analysis was undertaken for
THESL equipment and proposed DG installations. The THESL distribution system was broken
down into three distinct regions for analysis as follows:
Horseshoe - 230 kV Supply
Downtown Toronto - 115 kV Supply
Scarborough East - 230 kV Supply
The THESL transformer stations served by these HONI transmission regions and affected by
the HONI transmission constraints are given inTable 3. Based on the present pre-assessment
and THESL’s forecast, the anticipated impact on the system fault levels and the impact on the
thermal limits are also shown in Table 3. The forecasted DG penetration may be readily
accommodated by the distribution system due to its low short circuit contribution, however,
with the existing HONI transmission constraints on the Downtown Toronto 115kV and
Scarborough 230kV Supplies, the values of 106MVA and 194MVA are limited to 10MVA each
(i.e., HONI constrained at the transmission level). Appendix B provides information on system
capacity for feeder busses on which renewable generation connection requests have been
received to date. Appendix C shows the DG generation capacity forecast by bus after five years.
Table 3: THESL Summary of System Capacity for Fault Levels by Region
THESL
Region
Horseshoe 230
KV
Transmission
Area without
constraints Local Station
Limits Apply
Downtown
Toronto - 115
KV
Downtown
Supply
Scarborough
East- 230 KV East to
Cherrywood
21
Available
Short Circuit
Capacity
(MVA) with
No HONI
Constraints
Available Short
Circuit Capacity
(MVA) with
HONI
Constraints
Forecasted
Generation
Capacity of DG
after 5 years
(MW)
Forecasted
Fault
Contribution
Inverter Type
DG (over 5 yr
period) (MVA)
Forecasted Fault
Contribution -90%
Inverter Type DG.
10% Sync (over 5 yr
period) (MVA)
3510
3510
273
364
464
2854
10
80
106
136
1731
10
146
194
248
EXHIBIT G1
Table 4: THESL Summary of Thermal Capacities by Region as per HONI values supplied July 14, 2011.
Available Thermal
Capacity (MW) with
No DG Connections
Forecasted
Generation Capacity
of DG after 5 years
(MW)
Net Thermal Limits
After Distributed
Generation Connected
(MW)
899
273
626
Downtown Toronto 115 KV Downtown
Supply
978
80
798
Scarborough East- 230
KV -East to
Cherrywood
399
146
253
THESL Region
Horseshoe 230 KV
Transmission Area
without constraints Local Station Limits
Apply
A summary of the constraints on the THESL system which limit its ability to accommodate DG
is given in Table 5. Based on the present pre-assessment there are six (6) system busses which
do not have the available short circuit capacity for accommodating any new DG and two (2)
busses have inadequate thermal capacity. This represents a total of 7 MW of DG capacities
which is constrained at the pre-assessed level. Based on THESL’s forecast, after five years the
total number of busses which are constrained by Thermal Capacity will be six (6) and those
constrained by Short Circuit Capacity will be eight (8). The total generation capacity which will
be affected by these constraints is approximately 99 MW.
Table 5: Summary of THESL Bus Constraints
Parameter
Existing DG connected to
system & Current
Assessments
Projected DG connected
to THESL Distribution
System after 5 years
Total DG Generation (MW)
200
470
Fault Contribution (MVA)
543
1103
Busses with Thermal constraints
2
6
Busses with Short circuits Constraints
6
8
Total DG MW constrained (Thermal)
1
47
Total DG MW constrained (Short Circuit)
6
52
22
EXHIBIT G1
3
3.1
PLANNED DEVELOPMENT TO ENABLE
RENEWABLE GENERATION CONNECTIONS
OVERVIEW
THESL has focussed its budget expenditures in areas where they will provide the earliest and
greatest improvement in terms of providing access to new renewable generation connections.
As discussed above, HONI has plans in place to address the current short circuit constraints
affecting the Leaside TS. This work is expected to be completed in 2013. While waiting for that
work to be completed, THESL will undertake projects to address areas which are not
constrained by HONI limitations (i.e., concentrate on the Horseshoe 230kV area).
As work on the HONI system progresses, additional projects will be undertaken to remove
limitations in areas where connections are limited due to constraints at the Leaside TS. These
projects will be timed to coincide with system improvements completed by HONI to remove
short circuit capacity constraints. THESL will synchronize its efforts to remove limitations
within its distribution system, with HONI.
THESL’s objective is to provide uniform access across its service territory, allowing equal access
to any proposed RE generation project, wherever requests may occur in the system. THESL
notes that it is unable to project with any certainty where future requests may arise, as those
considering projects in areas known to be capacity constrained may not have approached
THESL in the past. It should be noted that the solutions proposed to address short circuit
capacity will result in a step increase in the system’s capacity to accommodate renewable
energy generation connections. For example, investments will increase the amount of
generation that can be connected to a given sub-station by a finite MW value, independent of
forecast or actual generation connection demands.
Project technologies including shared station upgrades, express feeders, upgraded feeders, inline reactors, advanced protection /monitoring/controls, energy storage and a generation
dispatch/monitoring centre are further defined in this section. A general description of the
options for enabling renewable generation connections is provided in Appendix F. The GEA
Plan includes the installation of capability for control and monitoring to effectively incorporate
the anticipated renewable generation into THESL’s system. As mentioned earlier, the GEA Plan
has been undertaken as an integrated planning process. Proposed GEA projects have been
coordinated wherever possible with projects to sustain the system. In some instances the
coordination of projects has resulted in lower overall costs compared to the cost of completing
sustaining and GEA projects separately.
23
EXHIBIT G1
THESL has identified other co-benefits associated with some of these projects:
Enhancement projects may result in completing work which would otherwise be
required to sustain the system at a later date.
Planned projects are primarily designed to address short circuit issues which are
primary constraints on connection of renewable generation, however, they will also help
to address constraints for clean sources of generation, such as CHP. Given its customer
base, THESL expects significant local interest in the OPA’s CHPSOP and pending CHP
IV RFP.
There are also co-benefits between projects for RE connections and SG. For example,
Ethernet equipped relays installed to allow generation monitoring and control permit
situational control capabilities which can also be used as part of SG.
Where costs may be recovered from provincial ratepayers, a calculation of the direct benefits
accruing to THESL’s customers, consistent with OEB guideline, has been completed and is
presented in this section and Appendix G.
A cost / benefit method is used to select options and to prioritize expenditures in accordance
with the planned development of the system.
OPA and HONI stakeholders have been consulted via 4 working sessions between February10,
2011 and May 31, 2011 to obtain their feedback regarding this GEA Plan. A summary of
stakeholder feedback is provided separately per OEB directives.
24
EXHIBIT G1
3.1.1
FORECAST FOR RENEWABLE GENERATION CONNECTIONS
Various scenarios have been reviewed of how much inverter-based versus rotating devices
(induction or synchronous machines) DG might be connected. THESL evaluated the DG
technology combinations based on existing known renewable energy applicants from the FIT
program. At this time THESL customers have enquired for connecting over 190 MW of
inverter-based PV systems through FIT and synchronous generator pre-assessments. THESL
has forecasted that over the next five years there will be 430 MW of renewable generation based
on the existing proposed connections.
The forecast for renewable generation is based on historical data as well as the existing preassessment projects submitted by THESL customers and developers. At present, THESL has
responded to over 900 enquiries for almost 130MW from customers and developers for FIT
projects alone.
A wide range of proponents have submitted project applications, including the Toronto District
School Board (TDSB), Toronto Community Housing Corporation (TCHC), Canadian Apartment
Properties Real Estate Investment Trust (CAPREIT) and OzzSolar. The projected renewable
capacity will be over 430 MW in five years. THESL’s present rate of inquiry for individual
customers is estimated at 7 MW per month for 40 inquiries. The estimated number of DG
locations will be approximately 2500 over five years resulting in total connected DG capacity on
THESL’s grid of over 500MW.
THESL recognizes that there is uncertainty in these forecasts. THESL recognizes that it may not
be aware of potential demand for connections as RE developers are aware of current limitations
within the THESL system and may therefore not focus their efforts in areas where they expect
connection capacity to be unavailable.
Figure 5 and Figure 6 show the cumulative forecast for renewable energy generation
connections and provide a breakdown of the various renewable generation types and their
contribution to the overall forecast. If only half of the pre-assessment proponents proceed with
their projects and connect to the grid, a projected renewable generation capacity of over 250
MW will be realized in the next five years, as shown in Figure 7. This clearly demonstrates the
large potential for connected renewable energy sources to THESL’s distribution system. The
key responsibility of THESL is to offer enabling options to ensure the ability of the renewable
projects to integrate with the distribution grid.
25
EXHIBIT G1
Figure 5: Renewable Energy Generation Connections Forecast
Figure 6: Projected Cumulative Renewable Energy Generations
26
EXHIBIT G1
Figure 7: Projected Cumulative Renewable Generations, and with Half of Pre-assessment Connected
3.1.2
SELECTING RENEWABLE ENERGY GENERATION ENABLING PROJECTS
Section 2 has identified the constraints in connecting DG to the THESL distribution system. The
list of transformer station busses that have constraints is attached in Appendix B. The stations
listed in the Appendix are in the areas of downtown Toronto 115 kV constraint and East
Scarborough 230 kV constraint. These stations have various limitations, generally short circuit
and thermal capacity and it is expected that connection availability will be achieved only when
HONI completes its upgrades and associated work to relieve the constraints. HONI upgrades
are expected to take a minimum of three to five years.
There may be solutions for connections in advance of this timeline; limitations do not exist on
all the busses of a station. Therefore, some station busses are still available for connection,
without requiring renewable enabling improvements. Although a bus has a constraint, a
proper detailed assessment and evaluation may provide connection. For example, carefully
reviewed equipment rating of a RE generation facility may reveal that it could withstand a
higher short circuit capacity than the designed bus short circuit capacity. Connection may be
possible in such circumstance, provided the fault level at the nearest customer location does not
27
EXHIBIT G1
exceed the design value of the customer equipment. In such circumstances, renewable enabling
improvement will not be required, but rather, a thorough, detailed CIA. Therefore, a higher fee
for CIA will be levied on the customer; in addition, a CIA by HONI, paid by the customer to
support such a connection, may also be required.
Apart from the exemptions mentioned above, the busses of each station that face constraints
require relief by HONI short term or long term plans. Some THESL constraints, particularly
thermal capacity and short circuit capacity, will be relieved when HONI plans are
implemented. THESL will evaluate whether it is reasonable and justifiable to wait for a long
period to connect a particular FIT project. Under these circumstances, THESL will plan to
implement renewable enabling improvements that may lead to other solutions. For example, a
RE generation connection to a bus constrained by short circuit can be mitigated by the
installation of fast tracking transfer trip scheme devices (shown in Appendix E), at a reasonable
cost. This can be accomplished by renewable enabling improvements (REI) under the OEB
guidelines and DSC rules. There may be other projects that could be connected only by
implementing system expansions. Advanced monitoring, protection and control of RE projects
is essential and is also allocated under REI. Moreover, in order to have the above listed
improvements and to make the overall renewable energy source connection function
satisfactorily, the existing protection and control system needs to be replaced with an advanced
system. This will also be allocated under renewable enabling improvements under DSC rules.
THESL DG Planning Strategy
The maximum capacity of DG that could be connected to 13.8 kV and 27.6 kV systems are
10MVA and 20MVA respectively. It is anticipated that HONI upgrades with respect to the
downtown Toronto 115kV transmission system will resolve Leaside TS issues by the end of
2013. It is also anticipated that THESL will be relieved of most of the issues with respect to
short circuit and thermal capacity when HONI upgrades to the downtown Toronto 115kV and
Scarborough East 230kV are also completed.
The projects and activities of renewable enabling improvements will address connection of FIT
projects as two categories. The first category is the outstanding FIT applications to OPA,
whether approved or unapproved and pre-assessed projects for which applications will be sent
to OPA for connections within the first three years of this five-year plan. The second category is
the forecasted projects over the next five years, and projects not addressed in the first category
for connections in third to fifth year of this five-year plan. Category 1 projects are distributed in
the constraint areas as listed in Table 6 and shown in the map in Figure 8 below:
28
EXHIBIT G1
Table 6: Distribution of Category 1 FIT Projects by Constraint Areas (OPA applications and pre-assessed)
Area
Number
Capacity in kW
1.
115 kV Constraint
186
29,464
2.
230 kV Constraint
245
37,488
3.
No Cap - Feeder unidentified
51
81,92
4.
4 kV System
1
200
5.
230 kV No constraint
424
69,691
Total
907
145,035
Figure 8: Geographic Distribution of FIT Applications
29
EXHIBIT G1
Category 1 projects are distributed in MS and TS as listed in Table 7 below:
Table 7: Distribution of Category 1 FIT Projects by TS and MS
(OPA applications and pre-assessed)
TS & MS
Number
Capacity in kW
Runnymede
27
3666
Fairbank
26
3838
Basin
7
10659
Bridgman
2
40
Carlaw
10
1244
Cecil
8
586
Charles
5
281
Dufferin
15
1545
Duplex
13
645
George&Duke
3
178
Gerrard
5
343
Glengrove
19
1045
Leaside 13.8
9
1492
Main
14
1156
Strachan
8
778
Wiltshire
13
1843
Windsor
2
125
186
29464
Bermondsey
57
8669
Ellesmere
37
4451
Leaside
20
2596
Scarborough
53
10956
Sheppard
41
6752
Warden
37
4065
Total
245
37488
51
8192
115 kV Constraint
Total
230 kV Constraint
No Capacity – feeders unidentified
No capacity
30
EXHIBIT G1
Of the 907 category 1 FIT projects totalling 145,035 kW, at least 50% are currently unable to get
connected due to constraints. Therefore, renewable enabling projects will be focused in these
areas and the associated stations and busses. Resolving the issues of some stations and busses
will depend on the implementation of HONI plans addressing short circuit and thermal
capacities. Projects that would not have suitable expansion or renewable enabling
improvement options will be included in category 2. Station busses that have been identified in
Table 7 are considered for renewable enabling improvements depending on priority based on
the number of eligible projects waiting and the total capacity that will be connected. Of the
options available, expansions or renewable enabling improvements for the selected stations
with the best cost/benefit ratio have been selected. Energy storage (ES) with greater than sixhour capacity and a dedicated generation dispatch/monitoring centre are technologies with
global system benefits and will be further discussed in Section 3.2. The chosen expansions and
renewable enabling improvements and cost are listed in Table 8.
Table 8: Enabling Improvements and Associated Cost Estimates
Number
Enabling Option/Method
Estimated Cost
Construction period
1
HONI Transformer
Replacement
$8,000,000/Installation
(THESL capital
contribution estimated as
40% of $8M)
4-5 years
2
New MS
$7,000,000/Installation
3-5 years
3
Express Feeder
$3,000,000/feeder
2-3 years
4
In-line reactor
$100,000/Installation
2-3 years
5
Fault current limiting
devices
$60,000/MW
2-3 years
6
Advanced protection and
control scheme
$150,000/Installation
2-3 years
7
Generator monitoring and
controls
$25,000/Installation
2-3 years
8
Feeder cut & Tie
$25,000/Installation
1-2 years
9
Energy Storage (NaS Battery
or CAES)
$15,000,000/Installation
(2MW-6 hour capacity)
1-2 years
10
Generation Dispatch /
Monitoring Centre
$2,000,000/Installation
1-2 years
31
EXHIBIT G1
Leslie TS and Richview TS are not in the transmission constrained areas, but certain busses of
these stations are constrained. Further, Woodbridge TS which is in the adjacent utility service
area requires renewable enabling connections as it shares feeders to THESL’s service area.
There will be a shared cost between the utilities and a capital contribution is estimated for
HONI work.
Renewable energy generation projects with inverter type interface have a limited fault
contribution typically in the range of 1.2 per unit of the inverter rated output. In spite of that at
some station busses as shown in Table 2, inverter type solar PV facilities cannot be connected
readily due to the existing short circuit constraints. Further, projects that are already approved,
pending approval and have undergone pre-assessment, may require some enabling
improvements.
Considering all the above, projects were selected and cost estimates were prepared primarily for
expansions and enabling improvements for the connection of FIT projects that are in category 1
and to alleviate thermal and short circuit constraints of the busses listed in Table 7. Selected
activities and options/methods of enabling renewable energy generation facilities are listed and
described in more detail below:
1. Replacement of transformers of HONI TS
2. Installation of new THESL MS
3. Installation of new express feeder on the constrained bus
4. Installation of in-line reactor on the feeder
5. Installation of fault current limiting devices
6. Advanced Protection Monitoring and Control System
7. Remote transfer tripping
8. Feeder Reconfiguration using cut & tie techniques
9. Energy Storage (long duration).
10. Generation Dispatch & Monitoring Centre
32
EXHIBIT G1
1) Replacement of transformers of HONI TS
Replacement of HONI Station transformers will be required to alleviate minimum load
constraints. When such transformers are installed, a higher impedance transformer can be
considered to limit fault current as well. This initiative will allow for accommodating more
generation. T his initiative may be of higher cost and time consuming as it involves the
transmitter, but the cost to THESL will be the allocated capital contribution. Higher costs may
be mitigated with the replacement of 40-50 year old transformers which have better efficiency
and reliability.
2) Installation of new THESL Municipal Stations (MS)
This initiative is similar to HONI transformer replacement and similar issues are resolved. The
cost will be the sole responsibility of THESL. Replacement costs are offset by increased
capacity, better efficiency and reliability.
3) Installation of new express feeder on the constrained bus
Express feeder installation is proposed to address large scale issues and to install a feeder free
from constraints. Many issues will be resolved if a proper station and bus are selected. Costs
will be mitigated by connecting DGs that have been waiting long or had been denied
interconnection previously.
4) Installation of in-line reactor on the feeder
For fault current mitigation, in-line reactors are installed at DG terminals. These devices could
also be installed at feeder terminations within substations. Where aggregate levels of DG
exceed a certain threshold, the device is installed at the TS. For installation at feeder
terminations, no momentary or sustained interruptions to customers are needed to complete the
work. In-line reactors have ongoing losses but fault current contribution is reduced by a 3:1
ratio.
5) Installation of fault current limiting devices
For fault mitigation, fault current limiting devices – regular clip fuses or S&C Fault Fiter® fuses
– are applied with small DGs. For large DG > 500 kW, although the protection threshold is 1
MW, fault current limiting devices are installed at generator terminals. These devices provide
very fast detection and interruption of DG output, once DG fault current reaches the preset
threshold. These devices may cause nuisance tripping. Fault current contribution is reduced by
a 3:1 ratio.
33
EXHIBIT G1
6) Advanced Protection, Monitoring and Control System
To mitigate the impact on existing system fault levels and enable the connection of renewable
generation a fast protection scheme has been devised that may readily be applied. This method
may be implemented on buses with short circuit constraints that at this time prevent renewable
inverter based connections. The technology leverages the fast fibre optic ethernet ring along
with the fast operating time of inverter based devices.
The advanced protection, monitoring and control system requires the establishment of a high
speed communication network with the associated protective equipment which will enable the
isolation of the generator from the distribution system before the main circuit breakers operate.
Inverters inherently have a fast isolation time for inverter gating and are integrated with the
communication grid for coordinated isolation.
7) Remote fast transfer tripping
The key in a fast tripping scheme is to cease output power of the inverter device before the
station and distribution protective devices begin to operate. For instance, tripping the inverter
well before the station breaker begins to open will not infringe on the fault interrupting
capability of breakers. This may be accomplished since new SF6 breaker parting time is 23
milliseconds (ms) whereas the fast tripping scheme will operate in fewer than 10 ms.
In summary, the microprocessor feeder relay protection at the station breakers sends a transfer
trip signal via ethernet switches. The system uses IEC 61850 Goose messaging compliant with
NIST and EPRI endorsement for smart grid network. Operating correctly, the transfer trip
signal reaches feeder customers within 3 ms. The inverter at the customer end receives the trip
signal and stops inverter gating within 2 ms. As a result, the generator ceases power output
within 10 ms.
The full duplex ethernet network with self healing provides a normal and redundant path to
feeder customers. All inverter-based generators must cease power production well before the
station breaker begins to open, thereby mitigating the short circuit impact. The distribution
system operates within station available short circuit capacity limits and the inverter-based
generator end opens/confirms station protection monitoring within 6 ms.
Further advantages of this system include monitoring and control also available through Goose
messaging. Real time monitoring ensures thermal limits are respected during minimum load
periods. Monitoring and control systems prevent reverse power at station transformers during
minimum station loading periods where generation penetration levels may be high. The
control system then scales back generator power output to ensure bus power (MW) remains
greater than the aggregate DG power supply (MW) on the bus. Where high levels of DG
penetration are anticipated, generator output power may be scaled back for short periods when
34
EXHIBIT G1
minimum bus load constraints are encountered. Appendix E provides a tripping system
overview.
8) Feeder Reconfiguration & Feeder Cut &Tie
Feeder reconfiguration using cut and tie techniques or the strategic installation of new switches
will eliminate the short circuit issue by providing connection access to an available type feeder
as compared to a constrained feeder. This outcome, however, depends largely on the
availability of feeders with capacity in close proximity to the constrained feeder. Such
configuration may cost up to $250k if major upgrades are needed and approximately $30k
where minor changes are needed. Due to contingency planning requirements and operating
constraints there may be limited situations where this option may be applied.
9) Energy Storage
Energy storage, usually as voltage regulators, has been used in electrical distribution systems
and transmission systems in some form for decades. Battery energy storage offers distribution
system benefits and has been used for some time in other jurisdictions. Energy storage will
become an essential component of the electricity infrastructure, helping to reduce voltage
fluctuations, increase reliability, provide emergency supply, moderate peak power costs and
accommodate renewable generation. Near term, the energy storage system will provide
support for local capacity constraints and service reliability issues due to load growth in the
downtown Toronto area. Energy storage with over six hours capacity has a multiplier effect,
whereby its capacity accommodates various area intermittent RE generation sources and
influences peak pricing across the entire market volume, by dampening peak prices without onpeak fuel consumption. NaS batteries are planned for typical 2MW / six-hour storage projects
with provision for other technologies such as compressed air energy storage (CAES) in the
future.
THESL recognizes that distributed energy storage is more costly than conventional solutions,
but energy storage provides rapid deployment without extensive civil work or emission
permitting. Energy storage can be redeployed subsequently to other constrained areas once
conventional solutions ‚catch-up‛. A more detailed explanation of the proposed use of energy
storage in THESL’s system in provided in Appendix F.
10) Generation Dispatch & Monitoring Centre
Real time monitoring is necessary for safety and control coordination via fibre communications
with THESL’s control centre. It includes dispatch, monitoring, communication, data analysis
and forecasting systems. It is applicable to all sizes of generation and will eventually be
required for existing and future generation sources. The system will have the ability to collect
data for planning purposes and coordination with conventional distribution outage
35
EXHIBIT G1
management, thereby enabling greater penetration of generation by best utilizing resources.
Large renewable generation connections could be constrained in future per recent IESO
planning guidelines requiring a generation control room with forecast capability.
3.2
GENERATION CONNECTION PROJECTS
Station Upgrades: Per Section 3.1 the following Station projects have been established:
Table 9: Selected Projects and Activities to increase areas with zero Capacity
Location
TS
MS Bus
Feeder
Estimated
cost ($)
Project
construction
period
#
TS Name
1.
Leslie BY Bus
6,7
1,091,341
2-3 Years
2.
Richview BY Bus
6,7
482,500
2-3 Years
3.
Wiltshire TS
10,012,894
4-5 Years
3a.
Wiltshire A1A2 Bus
3b.
Wiltshire A3A4 Bus
3c.
Wiltshire A5A6 Bus
6,7
3d.
Wiltshire B1B2 Bus
6,7
8,183,267
2-3 Years
3,313,492
2-3 Years
8,955,473
3-5 Years
12,700,000
3-5 Years
2,752,032
1-2 Years
1
6,7
3
6,7
4.
Carlaw TS
4a.
Carlaw A4A5 Bus
4b.
Carlaw A6A7 Bus
4c.
Carlaw A8A9 Bus
6,7
4d.
Carlaw B1B2 Bus
6,7
4e.
Carlaw B3B4 Bus
6,7
5.
Cecil TS
5a.
Cecil A1A2 Bus
5b
Cecil A3A4 Bus
7
5c.
Cecil A5A6 Bus
7
5d.
Cecil A7A8 Bus
7
6.
Gerrard MS
6a.
Gerrard A1A2 Bus
7.
Bridgman MS
7a.
Bridgman A5A6 Bus
8.
Leaside TS
8a.
Leaside A1A2Q1Q2A1A2Q1Q2
36
8
3
3, 4
6.7
7
2
6,7
2
3
6,7
6,7
EXHIBIT G1
Table 9: Selected Projects and Activities to increase areas with zero Capacity
Location
TS
#
TS Name
9.
Woodbridge TS
9a.
Woodbridge BY Bus
10.
Basin TS
10a.
Basin A5A6 Bus
10b.
Basin A7A8Bus
11.
Future projects
MS Bus
Feeder
1
Estimated
cost ($)
Project
construction
period
2,000,000
4-5 Years
5,718,752
2-3 Years
6,7
3
6,7
6,7
8,920,000
$64, 129,752
Total
Estimated Construction Schedule
All project activities will be scheduled within the five-year period from 2012 to 2016. Each
activity will have a different completion period. Some activities will be started and completed
within a year. But depending on the applications received for renewable connections, the
particular activity will be spanned within the five-year period for varying numbers of
connections. Some activities will take more than one year and the particular activity will be
spanned over the period of five years or less depending on when the application for connection
is received and how the project is progressed on both the customer end and by other authorities
such as OPA, HONI, IESO and THESL. Table 9 indicates the anticipated timeline of each
activity and Table 12 presents the estimated schedule for each project planned between 2012
and 2016.
Description of benefits
The major benefit of implementing these projects is that renewable energy projects will be
successfully implemented in the THESL service area, by encouraging THESL customers and
other stakeholders to install renewable energy projects, thereby achieving the spirit and intent
of the GEEA. Accordingly, THESL proposes to not delay these projects until HONI resolves the
Leaside TS short circuit constraint. The costs associated with the options and methods adopted
in the projects are reasonable and achievable within the proposed timeframes. These projects
will enable at least 320MW of generation capacity and technical benefits are listed below:
Fault current levels are reduced considerably, almost by 2:1 or 3:1 which enables greater
generator capacity. Options provide fast detection and interruption of DG output, once
DG fault current reaches the preset threshold allowing more generation connections;
37
EXHIBIT G1
The major enabling achievement is establishing bi-directional flow which enables more
generation project connections. Additional benefits are automated communication and
remote control to interrupt generators if minimum load threshold is reached;
By installing transfer trips, large generators will safely trip when the capacity threshold
is reached and isolate from the THESL distribution system, allowing additional capacity;
Collection and analysis of historical data supports grid planning; and
Advanced monitoring, protection and control of generators limits system faults and
provides fast isolation which enables greater penetration of larger generators.
There are various risks to successful completion of projects supporting this GEA Plan,
including:
Increase or decrease in volume of FIT and CHP applications;
Unequal distribution of generation projects in specific constrained areas;
Retrofit and upgrade of existing infrastructure may involve higher costs; and
Planned projects may get delayed due to unforeseen reasons.
Project costs are summarized below in Tables 10, 11, 12 and 13 below:
Table 10: 2012-2016 GEA Plan Capital Expenditures (Projects Enabling Renewables)
Capital
Expenditures
Enabling
Renewables
2012
2013
2014
2015
2016
Subtotals
$25.1M
$32.9M
$32.9M
$20.3M
$20.3M
$131.6M
Table 11: 2012-2016 GEA Plan Operating Expenses (Projects Enabling Renewables)
Operating
Expenses
Enabling
Renewables
38
2012
2013
2014
2015
2016
$0.2M
$0.2M
$0.2M
$0.2M
$0.2M
EXHIBIT G1
Subtotals
$1.0M
Table 12: Project Capital Details Enabling Renewable Energy Generation Capacity
39
EXHIBIT G1
Table 13: Project Operating Expenditure Details Enabling Renewable Energy Generation Capacity
40
EXHIBIT G1
4
SMART GRID
Through industry participation and regulatory due diligence THESL’s Smart Grid (SG)
initiatives are aligned with the objectives set under Minister’s Directive, November 23, 2010:
1. Customer Control: Enabling the smart grid will allow the utility to offer more value to
its customer base. The implementation of the Advanced Metering Infrastructure (AMI)
has been nearly completed in Ontario, it is expected that a myriad of services will be
developed to leverage the valuable information that it is now available. The aim is that
the increase in visibility of information will allow THESL to focus on customer
experience resulting in more services for the customers and better control of energy
consumption. THESL is also aware of its role in the industry in the areas of renewable
generation and energy storage. Once customer programs are developed THESL will
continue to educate consumers regarding the services that are available and the
processes to obtain those benefits.
2. Power System Flexibility: Enabling technologies for distributed renewable generation
will ensure that conditions and grid operations are stable. Distribution automation
plans are geared to increase grid control and monitoring by adding granularity and
system visibility. Ultimately, with the increase of distributed generation and the
addition of other applications THESL will ensure that the service delivery will maintain
the highest standards of quality, reliability and safety.
3. Adaptive Infrastructure: The impact of emerging technologies will require an asset
management strategy that allows flexibility and scalability. At THESL the smart grid
planning and development process has evolved new practices to enable innovation
while accommodating and designing different business models.
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EXHIBIT G1
4.1
SMART GRID – CURRENT ASSESSMENT
THESL initiated smart grid (SG) development and demonstration through the establishment of
Toronto’s Smart Community, a demonstration area where prioritized initiatives can be tested,
processes developed, customer acceptance understood and operating procedures created.
Expected benefits will be demonstrated, measured and used to support potential full-scale
deployment. Additional opportunities and potentials will also be identified for further
demonstrations. Results and lessons learned will be shared with the industry in various forms
such as white papers, presentations and online content. The selected demonstration area is
located in North York and consists of ten feeders, two substations and over 25,000 customers.
This area was selected based on reliability levels, equipment in-service, smart meters installed
and customer diversity.
THESL has implemented a number of technologies within its system that may be considered to
be part of a ‚Smart Grid‛. For purposes of the GEA Plan, THESL considers ‘emerging
technologies’ as those that are being tested or demonstrated within the THESL system. THESL
treats such technologies as emerging for a period of two to three years until standards and
procedures are developed and they are accepted by the Electrical Safety Authority (ESA). If the
emerging technologies are successfully demonstrated after two to three years they will be
incorporated as an element in the sustainment budget and allocated under the EDR filing for
infrastructure.
THESL’s approach includes strategic and prudent modernization of its distribution
infrastructure, and expands the benefits of successfully proven technologies in other parts of its
service. THESL will continue to focus on technologies and programs that will assist in
proactively addressing emerging requirements such as distributed generation and plug-in
electric vehicles. This will involve the development of ‚smart circuits‛ to improve flexibility,
visibility, control, reliability and safety of the system. The SG roadmap shown in Figure 14
illustrates the technology advancing over the next 20+ years and the associated benefits
expected.
42
EXHIBIT G1
Figure 14: Smart Grid Roadmap
2010
2013
2023
2033
Under this comprehensive and forward-looking approach, there exist unique opportunities to
apply modern technologies for the various configurations of THESL’s system, including 27.6
kV, 13.8 kV, 4 kV and secondary network systems.
The initial three-year focus of the SG roadmap relates to the establishment of Toronto’s Smart
Community. This is a demonstration area where prioritized initiatives can be tested, processes
developed, customer acceptance understood, and operating procedures created. Expected
benefits are data integration, improved monitoring and control.
The three- to ten-year focus involves the expansion of demonstrated initiatives from the Smart
Community into larger scale deployments. Simultaneously, additional initiatives will be
piloted, characterized by technological advances, new or converged standards, and building on
the foundations of the Smart Community.
The introduction of larger volumes of commercially available electric vehicles (EV) over the
next five years is expected to be concentrated in metropolitan areas. Building on the lessons
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EXHIBIT G1
from the EV pilot program in Toronto, a scalable infrastructure rollout will comprehend the
impact on distribution assets through integration into the smart grid. EV charging systems will
leverage the monitoring and control functionality of automation technology while ensuring
flexibility, visibility, control, reliability and safety. The early metering and impact analysis
applied for EV will be enhanced with the integration of analytics into communications and
distribution management systems. Field demonstrations will offer enhanced data capabilities
beyond energy metering to load monitoring and power quality. Based on technical and
business requirements EV infrastructure design, specifications, standards, communications,
privacy and security will be extended.
Finally, the ten- to 25-year focus represents the end state of the SG as defined by present drivers.
Initiatives are characterized by complete integration of technologies and services, collaboration
between the utility and customers, and energy sourced primarily from renewable and clean
generation.
Proven SG technologies will span THESL’s entire service territory. This roadmap is intended to
be living and evolving, and able to adapt to changing conditions and needs over time.
THESL’ s SG is being developed to ensure modernization of the grid. To do so, it is paramount
to continue building a foundation of components for monitoring. As of today, SG
developments have demonstrated operational value in the realization of different sensing
technologies such as transformer smart meters, power line monitors, self-healing switching and
many more. At its early stage of development, many options for integration and intelligence
are viable contributions to the overall objective. The degree of evolution in these areas may
vary over time given the lack of solutions available and changes in technology. THESL
recognizes the need to adapt to changing conditions and needs over time.
THESL’s distribution system presents specific challenges and therefore creates opportunities for
the realization of the SG. The power distribution grid currently does not have sufficient
visibility for monitoring and control operations, whereas the SG includes advanced monitoring
and automation technologies. THESL will build upon lessons learned during developmental
phases and accommodate the transition of the industry into the intelligence layer. While in
compliance with regulatory objectives, THESL’s efforts are placed on modernizing its delivery
and service networks.
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EXHIBIT G1
The characteristics and challenges for the four main configurations in THESL’s distribution
system are outlined below:
27.6 kV System: THESL’s service territory is served by the 27.6 kV primary distribution
system through 20 transformer stations (‚TS‛) serviced from Hydro One transmission
lines. A mix of overhead and underground, all 27.6 kV feeders are arranged to run
radially from the TSs and keep feeder interconnection points normally open. These
feeders serve a larger number of customers as compared to other systems, as well as 13.8
kV or 4.16 kV municipal substations (‚MS‛). The challenge of the 27.6 kV system is an
ageing infrastructure coupled with long feeders and a relatively large number of
customers.
13.8 kV System: There are fifteen 115/13.8 kV transformer stations located in the preamalgamation city of Toronto. The dual radial system serves most of the
commercial/industrial loads of the Toronto downtown core and 4 kV stations where
each customer has two feeders connected in a normal/standby configuration. Customers
with loads in excess of 10MVA are supplied with three or more dedicated feeders with
pilot-wire protection. The key challenge with the 13.8 kV system is that municipal
stations are typically older than 40 years with limited visibility and remote control
capabilities. Feeder equipment is also largely unmonitored and lacks automation
capabilities. Age, loss minimization, and equipment availability are drivers for system
conversion, as well as requirements for future load growth.
4.16 kV System: The 4.16 kV overhead system is fed by 27.6 kV feeders outside of the
pre-amalgamation city of Toronto and by 13.8 kV feeders and municipal stations within
the Toronto area. Over the years, some areas of the 4 kV overhead system have been
converted and are supplied from the 13.8 kV overhead or URD systems. The challenges
with the 4.16 kV system are legacy equipment and higher system losses due to a lower
voltage. The system is also largely unmonitored at the station and along the feeder.
Secondary Network System: The secondary network is a system of interconnected
secondary conductors, designed in grid or mesh configurations and supplied by a
number of network units located in network vaults. The key challenges with network
vaults are legacy and ageing network units, harsh vault conditions and complexity of
system design, thus leading to low probability high impact outages. Further, there are
no remote monitoring and control capabilities in network vaults.
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EXHIBIT G1
The initiatives in THESL’s 25-year roadmap were selected, prioritized, and will be evaluated on,
the following criteria:
Necessity to deliver on government policy and ability to generate short term results;
Customer needs and expectations;
Technology trends and readiness; and
Feasibility and capacity to execute, both in financial and skill sets.
In response to the provincial government’s target that one in 20 vehicles in Ontario be electric
by 2020 and the automotive industry plans to launch electric vehicles (EV) commercially in
2011, THESL has undertaken an early EV pilot program to demonstrate and assess the
requirements for EV charging infrastructure. This consists of testing the performance of EV
charging stations and metering integrated with THESL’s energy and distribution management
systems. The intent of the program is to:
understand the impact of EVs on the distribution grid, including loading and power
quality as well as long term impact on distribution assets;
develop safety, operating and control procedures and practices;
understand the design, specifications, standards, metering, billing and data
requirements surrounding vehicle charging; and
integrate the monitoring of vehicle loads with the rest of the smart grid technology to
secure the development of an integrated control scheme.
Currently a few EVs have been deployed in the city of Toronto, and it is expected that the
introduction of commercially available EVs will happen mid-2011. It is anticipated that the EV
demonstration will provide empirical information regarding real driving and charging
behaviour. This will augment the theoretical modelling and impact studies THESL has done to
date and is crucial given the potential for two-way power flow with EVs.
4.2
SMART GRID DEMONSTRATION PROJECTS
THESL addresses the SG with the intent to learn and demonstrate the development of energy
industry technology. Through the SG development process THESL has acquired knowledge of
specific monitoring functionalities. However, the deployment of different components has
proven to be complex. Demonstration projects include activities where THESL seeks to acquire
knowledge and experience while developing solutions and applications, all of which can be
integrated into its current system to demonstrate the functionalities and benefits of the smart
grid. Work in 2012 will continue to build upon previous projects with the aim to further
demonstrate an integrated SG.
46
EXHIBIT G1
Through active participation in conferences, academic communities and industry groups,
including the Ontario Smart Grid Forum, THESL has undertaken a prudent review of other
demonstration projects to ensure that its demonstrations are well coordinated with those of
other stakeholders for information sharing, and that any projects undertaken are concrete
investments that will lead to the advancement of knowledge and lessons learned in the
implementation of a smart grid. THESL has taken care to ensure that the initiatives will not
bring about unnecessary duplication of efforts, but will contribute towards generating
immediate benefits to the planning and operation of the system.
In 2012, THESL will continue with the expansion and development of the Smart Community.
The intent is to focus on technologies and programs that address system challenges such as
reliability while introducing emerging requirements for distributed generation, connection of
electric vehicles and the development of energy storage solutions. The proposed SG projects
are described below.
1) Smart Sensors Development
Under time-variable energy pricing, inclusion of intermittent renewable generation and
connection of plug-in electric vehicles, THESL’s distribution system will experience
unpredictable supply and demand that may result in system overloads, voltage variations,
phase imbalances, excessive harmonic effects and more. Thus a granular approach must be
adopted, with advanced sensing and power flow control, adaptive protection, energy storage
and power quality mitigation measures. THESL envisions the following essential components
of the SG:
Smart metering – gateway between the grid and the customer. Intelligence at each
customer, enabling time of-use rates, remote meter reading, supporting operational
needs (e.g., outage, restoration, over/under-voltage, tampering and other event
reporting), and potentially interoperating with home energy management systems and
home area networks
Transformer smart metering – monitoring of secondary systems, including transformer
load monitoring, outage notification, restoration confirmation, voltage detection and loss
detection. Transformer smart metering is also expected to improve the connectivity
model and phase balancing, as well as capture transformer temperature and vault
conditions. THESL has introduced smart metering on poletop transformers across the
Smart Community. In 2012 THESL intends to use the data from these to demonstrate
transformer load monitoring and theft detection tools. In addition, THESL will continue
to work with manufacturers to develop solutions for metering of padmounted and
submersible transformers
47
EXHIBIT G1
Primary line sensors – monitoring of primary systems, including system loading,
voltage, current, faults, power quality, conductor temperature and system losses
Self-healing switching – automatic fault detection, location, sectionalisation, isolation
and restoration, to dramatically reduce the outage duration of non-faulted segments of a
feeder. Also improve monitoring of major points in the feeder including voltage and
current
Substation intelligence – gateway between the transmission and distribution grids.
Intelligence at transformer or municipal stations such as intelligent relays, for
interoperation with the bulk power systems as well as downstream feeder intelligence.
Moving towards signature detections, power quality measurements, fault anticipation,
and more. THESL has supported two applications to the MEI Smart Grid Fund for
development of substation intelligence. If these are successful in receiving funding,
THESL intends to install prototype units in 2012 for evaluation
2) Community Energy Storage
In 2012 THESL plans to demonstrate one or more energy storage units in its Smart Community
as Community Energy Storage (CES). This is the continuation of a project that commenced in
2011 in partnership with ECamion and the University of Toronto. This project is partly funded
by Sustainable Development Technology Canada.
The CES will be operated as distribution facilities to provide grid support and integrated into
the distribution planning process. Each energy storage unit will consist of battery storage,
battery management system, power converter, power conditioning system and
communications. Expected benefits include the following:
Mitigate effects of intermittent generation and demand such as from renewable
generation sources and electric vehicle loads, effectively functioning as grid ‚shock
absorbers‛ by providing capacity relief and energy balancing;
Enhance system utilization and efficiency while preventing system overloads through
load levelling, increasing system capacity and reducing losses;
Improve reliability through operating in conjunction with self-healing switching
schemes to increase alternative supply capacities;
Provide voltage regulation, loss reduction and power factor correction capabilities
through active and reactive power injection;
Potential to provide active power filtering capabilities through transient and harmonic
power injection, hence mitigating power quality effects such as harmonic distortion,
48
EXHIBIT G1
voltage sags and swells and flicker, thus providing ‚digital grade‛ power quality to
customers; and
Potential to provide backup power and ride-through capabilities during system outages
and supporting microgrid applications.
Assuming successful demonstration of the technology, THESL anticipates that the challenges
for widespread implementation will include maturity of battery technology, siting of physical
assets, control and operating procedures and integration into the planning process. The results
of the demonstration will enrich THESL’s understanding of the challenges to be addressed in
implementing the technology.
Energy storage technologies have been used in transformer stations for DC supply and for large
scale voltage regulation. Energy storage technologies have also been utilized in the
transmission system in the form of flexible AC transmission systems for power quality
mitigation. THESL’s approach to energy storage works under the framework of system
integration where the storage unit will interoperate with other smart grid components such as
transformer smart meters, self-healing switches and the energy management system.
Community Energy storage enables localized grid support at the required areas on a feeder for
a large number of customers and is distinct from long duration energy storage. THESL’s
approach for long duration energy storage is described in Appendix F.
3) Electric Vehicle Infrastructure Integration
In response to the provincial government’s target that one in 20 vehicles in Ontario will be
electric by 2020, as well as to support emerging trends in the automotive industry, THESL plans
to demonstrate how EV charging infrastructure can be fully integrated into its smart grid. The
infrastructure may consist of a combination of EV charging stations, metering, communications
and an EV management system that is integrated with THESL’s energy and distribution
management systems. This will be demonstrated using electric vehicles and charging stations
from a diverse group of stakeholders. Expected benefits of the project include the following:
understand the real time impacts of electric vehicles on the distribution grid, including
loading and power quality, as well as long-term impacts on distribution assets;
develop safety, operating and control procedures and practices;
understand the design, specifications, standards, metering, communications, security,
privacy, billing and data requirements surrounding vehicle charging; and
integrate the monitoring and control of vehicle loads with the rest of the smart grid to
develop an integrated control scheme.
49
EXHIBIT G1
THESL has already developed an internal model that assesses the impact of vehicle charging
using ‚top‐down‛ scenario analyses, taking into account various parameters including vehicle
penetration levels, vehicle types and sizes, charging circuitry, charging strategy and base load
profile.
This project offers a unique ‚bottom up‛ approach where physical charging of vehicle loads are
coordinated with the rest of the smart grid for integrated ‚smart charging‛ or ‚grid-aware
charging‛, including transformer smart meters, power line monitors, self‐healing switches,
energy storage units and the energy management system. This will enable granular, near
real‐time monitoring and control of vehicle loads that will provide insight into its impact and
mitigation measures throughout the system.
In addition, THESL’s demonstration pilot will assess the operating models of diverse charging
station infrastructure providers as well as identify technical requirements for the operation,
management and integration of these systems. It is anticipated that this demonstration will
enrich THESL’s understanding of the challenges to be addressed with implementing the
technology.
The SG project capital costs are shown in Table 14 below:
Table 14: Capital Expenditures for Smart Grid Projects for 2012 - 2016
Project Capital
2012
2013
2014
2015
2016
Smart Sensors
Development
$0.5M
$0.5M
$0.5M
$0.75M
$0.75M
Community Energy
Storage
$1.0M
$1.5M
$1.5M
$1.75M
$1.75M
Electric Vehicle
Infrastructure Integration
$2.0M
$2.0M
$2.0M
$2.0M
$2.0M
Total Capex
$3.5M
$4.0M
$4.0M
$4.5M
$4.5M
50
EXHIBIT G1
4.3
SMART GRID STUDIES AND PLANNING EXERCISES
Studies and planning exercises have been a cornerstone of THESL’s planning and development
of the smart grid. Through the ongoing assessment of industry solutions THESL continues to
acquire detailed information regarding the application of smart grid initiatives in its service
territory and to its business processes. Moreover, it is expected that moving forward, insights
from the application of new technologies and emerging requirements for integration will need
to be defined and validated. Extensive work is required to enable an effective integration of
current and emerging technologies into the THESL planning and operating model. This
includes the development of safety, control and operating practices, as well as optimal designs,
locations, specifications, controls and integration of specific technologies.
Such studies and planning exercises will continue to support existing and future demonstration
programs. Areas of studies and planning may include energy storage, plug-in electric vehicles,
advanced automation schemes and home energy management. Academic institutions and
experienced consulting agencies are being engaged in the development of these industry
assessments. The results of these studies will continue to aid in developing and implementing a
smart grid by proper design, planning and implementation to provide benefits to the
distribution system and its customers. Results will be shared in collaborative networks that are
international in reach, such as IEEE, CEATI International, EDA and the Ontario Smart Grid
Forum, and will include participants from utilities, academia, vendors, consultants and system
integrators.
Table 15: Operating Expenditures for Smart Grid Projects for 2012 - 2016
Project Operating
Expense Estimates
2012
2013
2014
2015
2016
Studies and Planning
$0.5M
$0.7M
$0.7M
$0.7M
$0.7M
Training and Education
$0.1M
$0.15M
$0.15M
$0.15M
$0.15M
Subtotals
$0.6M
$0.85M
$0.85M
$0.85M
$0.85M
51
EXHIBIT G1
5
5.1
GEA PLAN COST AND ALLOCATION
GEA PLAN COST SUMMARY
The aggregate capital and operating expenditures for both enabling renewables and developing
the smart grid are shown in Tables 16 and 17. THESL’s GEA Plan proposes a total capital
investment of $152M over five years and a total operating expense of $5M over five years as
detailed in Sections 3 and 4.
Table 16: 2012 – 2016 GEA Plan Capital Expenditures (Totals may not match due to rounding)
Capital
Expenditures
2012
2013
2014
2015
2016
Subtotals
Enabling
Renewables
$25.1M
$32.9M
$32.9M
$20.3M
$20.3M
$131.6M
Developing
Smart Grid
$3.5M
$4.0M
$4.0M
$4.5M
$4.5M
$20.5M
Subtotals
$28.6M
$36.9M
$36.9M
$24.8M
$24.8M
$152.1M
Table 17: 2012 – 2016 GEA Plan Operating Expenditures
Operating
Expenses
2012
2013
2014
2015
2016
Subtotals
Enabling
Renewables
$0.2M
$0.2M
$0.2M
$0.2M
$0.2M
$1.0M
Developing
Smart Grid
$0.6M
$0.85M
$0.85M
$0.85M
$0.85M
$4.0M
Subtotals
$0.8M
$1.05M
$1.05M
$1.05M
$1.05M
$5.0M
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EXHIBIT G1
5.2
GEA PLAN COST ALLOCATION (DIRECT BENEFITS)
The calculation or quantification of the direct benefits accruing to the distributor’s customers,
consistent with the OEB’s guideline, has been completed for costs eligible for recovery from
provincial ratepayers. The summary of calculated Direct Benefits is shown in Table 18. The
corresponding financial values are provided in Table 19. The detailed calculation and criteria
are set out in Appendix G.
Table 18: 2012 – 2016 GEA Plan Cost Allocation (Direct Benefits Percentages)
Table 19: 2012 – 2016 GEA Plan Cost Allocation (Direct Benefits Financial Values)
Capital
Expenditures
2012
2013
2014
2015
2016
Subtotals
Gross Cost
$28.6M
$36.9M
$36.9M
$24.8M
$24.8M
$152.1M
Less Generator
Contribution
$0.0M
$0.0M
$0.0M
$0.0M
$0.0M
$0.0M
Less Provincial
Recovery
$22.0M
$28.3M
$28.3M
$17.6M
$17.6M
$113.9M
THESL Cost (Net)
$6.6M
$8.6M
$8.6M
$7.2M
$7.2M
$38.2M
THESL is seeking a funding adder and variance account per Table 19 for GEA Plan
expenditures. THESL has included a revenue requirement calculation in its 2012 Electricity
Distribution rate Application for the amounts to be recovered in rates beginning in the year
2012, identifying all assumptions used in the calculation, and the basis for those assumptions.
53
EXHIBIT G1
APPENDIX A:
DESCRIPTION OF THESL SYSTEM
Prior to its amalgamation with the neighbouring municipal utilities, much of THESL’s
distribution system operated at 4.16kV or 13.8kV, which serves downtown Toronto and other
high load density areas. Amalgamation with the neighbouring utilities (in what is commonly
referred to as the ‚Horseshoe‛) introduced a significant amount of higher rated 27.6kV
distribution facilities. Two important differences between these two systems are their load
carrying capacity and their source of supply.
All 13.8kV stations in central and downtown Toronto are served via HONI 115kV lines
emanating from Manby and Leaside stations. The 27.6kV stations are served from 230kV lines
running east-west in a corridor north of Highway 401 between Cherrywood and Richview
stations and from an eastern corridor into Leaside station.
Figure A: Toronto Area Transmission Supply
Figure A illustrates the 230kV (light blue) and 115kV (green) HONI transmission lines that serve
THESL’s 27.6kV and 13.8kV systems, respectively – THESL’s service area is shaded tan. To
limit fault current and undesired parallel flows, the 115kV systems serving downtown Toronto
from Manby and Leaside are electrically separated. Any future plans to tie the 115kV stations
would reduce available short circuit capacity, thereby further curtailing DG installations.
54
EXHIBIT G1
For this GEA Plan, the capacity of 13.8kV lines is assumed to be approximately 10 MVA, with
the 27.6kV system limited to 20 MVA. It is also worth noting that many of the 115/13.8kV
downtown stations are over 30 to 40 years old, whereas many 230/27.6kV stations are less than
30 years in age.
Distribution System Voltage Levels and Feeder Vintages
Just as each type of DG unit, whether a photovoltaic (‚PV‛) system or synchronous generator,
has certain electrical and physical characteristics that require consideration as part of a utility’s
interconnection process, distribution feeders (or circuits) have inherent characteristics that
require additional review as part of the evaluation process. These characteristics are largely
driven by the type of system that an individual feeder is embedded within and may include:
voltage level; feeder length; network type, i.e., radial, network/secondary, or spot; physical
thermal limits; and feeder length.
THESL’s distribution system is comprised of distribution feeders that operate at one of three
nominal distribution primary voltage levels – 4.16 kV, 13.8 kV, or 27.6 kV. Within the THESL
system the primary voltage level of distribution feeders is largely based on feeder vintage,
which tends to vary geographically. In total, THESL customers are served by approximately
900 feeders emanating from 13.8KV and 27.6KV Transformer Stations (‚TS‛). Overall,
including the total number of feeders from TSs and MSs, the number of feeders at each
distribution primary voltage level is:
27.6 kV – 261 Feeders (Transformer Stations)
13.8 kV – 630 Feeders (Transformer Stations and Municipal Stations)
4.16 kV – 652 Feeders (Municipal Stations)
Figure B provides a transmission overview of the various areas in the city of Toronto that are
served by transformer stations (TS) and the system voltage level. The TSs that supply THESL’s
distribution feeders with a nominal system voltage of 27.6 kV (blue) serve nearly 3000 MW of
load across much of the surrounding outer ring of the city, while TSs that operate at 13.8 kV
(red) serve almost 2000 MW of load in the central and downtown area.
55
EXHIBIT G1
Figure B: Map of THESL Supply Stations by System Voltage
Network Topologies
Feeders within the THESL system are configured according to one of four distribution system
network topologies, which are typical of systems across North America: radial, loop, secondary
network, and spot network systems.
Much of THESL’s network is organized by feeder voltage discussed above and follows the
growth of the city of Toronto over the past several decades.
the central and downtown core areas of the city are largely served by 13.8 kV dual-radial
distribution lines and cables;
Secondary network and spot network systems serve the core downtown financial
district.
The surrounding area of the city is mostly served by 27.6 kV overhead radial feeders.
Figure B also illustrates the points of interconnection between transmission and distribution
systems. Although much of the transmission system operates without constraint, increased
demand for power from consumers and interconnection for DG and FIT program generators
has placed limitations on certain areas of the system.
56
EXHIBIT G1
APPENDIX B: SYSTEM CAPACITY VS. PROPOSED GENERATION
TO-DATE (203MW)
(THESL Distribution System Thermal & Bus Fault Levels at Pre-assessed State using HONI
Data values supplied July 14, 2011)
TS Name
Agincourt B Bus
Total
Agincourt Y Bus
Total
Basin A5A6 Bus
Total
Basin A7A8 Bus
Total
Bathurst B Bus
Total
Bathurst J Bus
Total
Bathurst Q Bus
Total
Bathurst Y Bus
Total
Bermondsey B
Bus Total
Bermondsey J
Bus Total
Bermondsey Q
Bus Total
Bermondsey Y
Bus Total
Bridgman
A1A2B Bus
Total
Carlaw A4A5
Bus Total
Carlaw B1B2
Bus Total
Carlaw B3B4
Bus Total
57
Min
Load
(MW)
HONI
Thermal
Capacity
(MW)
Available
Station
Capacity
Before DG
and FIT
Projects
(MVA)
14.38
30
125.20
1.35
1.79
Satisfied
Satisfied
13.24
29
124.36
4.90
6.53
Satisfied
Satisfied
10.72
11
64.84
0.75
1.00
Satisfied
Satisfied
9.46
9
64.84
0.00
0.00
Satisfied
Satisfied
14.89
40
94.09
6.46
22.37
Satisfied
Satisfied
11.75
12
63.59
7.92
32.33
Satisfied
Satisfied
12.26
12
97.45
0.53
0.70
Satisfied
Satisfied
11.75
37
107.85
8.80
33.73
Satisfied
Satisfied
11.06
11
119.42
4.02
5.36
Satisfied
Satisfied
0.57
1
112.79
0.84
1.12
Failed
Satisfied
5.11
5
112.48
1.69
2.25
Satisfied
Satisfied
20.60
21
94.19
1.98
2.64
Satisfied
Satisfied
12.43
12
48.48
0.04
0.05
Satisfied
Satisfied
3.33
19
N/A
0.09
0.12
Satisfied
N/A
N/A
N/A
0.00
0.00
N/A
N/A
N/A
0.00
0.00
Sum of
DG & FIT
Generation
Capacity
MW
Total DG &
FIT Fault
Contributions
(MVA)
Thermal
Load
Check
Bus Fault
Level Check
EXHIBIT G1
TS Name
Carlaw A6A7
Bus Total
Carlaw A8A9
Bus Total
Cavanagh J Bus
Total
Cavanagh Q Bus
Total
Cecil A1A2 Bus
Total
Cecil A3A4 Bus
Total
Cecil A5A6 Bus
Total
Cecil A7A8 Bus
Total
Charles A1A2
Bus Total
Charles A3A4
Bus Total
Charles A5A6
Bus Total
Charles A7A8
Bus Total
Dufferin A5A6
Bus Total
Dufferin A7A8
Bus Total
Dufferin B1B2
BusTotal
Dufferin A1A2
Bus Total
Dufferin A3A4
Bus Total
Duplex A1A2
Bus Total
Duplex A3A4
Bus Total
Duplex A5A6
58
Min
Load
(MW)
HONI
Thermal
Capacity
(MW)
Available
Station
Capacity
Before DG
and FIT
Projects
(MVA)
6.14
6
101.47
0.71
0.94
Satisfied
Satisfied
13.04
13
101.58
0.53
0.70
Satisfied
Satisfied
N/A
N/A
N/A
2.38
3.17
N/A
N/A
N/A
2.90
3.87
10.82
11
61.55
6.67
33.35
Satisfied
Satisfied
12.91
13
61.24
0.14
0.19
Satisfied
Satisfied
15.76
16
41.28
0.29
0.39
Satisfied
Satisfied
22.57
23
42.20
1.44
6.59
Satisfied
Satisfied
11.81
12
96.12
0.20
0.26
Satisfied
Satisfied
12.93
13
96.74
0.00
0.00
Satisfied
Satisfied
15.58
16
51.15
0.00
0.00
Satisfied
Satisfied
11.34
11
58.56
0.09
0.12
Satisfied
Satisfied
13.90
14
61.14
0.24
0.32
Satisfied
Satisfied
8.10
8
61.44
0.29
0.39
Satisfied
Satisfied
N/A
N/A
N/A
0.00
0.00
9.45
9
23.58
0.05
0.07
Satisfied
Satisfied
4.70
5
27.18
0.97
1.29
Satisfied
Satisfied
10.16
10
58.36
0.24
0.32
Satisfied
Satisfied
8.62
13.33
9
13
58.36
56.46
0.05
0.36
0.06
0.48
Satisfied
Satisfied
Satisfied
Satisfied
Sum of
DG & FIT
Generation
Capacity
MW
Total DG &
FIT Fault
Contributions
(MVA)
Thermal
Load
Check
Bus Fault
Level Check
EXHIBIT G1
TS Name
Bus Total
Ellesmere J Bus
Total
Ellesmere Q Bus
Total
Esplanade A1A2
Bus Total
Fairbank B Bus
Total
Fairbank BQ Bus
Total
Fairbank Y Bus
Total
Fairbank YZ Bus
Total
Fairchild B Bus
Total
Fairchild J Bus
Total
Fairchild Q Bus
Total
Fairchild Y Bus
Total
Finch B Bus
Total
Finch J Bus Total
Finch Q Bus
Total
Finch Y Bus
Total
G & D A1A2
Bus Total
G & D A5A6
Bus Total
Gerrard A1A2
Bus Total
Glengrove A3A4
Bus Total
Glengrove A5A6
59
Min
Load
(MW)
HONI
Thermal
Capacity
(MW)
Available
Station
Capacity
Before DG
and FIT
Projects
(MVA)
19.54
36
82.21
2.07
2.76
Satisfied
Satisfied
16.38
32
80.53
2.38
3.18
Satisfied
Satisfied
18.12
18
70.39
8.40
42.00
Satisfied
Satisfied
N/A
N/A
N/A
1.90
2.53
21.49
61
59.24
0.50
0.67
Satisfied
Satisfied
N/A
N/A
N/A
0.13
0.17
22.95
63
0.00
1.57
2.97
Satisfied
Failed
18.01
18
96.61
0.40
0.54
Satisfied
Satisfied
10.31
26
114.16
1.38
5.14
Satisfied
Satisfied
20.47
36
115.63
0.41
0.54
Satisfied
Satisfied
18.54
19
89.23
2.85
8.38
Satisfied
Satisfied
15.09
20.30
15
36
99.97
80.84
3.51
2.64
4.67
3.51
Satisfied
Satisfied
Satisfied
Satisfied
19.00
35
80.84
3.15
4.19
Satisfied
Satisfied
20.26
20
71.68
7.76
29.79
Satisfied
Satisfied
N/A
N/A
N/A
0.00
0.00
N/A
N/A
N/A
0.00
0.00
3.33
19
0.00
0.22
0.29
Satisfied
Failed
8.19
7.70
24
24
N/A
39.08
0.29
0.76
0.38
1.01
Satisfied
Satisfied
Satisfied
Sum of
DG & FIT
Generation
Capacity
MW
Total DG &
FIT Fault
Contributions
(MVA)
Thermal
Load
Check
Bus Fault
Level Check
EXHIBIT G1
TS Name
Bus Total
Horner B Bus
Total
Horner Y Bus
Total
John A3A4 Bus
Total
John A5A6 Bus
Total
John A11A12
Bus Total
John A13A14
Bus Total
John A15A16
Bus Total
John A17A18
Bus Total
Leaside BY Bus
Total
Leaside Y Bus
Total
Leaside A1A2
Bus Total
Leaside Q1&Q2
Bus Total
Leslie BY Bus
Total
Leslie J Bus
Total
Leslie Q Bus
Total
Leslie Y Bus
Total
Main A1A2 Bus
Total
Main A3A4 Bus
Total
Malvern J Bus
Total
60
Min
Load
(MW)
HONI
Thermal
Capacity
(MW)
Available
Station
Capacity
Before DG
and FIT
Projects
(MVA)
17.56
18
83.55
4.39
13.92
Satisfied
Satisfied
21.24
21
67.31
11.19
46.82
Satisfied
Satisfied
32.54
33
N/A
3.34
16.55
Satisfied
34.96
35
N/A
0.00
0.00
Satisfied
45.30
45
94.06
0.00
0.00
Satisfied
Satisfied
24.63
25
98.08
0.00
0.00
Satisfied
Satisfied
36.93
37
94.06
0.00
0.00
Satisfied
Satisfied
29.23
29
74.51
0.09
0.11
Satisfied
Satisfied
18.00
18
61.72
1.15
1.53
Satisfied
Satisfied
N/A
N/A
N/A
0.54
0.70
13.00
16
#N/A
1.56
2.08
N/A
N/A
N/A
0.52
0.70
#N/A
13
0.00
0.98
1.31
Satisfied
Failed
17.00
33
95.03
4.91
17.72
Satisfied
Satisfied
20.80
37
99.55
2.06
2.75
Satisfied
Satisfied
N/A
N/A
N/A
6.67
26.95
9.70
10
26.35
0.55
0.73
Satisfied
Satisfied
13.42
13
22.95
0.66
0.89
Satisfied
Satisfied
18.24
18
109.33
1.71
2.27
Satisfied
Satisfied
Sum of
DG & FIT
Generation
Capacity
MW
Total DG &
FIT Fault
Contributions
(MVA)
Thermal
Load
Check
Bus Fault
Level Check
EXHIBIT G1
Satisfied
TS Name
Malvern Q Bus
Total
Manby BY Bus
Total
Manby QZ Bus
Total
Manby Y Bus
Total
Manby Z Bus
Total
Manby VF Bus
Total
Manby V Bus
Total
Rexdale BY Bus
Total
Rexdale QJ Bus
Total
Rexdale Q Bus
Total
Rexdale Y Bus
Total
Richview BY
Bus Total
Richview E Bus
Total
Richview J Bus
Total
Richview Q Bus
Total
Richview Y Bus
Total
Runnymede BY
Bus Total
Runnymede Y
Bus Total
Scarborough B
Bus Total
Scarborough J
61
Min
Load
(MW)
HONI
Thermal
Capacity
(MW)
Available
Station
Capacity
Before DG
and FIT
Projects
(MVA)
13.84
14
108.27
1.18
1.57
Satisfied
Satisfied
14.00
34
146.50
0.78
1.04
Satisfied
Satisfied
20.00
41
142.46
0.72
0.96
Satisfied
Satisfied
N/A
N/A
N/A
0.75
0.99
N/A
N/A
N/A
0.80
1.07
30.00
75
41.75
1.89
2.52
Satisfied
Satisfied
N/A
N/A
N/A
1.24
1.65
24.00
49
78.22
3.46
10.48
Satisfied
Satisfied
18.00
43
73.07
2.08
2.77
Satisfied
Satisfied
N/A
N/A
N/A
0.78
1.04
N/A
N/A
N/A
1.10
1.47
24.00
64
0.00
1.30
1.73
Satisfied
Failed
11.10
11
123.20
2.64
3.52
Satisfied
Satisfied
18.83
19
123.20
1.40
1.87
Satisfied
Satisfied
18.83
44
78.61
3.36
5.40
Satisfied
Satisfied
N/A
N/A
N/A
0.00
0.00
24.00
80
76.96
1.11
1.48
Satisfied
Satisfied
N/A
N/A
N/A
2.55
3.40
6.92
20.81
7
21
N/A
N/A
3.23
3.03
4.31
4.05
Sum of
DG & FIT
Generation
Capacity
MW
Total DG &
FIT Fault
Contributions
(MVA)
Thermal
Load
Check
Bus Fault
Level Check
EXHIBIT G1
Satisfied
Satisfied
TS Name
Bus Total
Scarborough Q
Bus Total
Scarborough Y
Bus Total
Sheppard BY
Bus Total
Sheppard JQ
Bus Total
Sheppard JQ
Bus Total
Sheppard BY
Bus Total
Strachan A3A4
Bus Total
Strachan B1B2
Bus Total
Strachan A1A2
Bus Total
Strachan A5A6
Bus Total
Strachan A7A8
Bus Total
Terauley A9A10
Bus Total
Terauley A1A2
Bus Total
Terauley A3A4
Bus Total
Terauley A5A6
Bus Total
Warden J Bus
Total
Warden Q Bus
Total
Wiltshire B1B2
Bus Total
Wiltshire A1A2
Bus Total
62
Min
Load
(MW)
HONI
Thermal
Capacity
(MW)
Available
Station
Capacity
Before DG
and FIT
Projects
(MVA)
15.27
15
N/A
2.06
2.75
Satisfied
16.71
17
N/A
2.64
3.52
Satisfied
33.00
73
24.19
2.88
3.84
Satisfied
Satisfied
19.00
44
92.62
2.01
2.68
Satisfied
Satisfied
19.00
N/A
92.62
8.44
36.92
Satisfied
33.00
N/A
24.19
0.43
0.57
Satisfied
11.06
11
86.14
1.83
8.30
N/A
N/A
N/A
0.10
0.11
11.27
11
86.14
0.07
10.72
11
57.43
9.72
10
14.25
Sum of
DG & FIT
Generation
Capacity
MW
Total DG &
FIT Fault
Contributions
(MVA)
Thermal
Load
Check
Bus Fault
Level Check
Satisfied
Satisfied
0.09
Satisfied
Satisfied
0.15
0.20
Satisfied
Satisfied
57.43
1.09
1.28
Satisfied
Satisfied
14
N/A
2.30
11.50
Satisfied
18.37
18
93.04
0.00
0.00
Satisfied
Satisfied
13.70
14
99.72
0.00
0.00
Satisfied
Satisfied
19.09
19
99.72
0.00
0.00
Satisfied
Satisfied
16.18
41
106.28
2.41
3.21
Satisfied
Satisfied
16.96
42
104.39
1.62
2.16
Satisfied
Satisfied
N/A
N/A
N/A
0.00
0.00
13.84
29
0.00
0.06
0.08
Satisfied
Failed
EXHIBIT G1
TS Name
Wiltshire A3A4
Bus Total
Wiltshire A5A6
Bus Total
Woodbridge Bus
Total
Min
Load
(MW)
HONI
Thermal
Capacity
(MW)
Available
Station
Capacity
Before DG
and FIT
Projects
(MVA)
13.84
30
0.00
1.60
3.97
Satisfied
Failed
21.51
42
97.13
0.86
1.14
Satisfied
Satisfied
N/A
0.00
0.00
Failed
N/A
Sum of
DG & FIT
Generation
Capacity
MW
Total DG &
FIT Fault
Contributions
(MVA)
Thermal
Load
Check
Bus Fault
Level Check
Note: Table is based on the following:
Presently Connected DG capacity of 78 WW
Proposed Connection FIT Capacity of 125 MW
HONI values as per June 30, 2011 update
PV contributes 1.2 p.u. Operates at 0.9 pf
63
EXHIBIT G1
APPENDIX C: SYSTEM CAPACITY VS. FORECAST GENERATION
AFTER 5 YEARS (450MW)
(THESL Distribution System Thermal & Bus Fault Levels at Forecasted State using HONI values
provided July 14, 2011)
TS Name
Agincourt B Bus
Total
Agincourt Y Bus
Total
Basin A5A6 Bus
Total
Basin A7A8 Bus
Total
Bathurst B Bus Total
Bathurst J Bus Total
Bathurst Q Bus Total
Bathurst Y Bus Total
Bermondsey B Bus
Total
Bermondsey J Bus
Total
Bermondsey Q Bus
Total
Bermondsey Y Bus
Total
Bridgman A5A6H
Bus Total
Bridgman A1A2B
Bus Total
Carlaw A4A5 Bus
Total
Carlaw B1B2 Bus
Total
64
Min
Load
(MVA)
HONI
Thermal
Capacity
(MW)
Available
Station
Capacity
Before
DG and
FIT
Projects
(MVA)
14.38
30
125.20
4.50
7.62
Satisfied
Satisfied
13.24
29
124.36
16.82
28.59
Satisfied
Satisfied
10.72
11
64.84
2.57
4.37
Satisfied
Satisfied
9.46
14.89
11.75
12.26
11.75
9
40
12
12
37
64.84
94.09
63.59
97.45
107.85
0.00
13.09
12.77
1.81
15.60
0.00
34.62
41.30
3.08
46.32
Satisfied
Satisfied
Failed
Satisfied
Satisfied
Satisfied
Satisfied
Satisfied
Satisfied
Satisfied
11.06
11
119.42
13.82
23.49
Failed
Satisfied
0.57
1
112.79
2.88
4.89
Failed
Satisfied
5.11
5
112.48
5.78
9.82
Failed
Satisfied
20.60
21
94.19
6.82
11.59
Satisfied
Satisfied
12.43
12
48.48
0.00
0.00
Satisfied
Satisfied
3.33
19
N/A
0.14
0.23
Satisfied
N/A
N/A
N/A
0.30
0.51
N/A
N/A
N/A
0.00
0.00
Total DG
& FIT
After 5 Yrs
incl.
Connected
(MW)
Total DG &
FIT Fault
Contributions
(MVA)
Thermal
Load
Check
Bus Fault
Level
Check
EXHIBIT G1
TS Name
Carlaw B3B4 Bus
Total
Carlaw A6A7 Bus
Total
Carlaw A8A9 Bus
Total
Cavanagh J Bus
Total
Cavanagh Q Bus
Total
Cecil A1A2 Bus
Total
Cecil A3A4 Bus
Total
Cecil A5A6 Bus
Total
Cecil A7A8 Bus
Total
Charles A1A2 Bus
Total
Charles A3A4 Bus
Total
Charles A5A6 Bus
Total
Charles A7A8 Bus
Total
Dufferin A5A6 Bus
Total
Dufferin A7A8 Bus
Total
Dufferin B1B2
BusTotal
Dufferin A1A2 Bus
Total
Dufferin A3A4 Bus
Total
Duplex A1A2 Bus
Total
65
Min
Load
(MVA)
HONI
Thermal
Capacity
(MW)
Available
Station
Capacity
Before
DG and
FIT
Projects
(MVA)
Total DG
& FIT
After 5 Yrs
incl.
Connected
(MW)
Total DG &
FIT Fault
Contributions
(MVA)
Thermal
Load
Check
Bus Fault
Level
Check
6.14
6
101.47
0.00
0.00
Satisfied
Satisfied
13.04
13
101.58
2.38
4.04
Satisfied
Satisfied
N/A
N/A
N/A
1.80
3.06
N/A
N/A
N/A
8.19
13.92
10.82
11
61.55
9.98
16.96
Satisfied
Satisfied
12.91
13
61.24
6.67
33.35
Satisfied
Satisfied
15.76
16
41.28
0.48
0.82
Satisfied
Satisfied
22.57
23
42.20
0.99
1.69
Satisfied
Satisfied
11.81
12
96.12
1.82
7.30
Satisfied
Satisfied
12.93
13
96.74
0.67
1.13
Satisfied
Satisfied
15.58
16
51.15
0.00
0.00
Satisfied
Satisfied
11.34
11
58.56
0.00
0.00
Satisfied
Satisfied
13.90
14
61.14
0.30
0.51
Satisfied
Satisfied
8.10
8
61.44
0.81
1.38
Satisfied
Satisfied
N/A
N/A
N/A
0.99
1.68
9.45
9
23.58
0.00
0.00
Satisfied
Satisfied
4.70
5
27.18
0.18
0.31
Satisfied
Satisfied
10.16
10
58.36
3.34
5.68
Satisfied
Satisfied
8.62
9
58.36
0.83
1.41
Satisfied
Satisfied
EXHIBIT G1
TS Name
Duplex A3A4 Bus
Total
Duplex A5A6 Bus
Total
Ellesmere J Bus Total
Ellesmere Q Bus
Total
Esplanade A1A2 Bus
Total
Fairbank B Bus Total
Fairbank BQ Bus
Total
Fairbank Y Bus Total
Fairbank YZ Bus
Total
Fairchild B Bus Total
Fairchild J Bus Total
Fairchild Q Bus
Total
Fairchild Y Bus Total
Finch B Bus Total
Finch J Bus Total
FinchQ Bus Total
Finch Y Bus Total
G & D A1A2 Bus
Total
G & D A5A6 Bus
Total
Gerrard A1A2 Bus
Total
Glengrove A3A4 Bus
Total
Glengrove A5A6 Bus
Total
Horner B Bus Total
Horner Y Bus Total
66
Min
Load
(MVA)
HONI
Thermal
Capacity
(MW)
Available
Station
Capacity
Before
DG and
FIT
Projects
(MVA)
Total DG
& FIT
After 5 Yrs
incl.
Connected
(MW)
Total DG &
FIT Fault
Contributions
(MVA)
Thermal
Load
Check
Bus Fault
Level
Check
13.33
13
56.46
0.16
0.27
Satisfied
Satisfied
19.54
16.38
36
32
82.21
80.53
1.24
7.12
2.10
12.10
Satisfied
Satisfied
Satisfied
Satisfied
18.12
18
70.39
8.19
13.93
Satisfied
Satisfied
N/A
21.49
N/A
61
N/A
59.24
8.40
6.52
42.00
11.07
Satisfied
Satisfied
N/A
22.95
N/A
63
N/A
0.00
1.70
0.44
2.88
0.75
Satisfied
Failed
18.01
10.31
20.47
18
26
36
96.61
114.16
115.63
4.81
1.39
2.56
8.97
2.36
7.32
Satisfied
Satisfied
Satisfied
Satisfied
Satisfied
Satisfied
18.54
15.09
20.30
19.00
20.26
N/A
19
15
36
35
20
N/A
89.23
99.97
80.84
80.84
71.68
N/A
1.40
6.72
12.06
9.06
10.82
13.78
2.39
15.55
20.50
15.41
18.39
40.91
Satisfied
Satisfied
Satisfied
Satisfied
Satisfied
Satisfied
Satisfied
Satisfied
Satisfied
Satisfied
N/A
N/A
N/A
0.00
0.00
3.33
19
0.00
0.00
0.00
Satisfied
Failed
8.19
24
N/A
0.75
1.28
Satisfied
7.70
24
39.08
0.99
1.68
Satisfied
Satisfied
17.56
21.24
32.54
18
21
33
83.55
67.31
N/A
2.61
9.72
17.25
4.44
23.78
58.04
Satisfied
Satisfied
Satisfied
Satisfied
Satisfied
EXHIBIT G1
TS Name
John A3A4 Bus Total
John A5A6 Bus Total
John A11A12 Bus
Total
John A13A14 Bus
Total
John A15A16 Bus
Total
John A17A18 Bus
Total
Leaside B Bus Total
Leaside Y Bus Total
Leaside A1A2 Bus
Total
Leaside Q1&Q2 Bus
Total
Leslie B Bus Total
Leslie J Bus Total
Leslie Q Bus Total
Leslie Y Bus Total
Main A1A2 Bus
Total
Main A3A4 Bus
Total
Malvern J Bus Total
Malvern Q Bus Total
Manby B Bus Total
Manby Q Bus Total
Manby Y Bus Total
Manby Z Bus Total
Manby F Bus Total
Manby V Bus Total
Rexdale B Bus Total
Rexdale J Bus Total
Rexdale Q Bus Total
Rexdale Y Bus Total
67
Min
Load
(MVA)
HONI
Thermal
Capacity
(MW)
Available
Station
Capacity
Before
DG and
FIT
Projects
(MVA)
Total DG
& FIT
After 5 Yrs
incl.
Connected
(MW)
Total DG &
FIT Fault
Contributions
(MVA)
Thermal
Load
Check
Bus Fault
Level
Check
34.96
45.30
35
45
N/A
94.06
3.44
0.00
16.73
0.00
Satisfied
Satisfied
Satisfied
24.63
25
98.08
0.00
0.00
Satisfied
Satisfied
36.93
37
94.06
0.00
0.00
Satisfied
Satisfied
29.23
29
74.51
0.00
0.00
Satisfied
Satisfied
18.00
N/A
13.00
18
N/A
16
61.72
N/A
#N/A
0.29
3.93
1.70
0.50
6.69
2.85
Satisfied
Satisfied
N/A
N/A
N/A
5.36
9.10
#N/A
17.00
20.80
N/A
9.70
13
33
37
N/A
10
0.00
95.03
99.55
N/A
26.35
1.80
3.37
9.43
7.09
7.82
3.06
5.72
26.09
12.05
29.07
Satisfied
Satisfied
Satisfied
Failed
Satisfied
Satisfied
Satisfied
Failed
13.42
13
22.95
1.87
3.17
Satisfied
Satisfied
18.24
13.84
14.00
20.00
N/A
N/A
30.00
N/A
24.00
18.00
N/A
N/A
24.00
18
14
34
41
N/A
N/A
75
N/A
49
43
N/A
N/A
64
109.33
108.27
146.50
142.46
N/A
N/A
41.75
N/A
78.22
73.07
N/A
N/A
0.00
2.28
5.87
4.06
2.67
2.48
2.50
2.75
6.51
4.25
8.00
7.16
2.68
3.80
3.88
9.98
6.91
4.54
4.22
4.23
4.68
11.07
7.22
18.88
12.17
4.55
6.46
Satisfied
Satisfied
Satisfied
Satisfied
Satisfied
Satisfied
Satisfied
Satisfied
Satisfied
Satisfied
Satisfied
Satisfied
Satisfied
Satisfied
Satisfied
Failed
EXHIBIT G1
Satisfied
TS Name
Richview B Bus
Total
Richview E Bus
Total
Richview J Bus Total
Richview Q Bus
Total
Richview Y Bus
Total
Runnymede B Bus
Total
Runnymede Y Bus
Total
Scarborough B Bus
Total
Scarborough J Bus
Total
Scarborough Q Bus
Total
Scarborough Y Bus
Total
Sheppard B Bus
Total
Sheppard J Bus Total
Sheppard Q Bus
Total
Sheppard Y Bus
Total
Strachan A3A4 Bus
Total
Strachan B1B2 Bus
Total
Strachan A1A2 Bus
Total
Strachan A5A6 Bus
Total
Strachan A7A8 Bus
Total
68
Min
Load
(MVA)
HONI
Thermal
Capacity
(MW)
Available
Station
Capacity
Before
DG and
FIT
Projects
(MVA)
Total DG
& FIT
After 5 Yrs
incl.
Connected
(MW)
Total DG &
FIT Fault
Contributions
(MVA)
Thermal
Load
Check
Bus Fault
Level
Check
11.10
11
123.20
4.47
7.60
Satisfied
Satisfied
18.83
18.83
19
44
123.20
78.61
9.07
4.82
15.42
8.19
Satisfied
Satisfied
Satisfied
Satisfied
N/A
N/A
N/A
10.94
19.43
24.00
80
76.96
0.00
0.00
Satisfied
Satisfied
N/A
N/A
N/A
3.83
6.51
6.92
7
N/A
8.78
14.93
Failed
20.81
21
N/A
11.11
18.89
Satisfied
15.27
15
N/A
10.44
17.74
Satisfied
16.71
17
N/A
7.10
12.06
Satisfied
33.00
73
24.19
9.05
15.38
Satisfied
Satisfied
19.00
19.00
44
N/A
92.62
92.62
9.90
6.90
16.83
11.74
Satisfied
Satisfied
Satisfied
33.00
N/A
24.19
11.95
43.42
11.06
11
86.14
1.48
2.51
N/A
N/A
N/A
2.37
9.32
11.27
11
86.14
0.10
10.72
11
57.43
9.72
10
14.25
14
Failed
Satisfied
Satisfied
0.11
Satisfied
Satisfied
0.23
0.38
Satisfied
Satisfied
57.43
0.52
0.88
Satisfied
Satisfied
N/A
1.92
2.81
Satisfied
EXHIBIT G1
TS Name
Terauley A9A10 Bus
Total
Terauley A1A2 Bus
Total
Terauley A3A4 Bus
Total
Terauley A5A6 Bus
Total
Warden J Bus Total
Warden Q Bus Total
Wiltshire B1B2 Bus
Total
Wiltshire A1A2 Bus
Total
Wiltshire A3A4 Bus
Total
Wiltshire A5A6 Bus
Total
Woodbridge BY
69
Min
Load
(MVA)
HONI
Thermal
Capacity
(MW)
Available
Station
Capacity
Before
DG and
FIT
Projects
(MVA)
Total DG
& FIT
After 5 Yrs
incl.
Connected
(MW)
Total DG &
FIT Fault
Contributions
(MVA)
Thermal
Load
Check
Bus Fault
Level
Check
18.37
18
93.04
2.30
11.50
Satisfied
Satisfied
13.70
14
99.72
0.00
0.00
Satisfied
Satisfied
19.09
19
99.72
0.00
0.00
Satisfied
Satisfied
16.18
16.96
N/A
41
42
N/A
106.28
104.39
N/A
0.00
8.27
5.58
0.00
14.06
9.48
Satisfied
Satisfied
Satisfied
Satisfied
13.84
29
0.00
0.00
0.00
Satisfied
Failed
13.84
30
0.00
0.20
0.33
Satisfied
Failed
21.51
42
97.13
4.30
8.96
Satisfied
Satisfied
N/A
2.90
4.92
Failed
N/A
EXHIBIT G1
Note: Table is based on the following:
New Total Connected DG capacity of 450 MW
Inverter contributes 90% of new fault level and rotating machines contributes 10%
TCHC (Toronto Community Housing Corporation) CHP 5MW at Gerrard A6
York University 6MW machine on Finch M2
University of Toronto 2MW on Cecil A21
RBC 10MW on Windsor A29
Asbridges Bay 10 MW at Basin TS
Enwave 11 MW at Cecil TS
HONI values as per June 30, 2011 update
PV contributes 1.2 p.u. Operates at 0.9 pf
70
EXHIBIT G1
APPENDIX D: DG INTERCONNECTION CAPACITY STUDY
(MAY, 2011 NAVIGANT)
71
EXHIBIT G1
THESL 2012 GEA Plan - Appendix D: DG Interconnection Capacity Study
(60 Pages)
TORONTO HYDRO SYSTEM CONNECTION
CAPACITY AND ENABLING OPTIONS FOR
DISTRIBUTED GENERATION
Presented to
Toronto Hydro-Electric System Limited
500 Commissioners Rd.
Toronto, ON M4M 3N7
MAY 2011
Navigant Consulting Ltd.
1 Adelaide Street East, Suite 3000
Toronto, ON M5C 2V9
416.927.1641
www.navigant.com
TABLE OF CONTENTS
1
EXECUTIVE S UMMARY ........................................................................................................................ 1
2
IN TROD UCTION ................................................................................................................................... 4
2.1
3
4
5
BACKGROUN D AN D POWER S YSTEM O VERVIEW ............................................................................ 7
3.1
Bu lk Pow er System H ierarchy and Ow nership .......................................................................... 7
3.2
Distribu tion System Top ology ...................................................................................................... 9
3.3
Short Circu it Capacity .................................................................................................................. 15
3.4
Feed er Thermal Rating and Transform er Therm al Cap acity .................................................. 16
3.5
Feed er Load Diversity .................................................................................................................. 18
3.6
Generation Cap acity and DG Scenarios ..................................................................................... 19
3.7
Conservation and Dem and Managem ent .................................................................................. 20
3.8
Load Transfer Scenarios ............................................................................................................... 20
3.9
Evolution of the Toronto-Area Distribu tion System ................................................................ 21
3.10
Lim iting Factors to Increased DG Penetration ........................................................................ 22
3.11
Ad d itional Details ....................................................................................................................... 27
D G CON N ECTION CAPACITY LIMITS ............................................................................................. 30
4.1
Derivation of DG Connection Cap acity Limits ......................................................................... 30
4.2
DG Connection Cap acity Lim its: Existing Cond itions ............................................................ 32
4.3
DG Connection Cap acity Lim its: After Leasid e and Manby Up grad es ................................ 35
EN ABLIN G O PTION S TO IN CREASE D G CON N ECTION CAPACITY .............................................. 38
5.1
6
7
Rep ort Contents ............................................................................................................................... 6
Imp act of Other Up grad es to the Area Transmission System ................................................ 42
COSTIN G AN D A PPLICATION OF EN ABLIN G O PTION S ................................................................. 43
6.1
Enabling Op tions for DG Cap acity ............................................................................................. 43
6.2
Pru d ent App roach to Enabling N ew DG Cap acity .................................................................. 46
6.3
Cost Im pact and Cost Recovery of Enabling Op tions .............................................................. 48
CON CLUSION S ................................................................................................................................... 50
A PPEN D IX A: CASE S TUD Y D ESCRIPTION S ............................................................................................ 52
A PPEN D IX B: POWER FLOW S IMULATION A N ALYSIS ............................................................................ 54
B.1 Backgrou nd and Method ology ........................................................................................................ 55
B.2 Short Circu it Analysis ....................................................................................................................... 57
B.3 Voltage Perform ance ......................................................................................................................... 58
A PPEN D IX C: EN ABLIN G O PTION D ETAILS ............................................................................................ 60
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page ii
1
E XECUTIVE S UMMARY
This Navigant study was commissioned by Toronto Hydro-Electric System Limited (THESL) in
response to the Ontario Energy Board’s (“OEB” or the “Board”) request to THESL in its EB2009-0139 decision. Specifically, the Board stated in its decision:
“THESL shall continue its analysis of the incorporation of [Distributed Generation] DG into its
Central and Downtown areas. In that regard it shall file a plan concurrent with its filing
according to its distribution system planning requirements.
The plan will contain an adoption of and justification for the “next steps” listed in the Navigant
study and referenced above, or in the alternative, rationale for an “alternative approach” to
determining the optimal power system configuration for Central and Downtown Toronto.”
The three “next steps” from the previous Navigant study1 referred to in the Board decision
include:
1. Gathering information with respect to the options and costs for upgrading the short-circuit
capabilities of the distribution and transmission system in this area, the effects of Toronto
Hydro's and the City of Toronto’s aggressive Conservation and Demand Management
(CDM) efforts, and an evaluation of the end of Life Asset Replacement plan for the
transmission system serving this area.
2. Further analysis to identify the preferred Local Area Integrated Electrical Service solution
that would serve as a long-term plan for the local subsystem that meets the unique issues
facing Central and Downtown Toronto. This analysis would assess local system impacts
and examine the short-term, midterm and long-term benefits and costs for each option.
3. Development of an implementation plan for the preferred solution that could include
development of additional CDM programs, working with stakeholders to lower barriers to
DG (including incentives as appropriate), reinforcing distribution and transmission system
facilities as necessary (leveraging Smart Grid initiatives where possible) and phasing of
system upgrades to manage short-circuit levels.
Per the Board’s request, THESL has continued its analysis of the incorporation of DG into its
distribution system through follow-on analysis undertaken by Navigant that is the subject of
this report and THESL’s own work in developing its Green Energy Act (GEA) Plan.
1
Central and Downtown Toronto Distributed Generation, Final Report, July 28, 2009, prepared for Toronto Hydro-Electric System
Limited and the Ontario Power Authority by Navigant Consulting Ltd.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 1
Navigant’s analytic approach was broadly consistent with the three “next steps” as identified in
the previous Navigant report with modifications as appropriate to reflect new information and
directions to THESL subsequent to the completion of the previous Navigant report. These key
changes relate to:
The requirement for THESL to prepare a GEA Plan,
The substantial number of connection requests to THESL under the FIT and microFIT
program, and
Hydro One Network Inc.’s (HONI’s) receipt of Board approval for upgrades to Manby and
Leaside TS (scheduled for 2012 or 2013) that will increase DG connection capacity in the
THESL system served through these stations.
Working closely with THESL engineering staff, Navigant assessed the DG connection capacity
across the THESL entire distribution system and identified various enabling options that would
address specific local DG connection constraints.
With respect to DG connection capacity on THESL’s 13.8kV and 27.6kV distribution system,
several feeders and busses were found to have significant DG connection capacity available,
whereas some feeders and busses were found to have very limited or no connection capacity.
In most areas with limited or no capacity, the current HONI transmission system is the limiting
constraint to new DG installations. THESL equipment is the limiting constraint for only a few
feeders and busses.
Navigant’s specific findings with respect to THESL’s DG connection capacity include:
Currently, new DG in downtown Toronto and the eastern section of the City is limited to
2
10 MW for PV (and zero for synchronous DG ) due to short circuit capacity limits at
HONI’s Leaside, Hearn and Manby stations, and transmission limits on the 230kV delivery
system East to Cherrywood station in Pickering,
OEB-approved upgrades to the HONI system over the next few years will increase the DG
connection capacity on THESL’s 13.8kV system to 377 MW for PV or 207 MW for
synchronous DG, and
Without considering the transmission system to which it is connected, THESL’s 27.6kV
system has connection capacity for up to 833 MW of PV or 693 MW of synchronous DG.
2
Inverter-based PV generation has different electrical characteristics than synchronous-based generation (such as for a mediumsized CHP installation), particularly with respect to fault current contribution. Given these differences, the available DG
connection capacity will depend on the type of generation to be connected. For simplicity Navigant refers to the connection
capacity for PV or for synchronous DG, whereas THESL is likely to get connection requests for a combination of generation types
and the connection capacity would likely fall between the values given for PV and synchronous DG.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 2
Considering the transmission system and HONI constraints, the connection capacity is
reduced to 356 MW for PV or 283 MW of synchronous DG.
Navigant and THESL jointly assessed the viability of the various enabling options as identified
by Navigant for potential inclusion in THESL’s GEA Plan. As part of this assessment, Navigant
and THESL estimated the likely range of costs and unit costs ($ / kW of DG enabled) for such
upgrades based on THESL’s system characteristics. Since there are several different types of
constraints, varying system configurations across THESL’s service territory and non-uniform
geographic and temporal distribution of DG connection requests, there is no single “silver
bullet” or option to address all of THESL’s DG connection capacity constraints.
In general, however, where mitigation and upgrades are needed, DG connection capacity can be
increased at a unit cost well below the installed cost of DG capacity. For feeders that are
constrained, the analysis undertaken by Navigant and THESL indicates that additional DG
connection capacity can be installed through a variety of enabling options at an expected cost
less than $300/kW of DG enabled with the following caveats:
Large DG (greater than 10 MW) may require dedicated feeders and station positions that
could cost more than $300/kW of DG enabled,
Local upgrades may still be required to address capacity and voltage constraints, and
Some enabling options require changes or upgrades to HONI system; notably, some
upgrades include replacement of HONI equipment that is 50 or more years old.
THESL’s GEA plan will incorporate appropriate enabling options into several local upgrade
plans that reflect local system constraints and the best available information on current and
forecast DG connection requirements on THESL’s stations and feeders. Together, the upgrade
plans proposed in THESL’s GEA Plan and HONI’s local transmission system upgrades will
significantly increase THESL’s DG connection capacity.
Even with these substantial upgrades, new DG connection applications outside THESL’s
current forecast may still be subject to constraints on certain feeders or buses. It is expected that
many of these constraints can be addressed through the application per THESL’s DG
requirements and cost recovery policy of the enabling options identified within this report.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 3
2
I NTRODUCTION
On August 28, 2009, Toronto Hydro-Electric System Limited (“THESL” or “Toronto Hydro”)
filed as part of its 2010 rate application (EB-2009-0139) a study by Navigant Consulting Ltd.
(the “previous Navigant study”) entitled “Central and Downtown Toronto Distributed Generation”.
The previous Navigant study concluded that distributed generation (DG) may be able to
provide some future electricity supply for Central and Downtown Toronto, but further analysis
is required to more fully understand how DG could serve the needs of Central and Downtown
Toronto and how it could serve the provincial government's policy objectives.
This current Navigant study was commissioned by THESL in response to the Ontario Energy
Board’s (OEB or Board) request to THESL in its EB-2009-0139 decision. Specifically, the Board
stated in its decision:
“THESL shall continue its analysis of the incorporation of [Distributed Generation] DG into its
Central and Downtown areas. In that regard it shall file a plan concurrent with its filing
according to its distribution system planning requirements.
The plan will contain an adoption of and justification for the “next steps” listed in the Navigant
study and referenced above, or in the alternative, rationale for an “alternative approach” to
determining the optimal power system configuration for Central and Downtown Toronto.”
The three “next steps” from the previous Navigant study3 referred to in the Board decision
include:
1. Gathering information with respect to the options and costs for upgrading the short-
circuit capabilities of the distribution and transmission system in this area, the effects of
Toronto Hydro's and the City of Toronto’s aggressive Conservation and Demand
Management (CDM) efforts, and an evaluation of the end of Life Asset Replacement
plan for the transmission system serving this area.
2. Further analysis to identify the preferred Local Area Integrated Electrical Service
solution that would serve as a long-term plan for the local subsystem that meets the
unique issues facing Central and Downtown Toronto. This analysis would assess local
system impacts and examine the short-term, midterm and long-term benefits and costs
for each option.
3
Central and Downtown Toronto Distributed Generation, Final Report, July 28, 2009, prepared for Toronto Hydro-Electric System
Limited and the Ontario Power Authority by Navigant Consulting Ltd.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 4
3. Development of an implementation plan for the preferred solution that could include
development of additional CDM programs, working with stakeholders to lower barriers
to DG (including incentives as appropriate), reinforcing distribution and transmission
system facilities as necessary (leveraging Smart Grid initiatives where possible) and
phasing of system upgrades to manage short-circuit levels.
Per the Board’s request, THESL has continued its analysis of the incorporation of DG into its
distribution system through follow-on analysis undertaken by Navigant that is the subject of
this report and THESL’s own work in developing its Green Energy Act (GEA) Plan.
Navigant’s analytic approach was broadly consistent with the three “next steps” as identified in
the previous Navigant report with modifications as appropriate to reflect new information and
directions to THESL subsequent to the completion of the previous Navigant report. These key
changes relate to:
The requirement for THESL to prepare a GEA Plan,
The substantial number of connection requests to THESL under the FIT and microFIT
program, and
Hydro One Network Inc.’s (HONI’s) receipt of Board approval for upgrades to Manby and
Leaside TS (scheduled for 2012 or 2013) that will increase DG connection capacity in the
THESL system served through these stations.
The Study covered two “phases” of local transmission and distribution system development:
The first phase (Stage 1) is based on existing and projected conditions as of the end of 2012; the
second phase (Stage 2) assumes that proposed upgrades at HONI’s Leaside 230/115kV
transformer station are in place by the end of 2013.
Given Navigant’s focus on DG connection to THESL’s distribution system, it is important to
note that this study does not address the following:
An assessment of the relative costs and benefits of different types of DG,
Evaluation of the impact of intermittent DG output from renewables on control area
operating reserves, unit ramping and minimum run constraints, and inter-area transfers,
and
An analysis of steady state or dynamic system transmission performance, particularly for
high penetration DG scenarios where a concurrent or cascading loss of major DG could
cause thermal or voltage violations.
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2.1 Report Contents
Subsequent sections of this report present Navigant’s findings. Specifically:
Section 3 provides an overview of the electric power delivery system in the province, the
power system configurations in Toronto and factors that influence the ability to integrate
new distribution generation (DG) under each of these configurations.
Section 4 describes the DG connection capacity limits within THESL’s service territory.
Section 5 describes enabling options to increase THESL’s DG connection capacity limits
that were developed jointly by Navigant and THESL.
Section 6 summarizes Navigant’s analysis of the costing for the enabling options
(expressed on a $ / kW of DG enabled basis) given THESL’s typical feeder configuration
and illustrates how these options could be considered by THESL for DG connection
applications on constrained feeders.
Section 7 presents Navigant’s conclusion with respect to THESL’s DG connection capacity
limits and enabling options to increase these limits.
Navigant understands that THESL’s GEA plan will incorporate appropriate enabling options
into several local upgrade plans that reflect local system constraints and the best available
information on current and forecast DG connection requirements on THESL’s stations and
feeders. Together, the upgrade plans proposed in THESL’s GEA Plan and HONI’s local
transmission system upgrades will significantly increase THESL’s DG connection capacity.
Even with these planned and proposed upgrades, new DG connection applications outside
THESL’s current forecast may still be subject to constraints on certain feeders or buses. It is
expected that many of these constraints can be addressed through the application per THESL’s
DG requirements and cost recovery policy of the enabling options identified within this report.
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3
B ACKGROUND AND P OWER S YSTEM O VERVIEW
This section provides an overview of the electric power delivery system in the Province of
Ontario and comparable electric utilities. It describes the differences in the power system
configurations in Toronto and factors that influence the ability to integrate new distribution
generation (DG) under each of these configurations. It reviews technical constraints including
short circuit capacity, thermal capacity, voltage limits, and other constraints that limit the
amount of new DG that can be installed on THESL’s distribution system. Section 2 describes in
detail the topic of fault current contribution, as it is one of the primary factors that limit DG
penetration, and how production of fault current limits differs depending on source, i.e.,
inverter-based versus synchronous DG. The evolution of the Toronto area distribution and
transmission systems is discussed, followed by a high-level assessment of the impact equipment
and system upgrades may have on allowable amount of DG that can be installed on THESL’s
distribution system.
3.1 Bulk Power System Hierarchy and Ownership
Ontario’s electric power system, like those elsewhere across North America, consists of
generation, transmission, and distribution system assets, each of which serve distinct functions.
Generating stations in the province are both privately and publicly owned and include those
owned by Ontario Power Generation. Electricity produced by these facilities, located
throughout the province, is transmitted over the electric transmission system, the majority of
which is owned and operated by Hydro One Networks, Inc. (HONI). While the transmission
system serves a number of large directly-connected power users, the majority of Ontario’s
electricity customers receive their power through THESL and other Ontario local distribution
companies (LDCs).
The transmission system delivers electricity produced from generating stations located across
the province (or from imports via transmission interfaces to other adjacent provinces and states)
to transmission or sub-transmission system-connected customers, or to various transformer
stations through high voltage lines, which operate at 115 kV, 230 kV, or 500 kV. From these
HONI or LDC-owned transformer stations, power is transmitted through main line and lateral
distribution feeder segments to overhead or pad-mounted distribution transformers.
Distribution transformers are the second last stop in the hierarchy of the electricity transmission
and distribution systems. The distribution transformers provide secondary service to homes or
commercial business at standard utilization voltages (e.g., 480 or 240 volts).
Figure 1 below depicts at a high level the responsibilities, ownership, and operation of the bulk
power system as they relate to this study (THESL elements are highlighted in green). It also
THESL System Connection Capacity and Enabling Options for Distributed Generation
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4
illustrates the points of interconnection between transmission and distribution systems.
Typically, HONI owns all equipment from the low voltage side of the substation step-down
transformers (including the transformer) to the high-voltage side of the generator step-up
transformers; THESL typically owns all equipment from the low side of the substation stepdown transformer to the customer meter. The latter includes 13.8kV and 27.6kV switchgear and
breakers, many of which are located on the same substation site where HONI high voltage
equipment is located.5
Figure 1 - Illustrative Structure of the Bulk Power System and LDC Distribution Systems
Though much of the transmission system operates without constraint, increased demand for
power from consumers and interconnection from FIT-related generators has placed limitations
on certain areas of the system. Hydro One has identified a number of constraints within its
system that have an impact on the investment and interconnection-related decisions of certain
of its downstream customers, including THESL. From Hydro One’s recent rate filing (EB-XXX),
specific technical constraints at both its Manby and Leaside transformer stations were
identified, each having an impact on THESL’s ability to approve requests for DG
interconnection.
Specific constraints include the following (other HONI constraints may apply):
Limited breaker capacity due to short circuit capacity constraints;
4
Figure 1 also seeks to provide clarity to readers by illustrating the hierarchy of the bulk power system from transmission systemconnected generation down through the distribution transformer and into the home.
5
One exception to this rule is THESL’s 230kV/27.6kV Cavanaugh Station, where THESL owns virtually all equipment located
within the substation fence.
THESL System Connection Capacity and Enabling Options for Distributed Generation
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Reverse power flow limitations based on transformer thermal capacity;
Reverse power flow limitations based on minimum load requirements; and,
Load transfer scenarios, i.e., Manby to Leaside (and vice-versa) constraints.
Technical constraints also exist within THESL’s distribution system; however, as this study
demonstrates, most technical limitations within the distribution system are subsumed by those
imposed by the transmission system. Constraints within the distribution system that limit the
amount of DG include:
Feeder continuous load thermal ratings;
Short circuit capacity (mostly station equipment); and,
Reverse power limits driven by transformer thermal capacity and minimum load
criteria (this may be deemed to be a transmission-level constraint as the devices are
owned by HONI).
While both short circuit capacity and reverse power flow limits are constraints within the
transmission and distribution systems, they reflect the technical limits of existing transformer
stations or issues that exist farther upstream, i.e., circuit breaker capacity constraints at HONI’s
Leaside, Hearn and Manby stations.
Within the context of this study, constraints at HONI’s Leaside and Manby 230/115kV
transformer stations have imposed limitations on both short circuit and thermal capacity within
the THESL distribution system, and impact THESL’s ability to interconnect new DG in the
13.8kV downtown system. These limitations are described in greater detail in the following
sections of this report.
3.2 Distribution System Topology
Distribution System Voltage Levels and Feeder Vintages
Just as each type of DG unit, whether a photovoltaic (PV) system or synchronous gas generator,
has certain electrical and physical characteristics that require consideration as part of a utility’s
interconnection process, distribution feeders (or circuits) have inherent characteristics that
require additional review as part of the evaluation process. These characteristics are largely
driven by the type of system that an individual feeder is located and may include: voltage level;
feeder length, overhead or underground, feeder type, i.e., radial, network/secondary, or spot;
physical thermal limits; and feeder length. Distribution feeders across North America operate
at one of several standard primary voltage classes: 5kV, 15kV, 25kV, or 35 kV.
Toronto Hydro’s distribution system is comprised of distribution feeders that operate at one of
three nominal distribution primary voltage levels – 4.16 kV, 13.8 kV, or 27.6 kV. Within the
THESL system the primary voltage level of distribution feeders is largely based on feeder
THESL System Connection Capacity and Enabling Options for Distributed Generation
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vintage, which tends to vary geographically.
approximately 900 feeders.
In total, THESL customers are served by
Distribution feeders within the THESL system also vary by length. The length of feeders
considered “long” and operating at the 27.6 kV level ranges between 5 and 6 km whereas
similarly long 13.8 kV feeders range in length between 3 and 4 km. Conversely, “short” feeders
operating at the 27.6 kV level range between 3 and 4 km, compared to similarly short 13.8 kV
feeders, which range between 2 and 3 km. Feeder length itself is not typically an issue when
interconnecting DG units to the distribution system; however, the distance such units are from
the transformer stations bus can be.
Figure 2 depicts how various areas of the City of Toronto are served by HONI transmission
lines that delivery bulk power to THESL stations by voltage level. Most 230kV transmission
lines serve THESL stations with distribution voltages at 27.6kV, whereas all 115kV transmission
lines in the downtown areas serve stations with distribution voltages at 13.8kV (shaded blue).
About 30 percent of THESL’s distribution feeders operate at 27.6 kV (unshaded) and serve
nearly 3000 MW of load across much of the suburban outer ring of the city, while almost 70
percent of feeders operate at 13.8 kV (shaded blue) and serve some 2000 MW of load. The area
shaded in tan is where underground secondary networks serve downtown load centres,
including the financial district and areas near the CN Tower.
Figure 2 – M ap of THESL System by System V oltage
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Distribution Feeder Topologies
Feeders within the THESL system are configured according to one of four distribution system
topologies, which are typical of systems across North America6 and include: radial, loop,
secondary network, and spot network systems. Much of THESL’s distribution system is
organized by feeder voltage as we previously detailed and follows the growth of the City of
Toronto over the past several decades.
The central and downtown core areas of the city are largely served by 13.8kV radial distribution
lines and cables; secondary network and spot network systems serves the core downtown
financial district. The outer suburban area of the city is mostly served by 27.6kV overhead
radial feeders. The three distribution feeder topologies are described in detail below.
Radial Systems
Radial distribution systems are the most common configuration used by electric utilities and are
the least expensive to design, construct, and maintain. However, this configuration is the least
reliable as customers are supplied from a single source at any given time. This type of system
contains no closed “loops” as shown below in Figure 3.
If any part of a given radial feeder system experiences a failure, some or all of the customers
served by that feeder will experience an outage until repair crews are able to repair and restore
the system.
Radial systems are mainly comprised of a transformer substation, a number of radial feeders,
and distribution line transformers that convert the higher voltage (e.g., 13.8 kV or 27.6 kV) to a
customer utilization level (120/240 V, 120/208 V, or 277/408 V). Figure 3 presents a schematic of
a typical radial configuration used in the THESL system.
Figure 3 – Radial Configuration
Substation
HV
Load
Load
Load
Load
Load
6
Secondary networks generally appear only for utilities serving urban or very high load density load centers.
THESL System Connection Capacity and Enabling Options for Distributed Generation
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Auto-Loop or “Loop” Network System
An auto-loop, or simply loop, system is an enhanced radial system differentiated by its ability
to serve customers via two radial feeders, as necessary. In looped systems automated or semiautomated equipment at the transformer substation detects when equipment failure has
occurred on one of the two feeders and can either automatically transfer load to adjacent feeders
or alert a control-room operator, who can then manually decide on the appropriate action to
take. Many of THESL’s 13.8kV downtown feeders operate in an auto-loop configuration.
Looped systems can provide utility customers with incremental reliability-related benefits, as
the time needed to restore service to some customers is reduced. Figure 4 illustrates the typical
configuration of a two-feeder loop network. The normally open switch at depicted by the open
dot is where the transfer is enabled, while one or more normally closed switches (or circuit
breakers) is open to ensure all lines operate in a radial manner. Once the fault is cleared and the
faulted line segment is returned to service, the feeders usually are switched back to their
original configuration.
Figure 4 – Looped Feeder Configuration (Radial)
Secondary Network Systems
Secondary network or simply “network” systems are among the most sophisticated distribution
systems used by electric utilities and often serve large central business districts within many cities
across North America. In network systems, customer loads are served by multiple feeders fed via
a number of redundant transformers and network protectors. As a result, they are inherently
more reliable than radial systems; however, they incur higher design, construction, operating and
maintenance costs.
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Figure 5 illustrates how customer load is served by the network system via several transformers
simultaneously supplied from different primary feeders. The secondary windings of integrated
network transformers (TX) and network protectors (NP) are interconnected in a parallel
configuration forming what is typically known as a “secondary grid system” – loads are then
served from various locations within this grid. The key feature of grid network systems is that
a loss of any single primary or secondary line segment will not cause an interruption in load.7
Some secondary networks are designed to sustain a loss of two elements without loss of load.
Such is the case for some of the secondary networks in downtown Toronto.
Figure 5 – Secondary Grid N etwork System
Substation
HV
TX & NP
TX & NP
LV
Loads designated
by arrows
Spot Networks
Spot networks are secondary network systems that consist of two or more network transformers
located at a single site. They are similar to secondary grid networks, but usually serve a much
small area. Further, some secondary spot networks are owned by business customers, whereas
virtually all grid networks are owned by the utility. Spot network distribution systems
typically a single site comprised of several buildings or a single large building such as an office
tower. Spot networks are designed to provide highly reliable service to a single site and are
often configured in high load-density areas within large cities.
In a spot network, the secondary network-side terminals of the network transformer units are
connected together by a bus or cable as presented in Figure 6; the resulting interconnection
structure is commonly referred to as a paralleling or collector bus. Should a fault or failure
occur on the paralleling bus, customers on the spot network are likely to experience an outage.
7
The vast majority of secondary network systems are located in underground conduit within high load density sections of urban
areas.
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Figure 6 – Spot N etwork Configuration
Substation
HV
TX & NP
TX & NP
LV
Loads
Cases Selected for Distribution Impact Analysis
Navigant’s analysis of the distribution system’s capability to interconnect DG incorporates
results from a detailed fault simulation study based on eight feeder configurations that were
selected as a representative cross-section of the THESL system. In order to fully understand the
impact that any DG may have on the THESL distribution system, detailed power flow and fault
study simulation analyses were undertaken by THESL using its CYME software package.
Working with THESL, Navigant developed eight cases for software simulation that represent a
cross-section of THESL’s feeder system based on voltage level, feeder type, and length. The
eight feeder cases simulated are as follows:
Long 27.6 kV Feeder ( 5-6 km)
Short 27.6 kV Feeder (2-4 km)
Long 13.8 kV Feeder (3-4 km)
Short 13.8 kV Feeder (2-3 km)
Pilot Wire 1
Pilot Wire 2
Bathurst Tie Point (Extended Feeder)
Terauley/G&D Tie Point (Extended Feeder)
The study’s outputs include short circuit profiles, voltage profiles, and cable ampacity profiles.
Simulations were undertaken with DG units connected at three locations: the transformer
station bus, feeder midpoint, and at the end of each distribution feeder. As such, the scenariobased results of the fault study simulation encompass a broad range of feeder and DG
configurations. These results have informed the higher-level modeling work undertaken in Part
2 and Part 3 of this study and provide a sound basis for many of the assumptions used.
THESL System Connection Capacity and Enabling Options for Distributed Generation
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These eight cases were further simulated under four DG operating scenarios that included:
No Connected DG
100% Synchronous DG
100% Photovoltaic DG
DG supply mix across feeders connected to a single bus
Detailed Power-Flow Simulation Cases
A series of power flow simulation analyses using the CYME distribution model were performed
to assess the impact of increasing levels of DG penetration on representative feeders selected for
detailed study. Three performance criteria were evaluated via CYME: (1) thermal loadings; (2)
voltage drop (or rise); and (3) incremental fault current contribution. Case studies included all
DG installed at the beginning (i.e., substation bus), middle, and end of the feeder. For
practicality and simplification of simulation model set up, all DG is assumed to be installed on
the main or trunk line feeders.
For this study, eight case studies were structured to represent typical feeder configurations in
the THESL system. The case studies include long and short feeders operating at 13.8kV and
27.6kV, and specialized cases where feeders operate in parallel to increase capacity limits and to
account for temporary feeder transfers that typical occur during maintenance of outages. These
case studies are listed in the prior sections. A more detailed description of these eight cases
appears in Appendix A. The results of the CYME studies are summarized in Appendix B.
3.3 Short Circuit Capacity
Short circuit capacity limits on both the THESL and HONI systems are important factors in the
determination of how much DG can be installed on THESL’s distribution system. Short circuit
capacity is generally defined as the maximum of current a device is able to withstand without
failure during fault conditions, such as a line-to-line or line-to-ground fault. The source of the
fault current is from all generators connected to the bulk power grid and from any DG
connected to the lower voltage transmission and distribution system8. The level of fault current
is highest when the fault is closest to the device. Accordingly, studies used to calculate the
maximum fault current for equipment and devices susceptible to short circuit capacity limits
assume the fault is located closest to these devices; for example, circuit breakers located within a
station.9 If the amount of fault current contribution from DG located on feeders produces
8
The terms short circuit capacity and maximum fault current have identical meanings and are used interchangeably throughout
the report.
9
To determine the short circuit capacity at stations and other locations on the power delivery system sophisticated power flow
simulation models are employed. These models predict how much fault current will flow to a specific location from generators
located throughout the province. These studies typically are conducted by HONI or the Ontario Power Authority (OPA) to
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 15
sufficient additional fault current to cause total fault current to exceed equipment ratings, then
the DG may not be allowed to interconnect to the system until corrective measures are made to
reduce fault current or upgrade equipment, or both.
Recent studies of the potential for DG in Toronto and recent applications for DG
interconnection underscore the impact of short circuit capacity on allowable DG penetration.
Prior studies confirmed short circuit limits in downtown Toronto can significantly limit DG
installations; in particular, the amount of rotating DG technology (e.g., synchronous
generators)10 currently is constrained in the eastern segment of downtown Toronto due to
limited available fault current at HONI’s Leaside Station. Short circuit capacity is usually
measured in thousands of amperes (e.g., 40kA for a breaker rated to withstand 40,000 amps of
fault current).
THESL Short Circuit Limits
The primary limiting element for short circuit capacity is substation equipment (where fault
current levels are highest); most THESL components subject to fault current limits are
substation low voltage breakers (HONI typically owns high voltage breakers and equipment).
Short circuit capacity at THESL’s downtown stations serving 13.8kV distribution feeders is
generally lower than at the stations serving THESL’s 27.6kV feeders.
HONI Short Circuit Limits
Prior DG studies and recently supplied data from HONI indicate fault current limits are
constrained mostly at the two major 230/115kV supply stations at Leaside and Manby. Leaside
is severely constrained due to the presence of 40kA rated equipment; mostly 115kV circuit
breakers. Recent applications for DG interconnection in downtown Toronto have been denied
11
due to unacceptable fault current contribution.
3.4 Feeder Thermal Rating and Transformer Thermal Capacity
Thermal capacity in both the transmission and distribution systems is largely based on the
physical properties of various types of equipment including the actual cables from which
feeders are constructed and the windings and internal and external equipment from which
primary transformers are built. As power flows through a conductive element the resistance of
determine the short circuit capacity at each station. The presence of DG on distribution feeders can contribute fault current that
can cause station equipment such as circuit breakers to exceed the short circuit capacity limit.
10
Synchronous generators produce up to six per unit or greater fault current, which is far greater than the one to two per unit fault
current produced by inverter-based DG technology such as PV. Further, the duration of fault current is longer for synchronous
DG, as it will continue to produce fault current until the generator breaker opens. The time interval for the DG breaker to open
varies, but can be up to 30 to 60 cycles (or longer). In contrast, inverters typically will produce fault current for three to four cycles
before damping out due to loss of a voltage source.
11
Mostly larger synchronous DG, including a 14 MW generator in downtown Toronto.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 16
that element produces a certain amount of heat, which that element must be able to safely
withstand. Further, lines and equipment that deliver electric power typically are rated to
withstand a threshold level of current when line faults or short circuit conditions exist;
commonly referred to fault duty or capacity. Lines and equipment typically are capable of
carrying very high levels of current for a short time interval; that is, the time typically required
for protective devices to electrically isolate and interrupt a fault before it damages equipment.
As illustrated in Figure 1, transmission system assets including lines and transformer stations
(up to and including the low-side of the station power transformer) are owned by Hydro One.
Distribution system assets such as transformer station low voltage bus and breakers,
distribution feeders (overhead lines and underground cable), distribution transformers, and
metering are owned by Toronto Hydro. While this study identifies the amount of DG that can
be installed on THESL’s distribution system, both transmission and distribution constraints and
impacts must be considered to determine acceptable levels of DG penetration.
Distribution System Continuous Load Feeder Thermal Rating
The continuous load thermal rating of feeders within the distribution system refers to the safe
operation of feeders under continuous full load conditions. Feeders operating within the
distribution system operate at one of three voltages (4.16 kV, 13.8kV, and 27.6 kV) as described
previously. Correspondingly, within each voltage class, feeders are rated at a continuous load
level to withstand the heat produced during the transmission of a given amount of power.
The 4.16 kV, 13.8 kV, and 27.6 kV systems each have feeders rated to operate no higher than 4
MW, 10 MW, and 20 MW, respectively. Within the distribution system, these feeder thermal
rating levels represent a theoretical ceiling on the level of DG that can be safely interconnected.
These thermal limits are analogous to the limits on household wiring circuits. A 240 V circuit
(such as for an electric range) can serve a higher power rating than a 120 V circuit (such as
would supply lights and outlets).
HONI-Owned Transformer Station Capacity Limits
The thermal capacity of HONI Transformer Station (TS or Station) equipment is based largely
on the ability of the station power transformer and ancillary equipment to withstand a predetermined level of reverse power flow. Reverse power limits are based on the configuration of
the transformer, its vintage, and primary winding system. Thermal capacity limits at
transformer stations connected to the THESL system are also affected by upstream issues,
which are beyond THESL’s control and responsibility. Accordingly, HONI calculates thermal
capacity limits at each transformer. Initial discussions with HONI indicate that many
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 17
transformers, particularly those located in stations described as the “Bermondsey” design, have
12
strict reverse power limits.
HONI owns all power transformers in each of its stations serving THESL (Note: THESL owns
the power transformers in the THESL-owned Cavanagh station and will own the power
transformers in the Bremner station currently under development by THESL). HONI also owns
all transmission lines, cable and ancillary equipment located upstream from the high-side of the
transformer. However, Navigant did not determine whether transmission line or cable thermal
limits would be exceeded for increasingly levels of DG, as THESL does not currently operate a
transmission load flow model that would detect thermal (or voltage) violations. Navigant has
assumed that the primary transmission thermal limits are limited to station transformers.
3.5 Feeder Load Diversity
THESL’s distribution system varies by geography, voltage level, and feeder configuration as
detailed previously. Its customers also vary by class, have unique load profiles, and are
comprised of a mix of residential, commercial/institutional, and industrial customers. THESL
distribution feeders range between serving a single commercial or industrial customer, in the
case of a spot network, to serving a diverse mix of customers via one of the other feeder
configurations.
Characteristics of Load Types
Feeders on the THESL system exhibit a range of load shapes depending on location and
customer mix. Residential and mixed commercial loads typically have lower demand at night
versus relatively flat industrial load profiles. A typical load profile for a feeder serving core
downtown load is given in Figure 7.
12
THESL has been notified that the Bermondsey configuration provides for cross-transformer connections to the low-side bus,
resulting in potential circulating power flows and excess heating in these transformers if power flows are reversed; that is, from
the low-side primary distribution into the transmission network.
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Page 18
Figure 7 – Typical Daily Load Profile
1.20
Actual Windsor TS Hourly Load Profile (Bus A3A4)
Normalized Load/Generation
1.00
0.80
0.60
0.40
Min load occurs at
4:30AM
0.20
0.00
1
2
3
4
5
6
7
8
9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
3.6 Generation Capacity and DG Scenarios
Part 1 of Navigant’s study examines limits associated with DG technologies mostly likely to be
installed on THESL’s distribution system. Locations include DG installations on THESL’s
4.16kV, 13.8kV and 27.6kV distribution feeders, and direct connection to stations via dedicated
feeder connections. The latter option assumes existing feeder capacity is insufficient or the DG
unit is too large to install on distribution lines. While no specific limit is assumed for DG unit
size, feeder thermal capacity effectively establishes limits of 10 MVA and 20 MVA for DG
installations on THESL’s 13.8 and 27.6kV distribution systems, respectively.
Navigant evaluated a range of DG technology combinations, from 100 percent inverter-based to
100 percent rotating machines (i.e., synchronous DG). The intent of evaluating DG over a
spectrum of technology types is to present potential ranges in DG penetration – a single value
based on a pre-defined mix of DG does not realistically portray what actually may be installed
prospectively. Further, it is not possible to determine in advance where DG is most likely to be
installed for each feeder. Accordingly, Navigant evaluated DG under three DG installation
scenarios: (1) at the station bus; (2) mid-feeder; and (3) at the end of the feeder.
Under Navigant’s direction, THESL conducted load flow simulation studies to evaluate
distribution feeder impacts for various combinations of DG technologies and feeder locations.
Findings from these studies led to a determination as to whether DG will cause violations of
thermal loading or voltage criterion described in Section 2.4, and whether the incremental fault
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 19
contribution will exceed station equipment short circuit limits. For the latter, Navigant
13
assumed fault current contribution of 5 to 1 for synchronous generation and 1.5 to 1 for PV.
3.7 Conservation and Demand Management
Over the past several years THESL has instituted several Conservation and Demand
Management (CDM) programs on a system-wide basis. Collectively, these programs have
reduced distribution feeder and substation peak loads, thereby freeing up capacity for other
purposes. The load forecasts used to identify available DG capacity are net of past and
projected CDM programs. As such, the impacts of CDM have been incorporated into the study
findings. Specifically, the available DG capacity, by location, recognized the demand reductions
achieved by CDM. In some instances, the load reduction achieved by CDM actually reduces the
amount of new DG that can be installed, as DG output offsets customer loads. If reverse power
is the primary limiting constraint on a feeder or substation, then available DG capacity may be
reduced due to CDM. To the extent that significantly higher CDM energy and peak demand
reductions are forecast, the analysis used to derive available DG capacity should be adjusted.
Several of the measures described in sections that follow include what could be considered as
“demand management” options for DG, including interruption of DG during critical load
intervals or when emergencies occur. Another option that may prove effective is to offer
customers owning DG an option that would allow THESL to interrupt load in amounts equal to
the size of the DG during emergencies or load transfers. This option would be offered when the
hours of interruption are expected to be very small; for example, less than 100 hours a year. A
variation of the demand management option for DG is to allow THESL to interrupt DG in low
load hours when reverse power limitations constrain DG capacity. The latter option would be
offered when the number of hours of reverse power flow is very low.
3.8 Load Transfer Scenarios
Similar to other LDCs, THESL occasionally will transfer load from one feeder onto an adjacent
feeder, mostly for line or station maintenance. When possible, routine maintenance is
performed when loads are low. Load transfers are also made when station or feeder outages
occur, in which case unfaulted line segments are transferred to adjacent feeders to minimize the
time and duration of outages to THESL customers. Because DG may be connected to both
13
These ratios express the increase in current produced by the generator under fault conditions versus rated output. The ratio
assumed for synchronous generators is consistent with prior studies and industry literature. The level of fault current for PV
tends to have greater variability than synchronous DG, as some studies and measurement show a one-to-one ratio, whereas
others show ratios of two-to-one of higher. For PV, this study applies a value used by HONI, which is more conservative than
lower ratios assumed by others involved in similar studies. Further, the impact of synchronous DG fault is greater than PV due to
longer breaker clearing times. Synchronous generation will continue to produce fault current until the station breaker or line fuse
clears the fault. In contrast, PV fault current dampens out very quickly – usually 2 to three cycles – as the collapse in the voltage
field due to a line fault causes the inverter to cease operation.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 20
feeders, it is highly likely that a single feeder may carry much larger amounts of DG when the
lines are reconfigured for maintenance or outage restoration. The impact of the larger amounts
of DG – even temporarily – is potential voltage or thermal loading violations. Further, if the
14
feeder transfer is from an adjacent station, fault current limits may be exceeded as well.
3.9 Evolution of the Toronto-Area Distribution System
Prior to its amalgamation with neighbouring municipal utilities (such as North York Hydro),
much of THESL’s distribution system operated at 4.16kV or 13.8kV, serving downtown Toronto
and other high load density areas. Amalgamation with the neighbouring utilities (in what is
commonly referred to as the “Horseshoe”) introduced a significant amount of higher rated
27.6kV distribution facilities. Two important differences between the two systems are their load
carrying capacity and their source of supply:
The older 13.8kV system has lower load carrying capability than the newer 27.6kV system.
All 13.8kV stations are served via HONI 115kV lines emanating from Manby or Leaside
supply stations whereas most 27.6kV stations are served from 230kV lines generally
running east-west in the corridor north of Highway 401.
Figure 8 illustrates the 230kV (light blue) and 115kV (green) HONI transmission lines that serve
THESL’s 27.6kV and 13.8kV systems, respectively – THESL’s service area is shaded tan.
Figure 8 – Toronto A rea Transmission Supply
14
Currently, most downtown 13.8kV feeders do not have feeder tie points that would enable station-to-station load
transfer. However, THESL currently is conducting studies to identify cost-effective upgrades that provide for
station-to-station load transfers via its 13.8kV system.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 21
To limit fault current and undesired parallel flows, the 115kV systems serving downtown
Toronto from Manby and Leaside are electrically separated. Any future plans to tie the 115kV
stations would reduce available short circuit capacity, thereby further curtailing DG
installations.
For this study, the thermal capacity of 13.8kV lines is assumed to be 10 MVA; the 27.6kV system
is limited to 20 MVA. Notably, many of the 115/13.8kV downtown stations are over 30 to 40
years old; whereas many 230/27.6kV stations are less than 30 years in age.
3.10 Limiting Factors to Increased DG Penetration
This section presents the operating, capacity and performance factors that can limit new DG
installations on THESL’s distribution system. It excludes factors that impact bulk transmission
operations or planning (e.g., 230kV and 500kV lines that support the interconnected grid) or
IESO control area generation performance. The impact of each of these constraints on the
amount of new DG that can be installed on THESL’s distribution system is presented in Section
4 along with candidate mitigation options and equipment upgrades that may increase DG
capacity limits, including the cost of these options.
Short Circuit Capacity Limits
Prior studies confirm short circuit limits on station equipment as one of the primary limiting
factors on the amount of DG that can be installed in certain areas of the THESL system;
particularly in downtown Toronto. Station equipment – often in the same location – is partly
owned by HONI, and partly by THESL. Typically, HONI owns and operates all equipment
from the low voltage side of station power transformers up to and including higher voltage
transmission equipment. Toronto Hydro typically owns lower voltage station circuit breakers
and switchgear line-ups. Studies results presented in subsequent sections indicate that in some
sections of the city, available short circuit capacity is limited by HONI constraints; in other
sections, THESL equipment is similarly constrained or is the primary limiting factor. Specific
factors that limit available short circuit capacity for THESL and HONI energy delivery systems
are described in greater detail below.
THESL Short Circuit Capacity
Most THESL equipment that is susceptible to fault current restrictions (i.e., short circuit
capacity) is located within the low voltage side of stations where THESL owns and operates
equipment (high voltage station equipment is discussed in the next section). Further, most
THESL station equipment subject to fault current limits is at older 13.8kV stations in downtown
Toronto; a much margin of available short circuit capacity is generally available on THESL’s
27.6kV system. Table 1 list stations where THESL short circuit capacity limits allow no
additional DG, and includes a summary of existing DG connected to each of these stations.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 22
Table 1: THESL Stations with Short Circuit Capacity Limits
(Low Voltage Constraints)
Available Short
Circuit Capacity
(MVA)
Sum of DG & FIT
Generation Capacity
(MW)
Bridgman A5A6H Bus Total
0
0.000
Carlaw A4A5 Bus Total
0
0.088
Carlaw B1B2 Bus Total
0
0.000
Carlaw B3B4 Bus Total
0
0.002
Cecil A1A2 Bus Total
0
6.670
Gerrard A1A2 Bus Total
0
0.219
Leaside A1A2Q1Q2
0
0.000
Leslie BY Bus Total
0
7.352
Richview BY Bus Total
0
1.050
Wiltshire B1B2 Bus Total
0
0.000
Wiltshire A1A2 Bus Total
0
0.057
Wiltshire A3A4 Bus Total
0
1.062
Wiltshire A5A6 Bus Total
0
0.485
Woodbridge BY Bus Total
0
0.000
THESL Station Bus
Many of the constraints on the THESL (and HONI) system that limit the amount of new DG
that can be added are located in downtown and eastern section of Toronto – many of these lines
operate at 13.8kV, the dominant voltage on the THESL system prior to amalgamation. The
27.6kV system that surrounds downtown Toronto – i.e., the “Horseshoe” – has fewer short
circuit capacity constraints. As noted, most short circuit capacity constraints are associated with
station bus or breaker ratings (as opposed to feeder constraints). Generally, THESL 13.8kV
station equipment is rated 500 for MVa, whereas 27.6kV stations, which generally include
newer equipment, is rated for 800 MVa. Each of these limits is specified within the provincial
Transmission System Code (TSC), which THESL follows in the design and operation of its
system.
HONI Short Circuit Capacity
Hydro One short circuit limits in the Toronto area are well documented. Navigant’s
Distributed DG Study and OPA’s 2008 study confirm that limited short circuit capacity in key
230/115kV substations in the eastern part of Toronto significantly constrains the amount of DG
that can be installed in certain downtown 115/13.kV substations. Figure 9 illustrates the three
major HONI in-City stations equipped with devices that are nearing fault current limits. The
limiting equipment is primarily circuit breakers and ancillary equipment rated for 40kA (40,000
amps). Modern devices typically are generally rated for 60kA. Of the three stations, Leaside is
most susceptible to short circuit violations, including those caused by incremental fault current
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 23
contributions from new DG. As noted in recent studies and reports, HONI expects to upgrade
Leaside and replace the breakers with higher rated equipment by the end of 2013.
Figure 9 – Downtown Short Circuits Limits (Transmission Stations)
Note: Short circuit levels near station equipment capability (~40,000 A) at Hearn, Manby and Leaside
Source: Electricity Service to Central and Downtown Toronto, Ontario Power Authority,
September 25, 2008
Figure 10 at the top of the following page illustrates graphically short circuits limits for THESL’s
service territory solely due to constraints at individual stations directly connected to THESL
feeders. The map is color-coded to highlight the boundaries between areas with severe
constraints versus those with ample capacity. The irregularity of the boundaries reflects the
territory served by feeders from stations with bus and breaker limits. Such boundaries usually
are not homogeneous as some feeders are very short in high load density areas, whereas other
feeders can traverse several kilometers in areas where load density is lower.
Until Leaside, Hearn and Manby 115kV breaker and bus upgrades are completed, HONI has set
short circuit capacity limits for new PV at 10 MVA in downtown Toronto and 10 MVA in the
southeastern section of the city (e.g., Scarborough) due to constraints on certain 230kV HONI
transmission facilities that are not directly connected to THESL feeders. Specifically, these
facilities are at HONI’s Manby and Leaside stations and HONI’s 230kV transmission line
running through the southeastern section of the city to Leaside from Cherrywood station east of
Toronto.
Figure 11 at the bottom of the following page illustrates the short circuit capacity limits on the
THESL system at individual stations directly connected to THESL feeders AND the constraints on
certain 230kV HONI transmission facilities that are not directly connected to THESL feeders. The
large red area in Figure 11 represents the areas of Toronto served by these transmission facilities.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 24
Figure 10 – Short Circuit Limits at Individual Stations Directly Connected to THESL Feeders
Figure 11 – Short Circuit Limits at Individual Stations Directly Connected to THESL Feeders and due to
Constraints on Specific HON I 230kV Transmission Facilities
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 25
Feeder Voltages
THESL seeks to limit voltage thresholds with a range (e.g., 115 volts to 125 volts for residential
supply voltage). Feeder voltages can experience unacceptable voltage drop (or rise) due to the
presence of DG. Under high feeder loading, voltages can drop below the acceptable threshold;
whereas large amounts of DG located at the end of a lightly load feeder increases the likelihood
that voltages will rise above the acceptable threshold.
Figure 12 illustrates how voltages can rise as a function of distance for lightly loaded feeders. 15
When DG is located close to the station breaker (left-hand side of X-Axis), voltages vary only
slightly. However, when DG is installed at or near the end of the feeder (8000 meters on left
side of X-Axis), voltages can rise to unacceptable levels. Feeders also can exhibit the opposite
behaviour – that is, low voltages can result when lines are heavily loaded.
Figure 12 – V oltage Rise for Lightly Loaded Feeders
THESL Capacity Constraints
Where the combined output of DG installations at the distribution level exceed the continuous
rating or lines, cables of station equipment, mitigation of these impacts or construction of
dedicated lines may be needed to serve new DG. Although maximum DG size is limited to 10
MVA and 20 MVA on 13.8kV and 27.6kV feeders, respectively, the combined output of several
feeders from a common bus may cause thermal loading violations. Further, large amounts of
DG on feeder laterals also can cause violations, as could combined DG output when DG from
15
THESL performed a voltage analysis on a hypothetical DG unit on a typical distribution feeder.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 26
independent feeders are combined (i.e., via feeder tie points) during maintenance or outage
events.
Protection Constraints
Large amounts of DG have the potential to impact distribution protection coordination. For
larger DG, sophisticated protection and control systems often are essential to enable
interconnection. Further, on secondary network systems, reverse power relay settings can
significantly limit DG penetration; particularly for rotating (synchronous or induction) DG.16
3.11 Additional Details
Other information that is relevant to a determination of DG penetration limits and cost of
mitigation is presented below, including how existing DG is incorporated into the analysis.
Existing DG Installations
Currently, there are several DG installations on THESL’s system, including residential and
commercial behind-the-meter installations. Collectively, the total rating of these devices is just
under 90 MW. Table 2 presents the total capacity of smaller and larger DG in Toronto.
Table 2 – Existing DG Capacity in Toronto (as of 2009)
Size of DG
Number
Power Output ( kW )
Micro (≤ 10kW)
219
726
Small (≤ 1MW)
16
5917
Medium (≤ 10 MW)
21
73,482
Large (>10 MW)
1
11,000
257
91,125
Total
Figure 13 illustrates existing residential DG locations in Toronto, mostly small PV rated less
than 10 kW.
16
Some utilities prohibit the installation of synchronous or induction DG on secondary and spot networks.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 27
Figure 13 – Residential DG Installations in Toronto
Figure 14 illustrates commercial DG installations in Toronto. Typically, commercial DG
installations are much larger than residential DG, including synchronous machines that are not
used in residential applications.
Figure 14 – Commercial DG Installations in Toronto
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 28
Because the residential and commercial DG that appears above is part of the existing system
and their output has already been incorporated into THESL load measurements, they are not
explicitly included in our analysis of DG penetration limits. Further, the aggregate capacity
existing DG is sufficiently low to warrant exclusion from our analysis.
The largest wind DG installation connected to the THESL system, a 750 kW wind turbine
located along the lakeshore, is shown in Figure 15.
Figure 15 – 750 kW W ind Turbine in Downtown Toronto
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 29
4
DG C ONNECTION C APACITY L IMITS
This section presents DG capacity limits on THESL’s 13.8kV and 27kV systems for inverterbased (PV) and synchronous DG as they exist today (Stage 1). This section also presents the
expected increase in DG capacity limits following HONI’s completion of OEB-approved
upgrades on the high voltage system that delivers power from the bulk power system to THESL
stations (Stage 2).
The DG penetration limits presented in this section cover two scenarios: the first assumes 100
percent inverter-based DG is installed; the second assumes 100 percent synchronous-based DG
is installed. Candidate options to increase these limits are presented for each DG technology
type on THESL’s 13.8kV and 27kV system.17
4.1 Derivation of DG Connection Capacity Limits
DG connection capacity limits for each DG technology were estimated by assessing the impact
of each constraint described in Section 2. The methodology Navigant employed to estimate
capacity limits both the 100 percent inverter-based and 100 percent synchronous DG scenarios
is described below.
Methodology
The following step-by-step approach was employed to identify DG capacity limits:
Establish an “Existing Conditions Case” based on a review of THESL’s system
refurbishment and upgrade plans through end of 2012; station loading is net of THESL’s
forecast of CDM impacts. The Existing Conditions Case (Stage 1) assumes upgrades at
HONI’s Leaside, Hearn and Manby Stations are not yet undertaken.
For all equipment on the distribution side of the 35 transformer stations serving THESL’s
service territory, review (and augment as necessary) information that THESL has compiled
with respect to available fault duty limits, single and three phase fault currents and other
station-specific information necessary to perform other tasks.
Identify and characterize feeder and system configurations representative of THESL’s
distribution system. These include the downtown secondary grid network (serving the
financial district), 4 kV and 13.8 kV feeders serving downtown Toronto and 27.6 kV
feeders serving the suburban areas of Toronto (i.e., the “Horseshoe”). Approximate the
17
The study does not explicitly identify mitigation options on THESL’s 4.16kV system, as 4.16kV lines typically are served from unit
stations emanating from THESL’s 13.8kV and 27kV lines, downstream of the station breaker. Accordingly, any upgrades to either
of the higher voltage lines are assumed to increase limits on the 4.16kV lines as well.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 30
percentage of THESL’s distribution system and relative mix of customers served by each of
18
these configurations.
Identify typical “base” generator configurations and their key electrical parameters
(including short circuit contribution) of each DG type. The DG types include synchronous
(such as large CHP), induction (such as small gas engines) and inverter-based equipment
(such as PV).
For each of the feeder and system configuration, identify short circuit constraints within
the THESL system for each of the base DG generation configurations connected: 1) at the
station busbar; 2) midway down the feeder; and 3), at the end of the feeder.
Identify incremental upgrade equipment / bundles and their associated costs to increase
distribution system short circuit capacity levels for each of the representative feeder /
system and DG configurations from above. As appropriate, identify incremental
equipment / bundles and associated costs to increase the ability to connect DG on the
THESL side of each of the transformer stations serving THESL.
The approach outlined above recognizes that factors that limit DG penetration will vary
according to DG size, location and constraints that exist at any particular feeder or substation.
Accordingly, DG limits were derived by identifying the most significant or limiting constraint
for each of the feeders that were analyzed for potential DG interconnection (up to 900 feeders
were analyzed). For example, on some feeders, new DG capacity was constrained by short
circuit capacity limits while others were constrained by reverse power or minimum loading
limits. Further, in some instances (e.g., specific feeders) the constraint was due to limits on the
THESL system; other limits were due to constraints on the HONI system.
This section and Section 4 also include a qualitative discussion of any potential physical or
electrical impacts on upgrades that may be required to address local constraints, including
larger DG that cannot be directly installed on THESL distribution lines or stations.
Key Assumptions
Key assumptions employed in the Existing Conditions Case analysis include:
1. Leaside, Hearn and Manby station short circuit capacity improvements and other
upgrades approved by the OEB are not yet undertaken (Phase 1)
18
This higher level approach avoids the need for a feeder-by-feeder analysis and recognizes that THESL’s system is comprised of a
limited number of relatively homogeneous network “topologies.”
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 31
2. To derive maximum limits, all DG is assumed to be installed at the station bus in order
to produce maximum fault current (fault current contribution at this location from PV is
1:5-to-one and from synchronous generation is five-to-one).
3. All feeders serve an even split of residential, commercial, and industrial customers.
4. All DG is assumed to be distributed “optimally” on the THESL system to fully utilize
the available DG connection capacity on each feeder / bus to the limiting constraint type
(NB - actual DG installations are likely to be clustered at the most suitable and costeffective locations, but there is no way of predicting this over the longer term).
5. Mix of assumed installed DG was evaluated for two scenarios per Section 3.6: 100%
inverter-based PV; and, 100% (rotating) synchronous machine.
6. Thermal limits for 13.6 kV and 27.6 kV feeders are assumed to be 10 MW and 20 MW,
respectively.
7. Zero available short circuit capacity at THESL stations served by 115kV lines connected
to either Leaside or Manby stations.
8. DG operates at or near unity power factor and remains fixed (not allowed to provide
reactive power support).
The results presented in the following section represent a theoretical upper limit on the amount
of DG that THESL could connect to its system based on these assumptions given. The reason
the results represent an upper limit is largely due to Assumption 4 – that the DG is optimally
distributed or deployed within THESL system to fully utilize all available DG connection
capacity up to the connection capacity limits. In simple terms, the results present below
should be viewed as the amount of DG that THESL could connect to its system if 1) THESL had
complete control over where on its system the DG connected, and 2) THESL deployed the DG
to utilize all available DG connection capacity. In reality, local capacity constraints caused by
clustering would likely limit the amount of DG that can be installed at any particular location
and the actual DG connection capacity would be somewhat less than presented below.
4.2 DG Connection Capacity Limits: Existing Conditions
This section presents the case study results for the existing system as it was configured as of
January 2011. These initial results are presented under the assumption that all DG is connected
to the station bus; that is, the worst case given that DG fault current contribution declines as the
DG is located further down the length of the feeder.19 Results are presented for THESL’s entire
19
The location of DG on the feeder does not impact limits caused by thermal capacity, reverse power or minimum load constraints.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 32
distribution system and for the 13.8kV and 27.6kV systems separately. However, the limiting
factor for new DG installations may be due to either THESL or HONI constraints. The
following subsections summarizes DG limits for the total system, followed by a description of
the methods and derivation of DG limits assuming optimal deployment (up to the lowest
constraint on each feeder) of 100 percent PV and 100 percent synchronous DG scenarios.
Approach Used to Derive Capacity Limits Given THESL & HONI Constraints
The analysis of DG capacity limits under existing system conditions started with a review of
available feeder thermal capacity for the THESL system. Available feeder thermal capacity
serves as a theoretical upper limit to how much DG can be connected in an unconstrained case,
assuming no voltage regulation criteria violations exist. Realistically, under no circumstances
could the distribution system support DG penetration at or near this theoretical limit. As such,
its use is solely intended to provide a base upon which to begin the analysis. (Illustratively, this
upper limit totals 11,200 MW and appears as the first row in Table 3 in the following
subsection.)
The available short circuit capacity is then calculated at each THESL station bus by identifying
the nominal short circuit capacity limits less any existing DG and FIT capacity. (THESL stations
with limited or zero available capacity appears in Table 1 of Section 2.) The lower of the THESL
thermal capacity limits versus available short circuit capacity, by feeder, represents the net DG
capacity available.
Next, existing short circuit capacity constraints due to HONI constraints are identified for each
THESL station. A detailed review of information provided to THESL by HONI confirms that
short circuit capacity levels at stations served by either Manby or Leaside TS have had their
short circuit capacity limits restricted to zero – HONI has indicated it will allow up to 10 MW of
PV capacity to be installed prior to station upgrades. This restriction further constrains
available capacity, and the net available DG capacity is reduced on feeders where HONI
available short circuit capacity is lower than THESL thermal capacity or short circuit capacity
limits.
Finally, the analysis assesses the impact that THESL minimum load and reverse power
constraints have on the estimate of available DG. Our review reveals that HONI’s minimum
load restriction – HONI restricts DG capacity on many station transformers to no greater than
20
aggregate minimum load each TS bus - further reduces available capacity for DG. If the
20
For THESL’s distribution system, the reverse power flow constraint is equal to the minimum load at the transformer station bus at
25 percent – a conservative estimate for PV which operates during daytime hours.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 33
amount of available DG capacity given HONI or THESL minimum load or reverse power limits
21
is less than thermal capacity or short circuit limits, then it became the limiting factor.
DG Capacity Limits: 13.8kV & 27.6kV Distribution
Existing limits for new DG capacity, derived via the process described in the prior section, are
presented in subsequent sections. First, DG capacity limits based solely on THESL system
constraints are presented (absent consideration of the HONI system), followed by the limits
based solely on the HONI system (before and after the planned upgrades to Leaside TS and
Manby TS and without consideration of the THESL system). On any given feeder, the
constraining factor could arise due to limits on the THESL system or the HONI system. The
combined limits – reflecting the lower of the THESL or HONI constraints across all of the
feeders analyzed – often are lower than limits based solely on a evaluation either of the two
systems (THESL or HONI) in isolation. Finally, the proportion of the constraints due to
limitations on both the THESL and the HONI systems are presented for both synchronous and
inverter DG technologies.
The amount of capacity available for DG was derived for two technology scenarios: 1) 100
percent PV (inverter technology), the 2) 100% synchronous DG. The primary difference in these
two technologies is the much higher fault current produced by synchronous DG - this further
limits the amounts of DG that can be installed on feeders and at stations where DG capacity is
limited either by THESL or HONI short circuit capacity.
DG Capacity Limits on THESL System in Isolation
Table 3 presents study DG capacity limits given THESL constraints. When evaluated on the
basis of THESL limits only, net available capacity is 1,626 MW for PV, 1,065 MW for
22
synchronous.
21
The models Navigant developed to perform the analysis simultaneously compare each of the constraints at the feeder level. The
net available DG capacity for each feeder is equal to the minimum capacity available considering all of the possible constraints
(i.e., it reflects the limiting constraint). The process in the subsection presents these constraints sequentially to facilitate the
discussion of DG limits that appear in charts and illustrations in section that follow. Further, as a rule, the factors that limit DG
capacity often followed the sequence described in this section; for example, for optimally distributed amounts of DG (and
assumed DG size at less than 10 MW), feeder thermal capacity was never the limiting factor for new DG.
22
In this table and those that follow, the maximum available DG capacity is based on the idealized assumption that DG installations
are optimally distributed on all feeders and substations up to the local DG connection capacity limits. The actual amounts will be
lower in many locations where DG is likely to be clustered and not optimally distributed. Further, larger DG (e.g., greater than 10
MW) typically will require dedicated feeders and substation breakers, which will significantly increase the cost of interconnection,
particularly in areas where distribution lines are located underground. In some locations such Windsor TS, spare distribution
station capacity is not available, which will increase interconnection costs.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 34
Table 3 – DG Capacity by V oltage Level and Technology (THESL System Only)
PV
Synchronous
13.8kV
27.6kV
TOTAL
(MW)
13.8kV
27.6kV
TOTAL
(MW)
Feeder Thermal Limit
5,660
5,460
11,240
5,660
5,460
11,240
Short Circuit Capacity
1,540
3,290
4,830
460
990
1,450
Minimum Load
710
1,110
1,820
570
890
1,460
DG Capacity: Minimum of All Constraints
595
1,031
1,626
371
693
1,065
DG Capacity Limit (THESL)
As discussed in Section 3.6, the fault current contribution of a synchronous machine is far
higher, at five times rated current, than that of an inverter-based device. Accordingly, the
distribution system can accommodate less synchronous DG capacity. Also, PV reverse power
limits are higher than synchronous DG due to the assumption that reverse power equal to 125
percent of minimum load can be accommodated (PV output during minimum hours of
minimum load often is zero).
DG Capacity Limits on HONI System in Isolation under Existing Conditions Case
Table 4 presents DG capacity limits given HONI constraints. Results are presented for PV and
synchronous DG. Results indicate the amount of DG capacity that can be installed given HONI
constraints is significantly lower, primarily due to short circuit capacity constraints at Leaside,
Hearn and Manby. Notably, zero synchronous DG and only 10 MW is available for new DG on
the 13.8kV system. In the following section, the impact of HONI station upgrades on total
available DG capacity is presented.
Table 4 – Base Case DG Capacity Limits (HON I System)
PV
Synchronous
13.8kV
27.6kV
TOTAL
(MW)
13.8kV
27.6kV
TOTAL
(MW)
TS Short Circuit Capacity
10
1,663
1,673
0
499
499
Minimum Load
578
601
1,179
578
601
1,179
Thermal Capacity
669
893
1,562
669
893
1,562
DG Capacity: Minimum of All Constraints
10
386
396
0
310
310
DG Capacity Limit (HONI)
4.3 DG Connection Capacity Limits: After Leaside and Manby
Upgrades
This section describes how OEB-approved upgrades at Leaside, Hearn and Manby, once
completed, will increase DG capacity limits, mostly on 13.8kV circuits in downtown Toronto.
Since these upgrades have been approved and under construction (or scheduled for
construction), this scenario is deemed to be the “Base Case” for purposes of determining the
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 35
most likely level of DG that can be installed on THESL’s distribution system. These upgrades
are scheduled to be completed within the next few years, the time when new DG may be
needed to meet provincial RPS targets. Similar to the Existing Conditions Case, the Base Case
studies evaluate DG capacity limits under the assumption of 100 percent PV versus 100 Percent
synchronous generation.
The additional capacity enabled by the HONI station upgrades occurs solely on the 13.8kV
system. Table 5 presents the increase in DG capacity under the assumption the HONI station
upgrades are in service. Hence, results that appear in Table 4 for the 27 kV system remain
unchanged (Table 3 also is unchanged as DG limits are listed from THESL constraints only).
Notably, both PV and synchronous DG capacity limits increase significantly once the station
constraints are addressed: up to 1,100 MW of PV and 370 MW of synchronous DG will be
enabled upon completion over the next few years. The much higher PV limits are due to the
lower short circuit fault contribution for PV compared to synchronous DG.23
Table 5 – DG Capacity Following HON I TS Short Circuit Upgrades (HON I System Only)
PV
Synchronous
13.8kV
27.6kV
TOTAL
(MW)
13.8kV
27.6kV
TOTAL
(MW)
1,248
1,663
2,992
374
499
898
Minimum Load
578
601
1,179
578
601
1,179
Thermal Capacity
669
893
1,562
669
893
1,562
DG Capacity: Minimum of All Constraints
499
386
884
278
310
588
DG Capacity Limit (HONI)
TS Short Circuit Capacity
Total DG Capacity Limits Considering THESL and HONI System
After Leaside, Hearn and Manby upgrades, total system capacity limits will increase to 490 MW
of synchronous DG or 733 MW of PV assuming optimal deployment to fill available capacity on
each feeder. Table 6 presents these totals by voltage, by technology, and reflect the lowest
amount of DG that can be added for each feeder given THESL and HONI constraints,
whichever is lowest.
Table 6 – Total N et DG Capacity Limits
PV
DG Capacity Limit (HONI &
THESL)
Net DG Limits - Lower of THESL & HONI
Constraints
23
Synchronous
13.8kV
27.6kV
TOTAL
(MW)
13.8kV
27.6kV
TOTAL
(MW)
377
356
733
207
283
490
If PV fault contribution ratio was reduced from 1:5 to 1 to 1:1, the available capacity for PV would increase to approximately 1,500
MW on the 13.8kV system.
THESL System Connection Capacity and Enabling Options for Distributed Generation
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DG Limits by System Constraint (THESL or HONI)
For the revised base case, which includes HONI station short circuit upgrades, the relative
contribution of each of the five HONI or THESL constraints to the aggregate system constraints
across all of the THESL feeders evaluated is summarized in Figure 16 and Figure 17. Notably,
of the 870 feeders evaluated, THESL and HONI thermal limits did not appear once as a limiting
factor, an expected result given the assumption of equal allocation of new DG capacity on all
feeders. Further, for PV the greatest constraint is reverse power/minimum load limits at
approximately 71 percent; whereas the largest constraint for synchronous DG is HONI short
circuit capacity at about 41 percent. Each of these results is expected, as synchronous DG
produces much higher fault current than DG. For PV, the primary mitigation option to enable
new DG is to address transformer reverse power constraints; options are presented in the
following subsection.
LimitsConstraints
by Constraint
Figure 16 – ContributionPV
to Capacity
A ggregate System
for PV (After HON I Upgrades)
0% 0%
13%
THESL Feeder Thermal (0%)
16%
THESL Short Circuit
Capacity
HONI Minimum Load
HONI Short Circuit Capacity
71%
HONI Thermal Capacity
(0%)
DG Capacity
by
Figure 17 – ContributionSynchronous
to A ggregate System
ConstraintsLimits
for Synchronous
DG (A fter HON I
Constraint
Upgrades)
0% 0%
THESL Feeder Thermal
(0%)
24%
41%
THESL Short Circuit
Capacity
HONI Minimum Load
HONI Short Circuit
Capacity
35%
HONI Thermal Capacity
(0%)
THESL System Connection Capacity and Enabling Options for Distributed Generation
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5
E NABLING O PTIONS TO I NCREASE DG
C ONNECTION C APACITY
Candidate solutions to address DG penetration limits were identified for each of the constraints
listed in the tables and charts presented in prior sections. These solutions are characterized as
“Enabling Options,” some of which apply to constraints on the THESL system, some of which
apply to the HONI system; and in some instances, may apply both to the THESL and HONI
systems.
The primary categories addressed include:
1. Fault Current Mitigation – options to reduce fault current contribution produced by DG.
Also includes increasing system fault current limits
2. Minimum Load Limits/Reverse Power Limits – options to mitigate reverse power
conditions or to enable reverse power on equipment
3. Thermal Capacity Limits – options to reduce thermal loadings or to avoid overloads
4. Protection Limits and Requirements – upgrades or controls to ensure protections
systems or setting are not compromised
Navigant and THESL conducted an exhaustive review of approaches to mitigate factors that
limit DG capacity, and identified 17 solutions to allow greater DG penetration. These solutions
are characterized as “Enabling Options”. Enabling options include solutions to address
constraints on:
•
THESL’s 13.8kV and 27.6 kV system;
•
HONI stations and lines; and
•
DG technologies (PV and Synchronous DG).
As noted in prior sections, the primary factors or constraints limiting the amount of DG that can
be installed on THESL’s distribution system include:
•
Short circuit capacity (HONI and THESL)
•
Reverse power limits (on HONI transformers)
•
Station thermal capacity limits (HONI and THESL)
•
Feeder thermal capacity limits (THESL)
THESL System Connection Capacity and Enabling Options for Distributed Generation
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A preferred set of enabling options were screened based on:
•
The amount of incremental DG enabled
•
Technical and operational performance
•
Cost (versus other alternatives)
•
Local upgrades will likely be required to mitigate local constraints
Table 7, Table 8 and Table 9 present each of the 17 candidate solutions, with descriptive details,
applications and thresholds, and high-level cost estimates (A more detailed description of these
options appear in Appendix C). As noted, some of these options apply to HONI, THESL, or
both. An explanation of each heading for each column is provided below for each of the four
constraint categories listed above. Certain upgrades apply only to the THESL and HONI
systems, and are designated as such in the following three tables.
Enabling Option – A description of the option intended to address the constraint
Expected Benefits – A qualitative description of the expected benefits; usually in terms of
the additional DG capacity that is enabled. Includes potential disadvantages or trade-offs
High Level Cost Estimate – Estimates of the cost of the solution or option based on
industry data, THESL estimates, or Navigant estimates
Table 7 presents six enabling options that may be suitable choices to mitigate short circuit
capacity constraints. Each of these options generally is suitable for mitigating fault current
contribution for either the THESL or HONI systems.
THESL System Connection Capacity and Enabling Options for Distributed Generation
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Table 7 – Enabling Options: Short Circuit Capacity
Item
#
Enabling Option
1
Current limiting fuses
(CLiP) or Fault Fighter
Fuse
- Very fast detection and interruption of
synchronous DG output
- May cause nuisance tripping for local faults
$50-60k per device, including spare fuse
2
In-Line Reactors
- For installation at feeder termination, no
momentary or sustained interruptions are need to
reduce short circuit currents
- Also avoids nuisance tripping for local faults
$100k per installation or $70k each if
installed directly at the generator,
3
In-Line Reactors at the
TS
- For installation at feeder termination, no
momentary or sustained interruptions are need to
reduce short circuit currents
- Also avoids nuisance tripping for local faults
4
Upgrading equipment
short circuit capacity
- Able to accommodate large amounts of DG &
improved protection coordination
- Extensive planning and construction and may take
several years to implement
Highly dependent on location and could
range from $260k for low voltage
replacements to several million dollars for
TS upgrades
5
Install high impedance
step-up transformers
or generator’s
- Lower short circuit currents than standard
transformers, but less than other options
10-15% incremental cost above standard
transformers
6
Feeder
Reconfiguration (e.g.,
feeder cut and tie)
- Enables greater amount of all types of DG (large
and small)
- Eliminates short circuit current for stations at risk
Up to $250k if major upgrades are
needed. Under $30k where adjacent
feeders are close & can be cut over
Expected Benefits
High-level Cost Estimate
$500k per installation or $70k each if
installed directly at the generator
Similarly, Navigant and THESL identified enabling options that address minimum load or
reverse power constraints as potential solutions for increasing DG capacity limits. Table 8
presents five enabling options considered as potential solutions to mitigate minimum load and
reverse power constraints, virtually all of which occur at the station level. All of the enabling
options listed except Item 10 – Replace TS Transformer, can be used to mitigate THESL and
HONI minimum load limits.
THESL System Connection Capacity and Enabling Options for Distributed Generation
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Table 8 – Enabling Options: M inimum Load/Reverse Power
Item
#
Enabling Option
Expected Benefits
High-level Cost Estimate
7
Dedicated feeder to station not
constrained by minimum load
Enabling greater amounts of large
scale DG
$2-4M per feeder
8
Increasing renewable output
beyond bus minimum ld condition
Very low cost option for enabling
higher amounts of renewable DG
None, other than monitoring feeder loads in
conjunction with renewable output
9
Interruptible DG
Enabling greater amounts of large
scale DG
$25-50k per DG installation, plus
communications systems where applicable
10
Replace TS Transformer
Reducing the minimum load limitations
caused by substation transformers
High cost may be mitigated for stations with
older transformers or devices near end of life
11
Dedicated substation transformer
and feeder unconstrained by
minimum load
Enabling greater amounts of large
scale DG
$6-8M per transformer and feeder
arrangement
Table 9 presents six options for mitigating or addressing constraints or requirements relating to
protection and controls.
Table 9 – Enabling Options: Capacity, Protection & Controls
Item
#
Enabling
Option
Constraint
Addressed
12
Local or mainline
equipment
replacement
Capacity Limits
Enables greater amounts of large
scale DG or DG in aggregate
Up to $25k for local transformation to
or $250K for single-phase line or
cable upgrade
13
Major substation
upgrade
Substation Capacity
Constraints
Enables greater amounts of large
scale DG or DG in aggregate
Costs range from $250k for single
switchgear replacement to over $3M
for major substation upgrades
14
Transfer-tripping
Capacity Issues
Enables greater amounts of large
scale DG without major system
upgrades
Between $50-150k per transfer-trip
scheme
15
Real-time
monitoring
System Planners and
Operations must
monitor DG for high
amounts of small PV
Enables greater amounts of DG
penetration
- For large devices, assume $25k per
for data communication and control
- For smaller DG, $100 per device to
access THESL smart meters
16
Substation Relay
Upgrades
Protection
Enables greater penetration of large
DG; e.g., synchronous devices
$50k per breaker
17
Transmission
Interconnection
Capacity, voltage,
protection or other
Eliminates local capacity and short
circuit capacity limits. Applicable to
large DG (10 – 20 MW each)
Up to $10M
Expected Benefits
High-level Cost Estimate
Specific enabling options listed in the above three tables are evaluated in further detail in
Section 4 to identify the most likely and cost-effective options. Section 4 also presents an
Implementation Plan that enables THESL and DG owners to balance the cost of options versus
the additional DG capacity enabled as part of the interconnection application process.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 41
5.1 Impact of Other Upgrades to the Area Transmission System
The analyses presented herein assume upgrades to Leaside, Hearn and Manby (Stage 2), but
exclude other major transmission upgrades or a possible third source of supply to Toronto. If
and when completed, any of these other upgrades would likely have a significant impact on the
results presented in this report.
THESL System Connection Capacity and Enabling Options for Distributed Generation
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6
C OSTING AND A PPLICATION OF E NABLING
O PTIONS
In this section the enabling options are evaluated with regard to cost versus additional DG
capacity enabled to identify a prudent course of action to be taken to respond to requests for
interconnection to THESL’s distribution system. Because one cannot predict either the location
or amount of DG that will be requested over time, costs are presented for a range of potential
upgrades for both PV and synchronous generation technology. The ability for THESL to select
from one of several candidate enabling options provides a “menu-driven” approach, with
potential costs based on the most appropriate option selected. The approach also recognizes
that specific solutions will be applicable depending on the type and size of DG and nature of the
constraint. Also, the approach does not preclude the very real possibility that additional costs
may be required of applicants for interconnection to address local constraints, or for larger DG
that may require dedicated circuits or substation equipment to enable interconnection with
exceeding distribution capacity limits.
6.1 Enabling Options for DG Capacity
Synchronous DG
For synchronous DG, seven enabling options were selected as the most cost-effective and
suitable solutions to address the two primary limitations for new DG (short circuit capacity and
minimum load/reverse power).
Five options were selected for mitigating short circuit current from synchronous DG under the
“enabled” case, including:
1. Current-limiting devices (CLiP fuses, S&C Fault Fiter fuses);
2. DG-side in-line reactors;
3. TS-side in-line reactors;
4. High impedance step-up transformers and high impedance DG; and,
5. System reconfiguration as it applies to cases in the THESL system.
The applicability and cost of each of the above varies based on technology, size, location and
generator preference. Similarly, Minimum load enabling option costs vary depending on
applicability and solution selected.
The three minimum load-related enabling options evaluated include,
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 43
1. Interruptible DG;
2. TS transformer upgrade/replacement; and,
3. System reconfiguration.
The unit costs ($/kW of DG enabled) to increase synchronous DG capacity limits based on the
seven options and the range of costs associated with these options are presented in Figure 18.
Notably, the range in cost to enable synchronous DG varies significantly, underscoring the
location-specific factors that determine the cost of individual applications for interconnection.
Figure 18 – Enabling Options and Cost for Synchronous DG
Enabling Options Required
CLiP fuses
S&C Fault Fiter fuses
Inline Reactors
High Impendence Step-up
Transformer
System Reconfiguration
Synchronous DG
connection request
on a constrained
feeder or TS
If SC Constraint
Increase DG connection
capacity by selecting from
SC mitigating options
$32 - 197/kW
If Minimum Load Constraint
Interruptible DG
Increase DG connection
capacity by selecting from
min load options
“Enable”
synchronous DG
connection
request
$26 - 202/kW
$26 - 202/kW
Transformer Replacement
System Reconfiguration
• Costing provided does not reflect that in specific cases:
— Short circuit AND minimum load constraints may need to be addressed,
requiring both types of enabling options
— Additional interconnection costs will likely result pending any local
upgrade requirements. Specific local upgrade requirements could also
be uncovered during generator interconnection process
Further, the costs ranges provided above do not reflect case-specific costs that may be needed to
interconnect DG. For example, costs may increase due to,
Short circuit and minimum load constraints may need to be addressed, requiring both
types of enabling options, which could substantially increase costs. However, the second
set of costs would not be needed until the increase in capacity achieved by the first
enabling option.
Additional interconnection costs will likely result pending any local upgrade
requirements. Specific local upgrade requirements could also be uncovered during
generator interconnection process.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 44
Clustering of DG to particular feeders or stations may reduce total DG capacity that can be
installed without upgrades. Given the likelihood that DG will be clustered based on
locality and opportunities (e.g., industries most suitable for synchronous DG for CHP and
rooftop orientation for PV), capacity limits likely will be reached in pockets within the City
and multiple enabling options may need to be deployed.
Photovoltaic (PV)
For PV, solutions are more straightforward as inverter-based technologies do not encounter the
same level of limitations and constraints as those associated with rotating machines such as
synchronous DG. The enabling options for PV include:
Upgrading TS’ to allow up to 25% reverse power flow (25 to 50 MVA)
Reverse power flow lesser of 25% or available short circuit capacity
24
Station transformer upgrades costs varied by station size, quantified below:
$5 million for 100 MVA
$10 million for 200 MVA
$15 million for 400 MVA
Figure 19 presents the ranges of costs applicable to PV. Although fewer options apply to
mitigate capacity constraints, the range in cost to interconnect new DG, where applicable, varies
considerably at different locations on the system.
24
Inline reactors were initially considered to mitigate short circuit current limits for PV; however, reverse power flow at HONI TS’
is the dominant constraint (reverse power limits are reached before short circuits).
THESL System Connection Capacity and Enabling Options for Distributed Generation
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Figure 19 - Enabling Options and Cost for PV
Enabling Options Required
PV connection
request on a
constrained feeder
or TS
Increase PV
penetration up to
125% of min TS load
$10/kW
SC limits
exceeded
?
[Yes]
Install TS-side inline
reactors (suppress
short circuit current)
$500,000 per device
or up to $54/kW
[No]
Transformer Station
upgrades required
(25% Reverse Power
Flow)
$202/kW
“Enable” PV DG
connection
request
$10 - 256/kW
• Costing provided does not reflect that:
— In specific cases additional interconnection costs will likely
result pending any local upgrade requirements
— Specific local upgrade requirements could also be uncovered
during generator interconnection process
The costs ranges provided above do not reflect case-specific costs that may be needed to
interconnect DG. For example, costs may increase due to the following:
Short circuit and minimum load constraints may need to be addressed, requiring both
types of enabling options, which could substantially increase costs. However, the second
set of costs would not be needed until the increase in capacity achieved by the first
enabling option.
Additional interconnection costs will likely result pending any local upgrade
requirements. Specific local upgrade requirements could also be uncovered during
generator interconnection process.
Clustering of DG to particular feeders or stations may require multiple enabling options to
be deployed.
6.2 Prudent Approach to Enabling New DG Capacity
HONI bases maximum PV capacity on minimum TS loading. Navigant believes this constraint
is overly conservative and recommends allowing PV up to 125% of minimum load (which is
still conservative). For example, a snapshot of daily load versus PV output profiles (Figure 20)
illustrate the coincidence of PV output with maximum hourly loads for large DG (> 20MW) for
the month of April 2010 – confirming PV output will get closest to hourly bus load during
shoulder periods on sunny (or high insolation) days with moderate temperatures.
THESL System Connection Capacity and Enabling Options for Distributed Generation
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Figure 20 – PV Output versus Load Profiles (Bathurst Station)
60
Maximum Bus Load in 2010 =
58 MW
Hourly Load/Output (MW)
50
Hourly Load (Bus Y Bathurst TS)
Hourly Output (PV DG)
40
30
20
Minimum Bus Load in 2010 =
14 MW
10
0
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
Figure 21 illustrates the significant difference between PV capacity versus actual minimum load
on a percentage basis, underscoring the margin between current HONI limits and calculated
limits for the Bathurst “Y” bus (reverse power does not occur until PV output is approximately
200 percent of Y-Bus minimum load).
Figure 21 - N umber of Reverse Flow Hours vs. PV Penetration (as % of M inimum Load)
200
Current HONI Limit
175
Reverse Flow Hours / Year
Proposed Limit = 125% of Min. Load
150
Calculated Limit for
Bathurst Y Bus
125
100
75
50
Incremental PV DG
given coincidence of
loading and PV output
25
0
100%
125%
150%
175%
200%
225%
250%
PV Capacity as % of Minimum Load
275%
300%
THESL System Connection Capacity and Enabling Options for Distributed Generation
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A duration curve showing the bus loading over all hours of 2010 sorted from highest to lowest
with the corresponding PV output for each hourly bus load based on the PV capacity limit of
125% of minimum load is shown in Figure 22. As shown, at no point during the year is PV
output greater than the bus loading.
Figure 22 – Duration Curve of Bus Loading and Coincident PV Output
(PV Capacity = 125% of M inimum Load)
6.3 Cost Impact and Cost Recovery of Enabling Options
THESL’s DG Requirements provide practical guidance and an equitable approach of cost
recovery for renewable generation enabling options per the OEB’s Distribution System Code
(DSC). Specifically:
THESL DG Requirements differentiate between expansions and enhancements
THESL will pay up to $90,000 / MW for expansions and entire cost of enhancements
necessary to enable renewable generation connection
Some enabling options are expansions, others are enhancements and others would likely
be considered enhancements, but are not specifically listed in the DSC
To eliminate uncertainty related to cost recovery of enabling options, Navigant suggests that
THESL seek Board concurrence with the following statement:
If an enabling option for renewable generation is NOT an expansion, then it will be
deemed to be an enhancement (i.e., enhancement list is open-ended)
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 48
As per the DSC, the costs of an enabling option for non-renewable generation (e.g., synchronous
CHP DG), regardless of whether it is an expansion or an enhancement, shall be recovered from
the generator requesting connection. Navigant is aware of significant interest in CHP in
Toronto and elsewhere. Given this interest, the OEB could consider establishing policy with
respect to specific types of non-renewable generation (e.g., those eligible for the OPA’s CHP IV,
CHPSOP and ERSOP generation procurements) that parallels the treatment for renewable
generation but any such change in policy would be outside THESL’s mandate.
It is also important to note that some enabling options can only be undertaken by HONI. Cost
recovery for these options would be subject to the OEB’s Transmission System Code (TSC) and
HONI’s policies reflecting the TSC. These options and policies are outside THESL’s mandate,
but THESL will work with HONI to identify the lowest cost enabling option for each generation
connection request.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 49
7
C ONCLUSIONS
Navigant’s study of DG connection capacity limits on THESL’s 13.8kV and 27.6kV distribution
system has identified several feeders and busses with significant DG connection capacity
available, whereas some feeders and busses were found to have very limited or no connection
capacity. In most areas with limited or no capacity, the current HONI transmission system is
the limiting constraint to new DG installations. THESL equipment is the limiting constraint for
only a few feeders and busses.
Navigant’s specific findings with respect to THESL’s DG connection capacity include:
Currently, new DG in downtown Toronto and the eastern section of the City is limited to
10 MW for PV (and zero for synchronous DG25) due to short circuit capacity limits at
HONI’s Leaside, Hearn and Manby stations, and transmission limits on the 230kV delivery
system East to Cherrywood station in Pickering,
OEB-approved upgrades to the HONI system over the next few years will increase the DG
connection capacity on THESL’s 13.8kV system to 377 MW for PV or 207 MW for
synchronous DG, and
Without considering the transmission system to which it is connected, THESL’s 27.6kV
system has connection capacity for up to 833 MW of PV or 693 MW of synchronous DG.
Considering the transmission system and HONI constraints, the connection capacity is
reduced to 356 MW for PV or 283 MW of synchronous DG.
Navigant and THESL jointly assessed the viability of the various enabling options as identified
by Navigant for potential inclusion in THESL’s GEA Plan. As part of this assessment, Navigant
and THESL estimated the likely range of costs and unit costs ($ / kW of DG enabled) for such
upgrades based on THESL’s system characteristics. Since there are several different types of
constraints, varying system configurations across THESL’s service territory and non-uniform
geographic and temporal distribution of DG connection requests, there is no single “silver
bullet” or option to address all of THESL’s DG connection capacity constraints.
In general, however, where mitigation and upgrades are needed, DG connection capacity can be
increased at a unit cost well below the installed cost of DG capacity. For feeders that are
constrained, the analysis undertaken by Navigant and THESL indicates that additional DG
25
Inverter-based PV generation has different electrical characteristics than synchronous-based generation (such as for a mediumsized CHP installation), particularly with respect to fault current contribution. Given these differences, the available DG
connection capacity will depend on the type of generation to be connected. For simplicity Navigant refers to the connection
capacity for PV or for synchronous DG, whereas THESL is likely to get connection requests for a combination of generation types
and the connection capacity would likely fall between the values given for PV and synchronous DG.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 50
connection capacity can be installed through a variety of enabling options at an expected cost
less than $300/kW of DG enabled with the following caveats:
Large DG (greater than 10 MW) may require dedicated feeders and station positions that
could cost more than $300/kW of DG enabled,
Local upgrades may still be required to address capacity and voltage constraints, and
Some enabling options require changes or upgrades to HONI system; notably, some
upgrades include replacement of HONI equipment that is 50 or more years old.
THESL’s GEA plan will incorporate the viable options into several local upgrade plans that
reflect local system constraints and the best available information on current and forecast DG
connection requirements on THESL’s stations and feeders. Together, the upgrade plans
proposed in THESL’s GEA Plan and HONI’s local transmission system upgrades will
significantly increase THESL’s DG connection capacity.
Even with these substantial upgrades, new DG connection applications outside THESL’s
current forecast may still be subject to constraints on certain feeders or buses. It is expected that
many of these constraints can be addressed through the application per THESL’s DG
requirements and cost recovery policy of the enabling options identified within this report.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 51
A PPENDIX A: C ASE S TUDY D ESCRIPTIONS
The following case studies were analyzed to assess DG capacity limits and enabling options for
THESL’s downtown 13.8kV and the27.6kV system located outside of the downtown area.
Case 1 - Long 27.6 kV Feeder
The long 27.6kV feeder is assumed to be approximately five to six kilometers in length.
This is one of the more common feeder types on THESL’s distribution system,
representing _ percent of the total population of feeders. For simulation purposes,
THESL’s NY85M1 feeder was selected for Case 1.
Case 2 - Short 27.6 kV Feeder
The short 27.6kV feeder is assumed to be approximately two to four kilometers in length.
The short 27.6kV feeder represents _ percent of the total population of feeders. For
simulation purposes, THESL’s NY85M1 feeder was selected for Case 2, as it exhibits
similar performance as the Case 1 27.6kV feeder.
Case 3 - Long 13.8 kV Feeder
The long 13.8kV feeder is assumed to be approximately three to four kilometers in length.
This is one of the more common feeder types on THESL’s downtown distribution system,
representing _ percent of the total population of feeders. For simulation purposes, THESL’s
George & Duke A19GD feeder was selected for Case 3.
Case 4 - Short 13.8 kV Feeder
The short 13.8kV feeder is assumed to be approximately three to four kilometers in length.
This also is one of the more common feeder types on THESL’s downtown distribution
system, representing _ percent of the total population of feeders. For simulation purposes,
THESL’s George & Duke A19GD feeder also was selected for Case 3, as it exhibits similar
performance as the Case 3 13.8kV feeder.
Case 5 – Pilot Wire
The pilot wire arrangement includes multiple 13.8kV feeders operating in parallel (the same
arrangement is possible for 27.6kV feeders), thereby increasing the effective capacity of
combination of lines. A pilot wire protection scheme is necessary to ensure only faulted line
sections trip when a line or cable fault occurs. This provides for greater redundancy and
reliability. The pilot wire scheme at THESL’s Terauley station was selected for simulation
analysis. The pilot wire arrangement is used as needed to accommodate large loads, and
represents _ percent of the total system
THESL System Connection Capacity and Enabling Options for Distributed Generation
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Case 6 – Pilot Wire
Case 6 is a variation of the Case 6 Pilot Wire Scheme.
Case 7 - Bathurst Tie Point (Extended Feeder)
This case includes the transfer of load from an adjacent feeder to another via closure of an
open tie, typically performed for outage events or maintenance. This is uncommon, but
may apply to many feeders on THESL’s system. The significance of this case is that a higher
amount of DG may be fed into a feeder breaker, thereby increasingly the likelihood of short
circuit violations.
Case 8 - Terauley/G&D Tie Point (Extended Feeder)
Case 8 is a variation of Case 7.
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A PPENDIX B : P OWER F LOW S IMULATION A NALYSIS
Appendix B presents THESL’s power flow simulation analysis of Distributed Generation (DG)
penetration scenarios and their impact on the distribution grid. These studies were conducted
to support the results and findings presented throughout this report.
The THESL distribution grid consists of 27.6 kV, 13.8 kV, and 4.16 kV looped-radial and pilotwire feeders. Hence, the feeders chosen for this study (listed below) provide a representative
sample of feeders found on THESL’s distribution grid. These feeders are:
a. 27.6 kV feeder - NY85M1 (Bathurst TS)
b. 13.8 kV feeder - A19GD, A20GD, A310GD (George & Duke TS)
c. 13.8 kV Pilot wire feeders – A23A, A25A, A27A (Terauley TS)
Both synchronous-type and PV-type DG were connected on these feeders at various points
depending upon the feeder types. As an example, the DGs were connected at three points along
the 27.6 kV feeders (close to the bus, end and midpoint of the feeder) while the pilot-wire feeder
only saw DGs connected at the endpoint.
This next section describes the methodology used to conduct this study. The impacts of these
DGs on the distribution grid were evaluated in terms of:
a.
Feeder short circuit profile
b.
Maximum DG permissible given system short circuit constraints (760 MVA– 27.6
kV, 475 MVA – 13.8 kV)
c.
Voltage profile along the feeder
d.
Ampacity profile of load along the feeder
Unless otherwise stated, the results of this study are based on existing civil and electrical
infrastructure.
Subsequent sections of this appendix report present the results of the case studies and the
impact of connecting these DGs to the THESL’s distribution system. Feeder parameters and
data used in the studies also are provided. CYMDIST software platform is used to conduct the
analysis.
THESL System Connection Capacity and Enabling Options for Distributed Generation
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B.1 Background and Methodology
For each of the representative feeders, the following DG technologies are connected along
various points of the feeder:
a. Synchronous-type DGs (6 MW, 12 MW, 20.9 MW)
b. PV-type DGs (500 kW, 2 MW, 5 MW)
For each scenario, the short circuit profile along with the voltage and ampacity profile are
calculated. Further, for each simulation, feeders’ loads are also considered. Based on the feeder
loading profile, the minimum and maximum load of feeder are connected to the feeder as a spot
or a distributed load depending upon the feeder type. The net feeder load flow at the station
breaker is important in assessing the thermal capacity of the feeder and bus. This load assists in
calculating cable ampacity (net power export as result of minimum load). However, the load is
assumed to have no impact on the short circuit profile.
Key study assumptions include:
a. Transformer reactance is assumed to be at 6.25%
b. For PV-type DGs, the fault contribution is assumed at 110% of rated current
c. Power factor of 90% is assumed for load conversion (kVA to kW)
d. For fault current simulations, contributions from both induction and synchronous
motors are factored in the analysis
e. Real power flow direction from bus to the end of feeder is defined as negative
f.
Real power flow direction from end of the feeder to the bus is defined as positive
The case studies are organized as follows:
a. Case Study title - Feeder type (27.6 kV)
1. DG scenario (no DGs/synchronous generators/ PVs/mixed)
1.1. DGs connected at the end of the feeder
1.2. DGs connected at the middle of the feeder
1.3. DGs connected close to the bus
b. Case Study title - Feeder type (13.8 kV/ Pilot-wire)
1. DG scenario (no DGs/synchronous generators/ PVs)
2.1. DGs connected at the end of the feeder (Short Circuit Current, Voltage and
ampacity
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 55
The existing calculations used the nominal voltage values; i.e. 27.6 kV and 13.8 kV instead of the
normal operating voltages (which tend to be up to 5% greater). In addition, the feeder length
and the dominant cable types of the respective feeders are:
a. 27.6 kV – 5.8km (556 Al Overhead bare, 1000 kcmil TRXLPE Underground cable)
b. 13.8 kV – 1.2 km (500 TRXLPE Underground cable)
c. Pilot-wire – 737m (500 PILC H type Underground cable)
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 56
B.2 Short Circuit Analysis
The results of THESL’s CYME short circuit analyses are displayed below for each of the DG
connection scenarios described above and in the main body of this report. It includes fault
circuit levels for DG installed at three locations on representative distribution feeders: (1) at the
substation bus; (2) middles of the feeder; and (3) end of the feeder. Results indicate that fault
current contribution from DG drops significantly as DG location is further from the substation
bus. Case study results presented in this report are based on the assumption that all DG is
installed at the substation bus. Thus, available DG capacity may be higher on feeders where DG
is installed further from the base and where short circuit capacity limits is the primary
constraint.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 57
B.3 Voltage Performance
In addition to short circuit data, the CYME model also produced feeder voltage profiles for DG
installed at the station bus, middle and the end of each representative feeder. The following
table summarizes results for the end of feeder installations, as these represent the worst case
scenarios. In addition, the voltages include minimum and maximum as derived by CYME
simulation studies, measured at the end of each feeder. Results indicate voltage performance
for all DG case and technologies is robust, as variances are well within limits (+/- 5 percent from
nominal).
CY M E Simulation Study Results - V oltage Profiles
DG Type
Feeder Voltage
Maximum
Load (PU
Voltage
Minimum
Load (PU
Voltage
Base Case
No DG
27.6kV
1.000
1.000
6.0 MW
Synch
27.6kV
0.996
1.001
20.9 MW
Synch
27.6kV
1.007
1.013
2.0 MW
Synch
27.6kV
0.991
0.997
5.5 MW
Synch
27.6kV
0.992
0.998
PV, Synch
27.6kV
0.996
1.001
PV, Synch
27.6kV
1.008
1.014
Base Case
No DG
13.8kV
0.997
0.999
2 MW
Synch
13.8kV
0.998
1.000
9.75 MW
Synch
13.8kV
1.001
1.003
PV
13.8kV
1.000
1.000
Synch
13.8kV
1.001
1.003
Pilot Wire
13.8kV
0.998
1.000
Pilot Wire
13.8kV
0.999
1.001
No DG
4.16kV
1.000
1.000
PV, Synch
4.16kV
1.000
1.000
DG Size (MW)
2 MW PV
6 MW Synch
5.5 MW PV
20.9 MW Synch
2 MW
9.75 MW
2.0 MW PV
2.0 MW PV
18.0 MW Synch
Base Case
0.5 MW PV
0.5 MW Synch
These results indicate that THESL’s short distribution feeders in the downtown area (13.8 kV &
4.16 kV) and higher voltage (27 kV) lines in the “horseshoe” area each contribute to stiff
voltages throughout the service territory. In all cases, voltages varied by no more than two
percent, regardless of DG location. For some feeder types, voltages were relatively unchanged.
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 58
Accordingly, voltage performance is not a limiting factor or primary constraint for DG capacity.
However, voltage performance should be studied for large DG or higher penetration scenarios,
as individual projects may create unacceptable voltage rise under light load or drop under
heavy load. A parametric analysis similar to the results portrayed in the following diagram
would be appropriate. In the example that follows, result indicate very minor shifts in voltage –
less than 1 percent for all cases - for DG installed on a 27.6kV feeder.
27.6 kV feeder - V oltage Profile - PV -DGs Connected at End of Feeder
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 59
A PPENDIX C: E NABLING O PTION D ETAILS
Provided below are detailed descriptions and costs of each of the 17 Enabling Options
evaluated in this study. Table heading descriptions presents each of the candidate solutions,
with descriptive details, applications and thresholds, and high-level costs. As noted, some of
these options apply to HONI, THESL, or both systems.
Constraint Addressed – Corresponds to one of the four constraint categories listed above.
Applies to both THESL and HONI systems
Enabling Option – A high-level title or description of the option intended to address the
constraint
Description – Provides specific details on the type of mitigation or solution proposed,
including location on the THESL or HONI system
Application – Describes the conditions under which the enabling option applies, including
the type of DG where the option applies (PV versus synchronous)
Benefits – A qualitative description of the expected benefits; usually in terms of the
additional DG capacity that is enabled. Includes potential disadvantages or trade-offs
High-Level Cost – Estimates of the cost of the solution or option based on industry data,
THESL estimates, or Navigant estimates
THESL System Connection Capacity and Enabling Options for Distributed Generation
Page 60
APPENDIX E: POTENTIAL RENEWABLE GENERATION ENABLING OPTIONS
THESL has various options to enable proposed renewable energy generations connected to its
distribution system where constraints exist. A list of options and methods that may be
implemented for each activity and that addresses various constraints and shortfalls are
discussed below. The enabling options are based upon a mix of solar PV inverter based (90%)
capacity compared to synchronous engines which represent approximately 10% of the
nameplate capacity.
Fault current mitigation activities to overcome HONI transmission system short circuit
constraints and THESL distribution system short circuit constraints, for both large and small
generators. The activities are of different options and are:
Installation of fault current limiting devices - Clip Fuse or S&C Fault Fiter® Fuse;
Installation of line reactors;
Installation of high impedance step-up transformer and high impedance DG. If standard
impedance 5%, increase to 10%; and
In addition, THESL distribution system short circuit constraints may be remedied by
distribution system configuration.
Minimum load mitigation activities with respect to bus loads of HONI TS and THESL TS & MS
are:
Installation of interruptible DGs;
Replacement of transformer; and
System Re-Configuration.
Capacity Issues- Increased Fault Withstand Rating of Equipment, particularly thermal capacity,
of THESL distribution system may be overcome by the options,
Replace or upgrade equipment that will exceed thermal ratings due to DG output;
Install transfer tripping scheme for DG risk; and
Replace local or mainline equipment such as local transformers or lines for localized
problems, or construction of dedicated feeders for main trunk line feeder overload.
DG Status Monitoring for system operation and the activities associate with it is installation of
smart grid monitoring communication, data collection and tracking systems.
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Implementing Advanced Protection and controls by upgrading substation relays and meeting
the system requirements via installation of transfer trip.
Replacing older station and substation breaker relays with programmable devices equipped
with DG protection functionality.
Upgrading HONI equipment for short circuit capacity is a long term project and already in
queue as deferred upgrades. These upgrades are performed by HONI with limited input from
THESL.
Large scale projects that may address and resolve many issues and most importantly the major
short circuit constraints of both HONI and THESL and/or the minimum load and capacity
issues. These projects will be carried out after carefully reviewing the enabling options of all the
above activities.
Express feeder for DG only dedicated feeder for specific generators.
Dedicated feeder to other substation unconstrained by issues re-routing arrangements.
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Fast Tripping Protection Scheme
Fast Tripping Scheme:
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APPENDIX F: ENERGY STORAGE (> 6 HOURS CAPACITY)
The first phase of deployment would commence in 2012 and involve a downtown site such as
Dufferin TS as sites to support renewable generation, manage peak power prices and provide
contingency mitigation. In future years, additional stations will be examined and projects
planned to ensure all stations achieve the same level of risk management and service reliability
through energy storage. Various benefits are associated with energy storage systems providing
over six hours capacity.
Accommodate Renewables
Energy storage systems can help manage intermittent renewable sources and support multiple
renewable projects in the station/feeder service area. Such systems can minimize the need for
other firm capacity to replace renewables and helps prevent dumping of energy during low
demand periods in the market.
Contingency
The distribution system in the former city of Toronto is based on a radial design. This design
does not provide ties between feeders originating from other neighbouring stations, and
therefore does not provide back-up during partial and complete station failure. In the event of a
station contingency, such a design would result in significant impacts to customer services.
During the station outage due to fire/flood at Dufferin TS on 15 January, 2009, over 34,000
customers were affected up to 24 hours. Similarly, on 23 January, 2005, over 3,500 customers
were affected for up to 10 hours because of flooding at Terauley TS. Although the outage costs
associated with such an interruption of services has been not been quantified within the
industry, the associated loss of business and productivity is estimated at $10M per occurrence.
Although a major distribution infrastructure plan to allow load transfer capability between
multiple neighbouring stations is being put in place, an alternative which provides support
until the distribution infrastructure can be implemented is important within the former city of
Toronto area. An energy storage system in the form of commercially available battery storage
can provide near-term support. This approach provides near term flexibility in dealing with
outages and may reduce the multiple ties from neighbouring stations, given that energy storage
can be deployed in a relatively short time to address system needs.
Voltage Fluctuations and Power Transients
The demands for electricity from consumers and industry, particularly in the downtown
Toronto area, are in constant change – mostly increasing over the years, with the result that the
supply voltage at THESL’s distribution system is prone to fluctuates due to such demand
changes. Minor variations in load are automatically smoothed by slight variations in the
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voltage available across the system. But for a big load relative to the capacity of a distribution
station, a load change would cause power transients that would deteriorate power quality
affecting all customers fed by the same distribution system. Electric energy storage installed at
the distribution station level would serve as a ‚reserve‛ to reduce such power transients within
the distribution system.
Peak loads
A number of the municipal stations located in the downtown area are operating close to its
capacity limits during summer and winter peaks, and conventional facility upgrades are
considered a necessity to maintain customer service. With battery storage, such upgrades,
which normally would involves longer lead time due to land/easement purchase and permits
requirements, can be deferred or avoided, and with its short lead time, energy storage can be
incorporated much sooner. The use of energy storage can provide flexibility and substantially
enhance THESL’s overall planning of the distribution system.
Managing Peak Pricing
Energy storage can be effectively utilized to store low-cost, off-peak energy during the night
and discharging the energy during the day at high prices. This has a multiplier effect whereby
the entire market volume is influenced when peak hours are tempered by even a small capacity
of energy storage. In other words, the entire market volume benefits from energy storage
dispatched during on-peak periods because of the nature of the price duration curve. It is also
useful that energy storage make use of low-cost energy to charge the system during off-peak
periods when the market pricing may be approaching negative price dynamics given the low
manoeuvrability of base load nuclear generation.
Lowered Emissions
Energy storage can be charged with low-emission sources and discharged to displace peaking
gas-fired resources or imported coal-fired resources which lowers emissions during periods of
peak demand.
Ancillary Services
Energy storage can be used to provide capacity spinning reserve and other ancillary market
services to provide financial benefits.
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ALTERNATIVES
A number of alternatives exist in mitigating partial and complete station outages for
distribution systems based on radial design where interties of feeders from other neighbouring
station do not exist. These alternatives include
•
on-site distributed generation fuelled by natural gas or diesel,
•
new distribution feeders from other stations,
•
energy storage using battery systems.
Distributed Generation
Distributed generation systems are small-scale power generation technologies (1MW to 10MW)
used to provide an alternative to address peak load without a traditional centralized power
generation system. Their capacity and fuel source must be firm, not intermittent. It is another
approach to address power constraint in a downtown distribution station. It reduces the
amount of energy lost in transmitting electricity because the electricity is generated very near
where it is used. This also reduces the size and number of power lines that must be
constructed. Commercially available distributed generation technology includes internal
combustion reciprocating engines, combustion turbines and micro-turbines. For grid support,
reciprocating engines are most suitable for the size ranging from 1MW to 10MW.
The advantage of using distributed generation for peaking support at stations is that firm
capacity can be provided with reasonable capital investment. Corresponding disadvantages
include local air/noise emissions, requirements for liquid/gas fuel infrastructure, longer
permit/approvals process and interconnection limits in the distribution system and
transmission system.
New Distribution Feeders
The most reliable and economic way to address power constraint in distribution station is to
upgrade the distribution system including enhancing distribution feeders to bring in more
capacity; however this may not be most favourable way to solve the problem due to the
physical complexity in downtown core area. It usually takes much more time to implement
distribution feeders compared to distributed generation and energy storage approaches.
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Comparison of Energy Storage to other Options
Energy storage systems are contrasted with the alternatives in the following table:
Criteria
Alternatives for 4MW Capacity
On-site Distributed
Generation (Nat. Gas)
New Distribution
Feeder
Battery Energy
Storage
Space Requirement
12 m x 40 m
Location specific
25 m x 35 m
Environmental Impact
– Air Emission & Noise
GHG of 13 ton (Nat
Gas)& noise
contribution at site
No GHG generated
& no noise
contribution
No GHG generated
& no noise
contribution
Fault/Short Circuit
Contributions to Grid
Potential contribution
of 20MVA fault level to
the grid
No fault
contribution
expected
Only small (4MVA)
contribution of fault
level to the grid
Construction Schedule
12 – 18 Months
12 – 36 Months
<12 months
Recommended Solution
As indicated above, there are a number of alternatives that can provide effective solutions to the
system need during a partial or complete station contingency in the downtown area. In terms
of rapid implementation, minimal environmental (air & noise) impacts and fault contributions
to the grid, it is clear that distributed energy storage is the most suitable solution. Such a
system can provide emergency power of up to six hours in an urban environment. An
interconnection point will be incorporated to accommodate mobile emergency generators for
sustained operation beyond six hours in extreme events such as ice storms or regional grid
failure.
The space requirement for distributed energy storage is more localized to where it is sited when
compared to the alternative of a new distributed feeder where the selected routing of the feeder
could potentially impact a wider area and hence longer lead time due to permitting
requirements. Its modular design is scalable to provide output in accordance with system
needs.
The value of energy storage is particularly attractive in situations where a TS is operating very
close to its capacity limit and yet projected load growths is not high enough to justify a
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conventional station upgrade right away, or a conventional station upgrade might not be
feasible due to land and permit issues. In contrast, energy storage can be deployed in a
relatively short time to address needs. Once a conventional distribution feeder/station upgrade
is in place, the energy storage system can be relocated somewhere else. Such flexibility over the
15-20 year lifecycle is very beneficial.
There are a few battery-based storage technologies available commercially, including;
•
Sodium Sulphur Battery (NaS)
•
Lithium-ion Battery (Li-ion)
•
Zinc Bromine Battery (ZnBr)
•
Lead Acid Battery (L/A)
Based on a number of studies by the U.S. Department of Energy (DOE) during 2006 to 2010
within the DOE Energy Storage Systems Program, the NaS system scores highest in terms of:
Power Rating, Energy Efficiency, Discharge Duration, Commercial Maturity, Cycle Life,
Relocation Cost, Maintenance Cost and Supplier Financial Strength.
COMPARATIVE COSTS
Component
On-site Distributed
Generation (Nat.
Gas)
New Distribution
Feeder
Battery Energy
Storage (NaS)
Civil Work
$4M
$2M
$2M
Electrical Work
$4M
$11.5M
$2M
Equipment
$8M
$2M
$26M
Total for 4 MW x 6 hr
$16M
$15.5M
$30M
Construction estimates, based on current market costs. [New on-site distributed generation @
$2/MW equipment; New 15 km 9-duct bank feeder @ $0.7M/km plus cabling @$0.2M/km for
400A feeder plus switchgear equipment; New NaS battery storage equipment plus civil/elect.]
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SCHEDULE
The 2MW / six-hour energy storage scope of work is planned for 2012 implementation, subject
to design, procurement and permit/approvals process.
BENEFITS
Energy storage can also help to improve reliability and utilization of an existing distribution
system without replacing it. The energy storage solution has the following benefits:
•
Provides stabilization of voltage sags, surges, harmonics and other transients;
Provides firm capacity of six hours initial emergency power;
Provides interconnection point for mobile emergency generators beyond initial 6 hours;
Provides electrical supply during maintenance periods;
Provides at least ten-year service life, based on 150 charge/discharge cycles per year;
Provides ability to moderate on/off peak prices; and
Rapid installation and simplified permits/approvals (no air/noise emissions are
involved).
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APPENDIX G: DIRECT BENEFITS CALCULATION
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APPENDIX H: GENERATION CONNECTION PROCESS & FEES
Renewable Generation Connection Process
In general, renewable energy source generation projects under the FIT program implemented
by the OPA are presently connected when there is connection availability. Connection
availability is checked through a pre-assessment before the customer submits an application to
the OPA. When the application receives a conditional offer from the OPA, at the request of the
customer, a Connection Impact Assessment (CIA) is performed. A fee is levied from the
customer for performing the CIA. Until December 8, 2010, CIA was applicable to projects of the
following:
FIT Capacity Allocation Exempt (CAE) projects, greater than 10kW and up to 250 kW,
when connected to the distribution system less than 15 kV;
FIT Capacity Allocation Exempt projects, 10kW and up to 500 kW, when connected to
the distribution system greater than 15 kV; and
FIT projects larger than specified in (i) and (ii).
Since December 8, 2010 CIA is applicable to MicroFIT projects and all FIT projects. The CIA fees
are levied under demand recoverable cost for the services provided. Two different flat rates are
charged for the MicroFIT and FIT CAE projects. For the large projects the CIA fees vary
depending on the complexity of the project and the details that need to be reviewed and
assessed for connection availability.
In addition, there may be a requirement for a CIA by the transmitter, HONI, or a utility with a
shared feeder and a system impact assessment (SIA) by the IESO. These fees are also demand
recoverable, but transacted via THESL from the customer to the respective stakeholder.
When the CIA is satisfactory, the renewable energy source project becomes eligible for
connection. THESL prepares a connection cost assessment (CCA), i.e., an estimate of
connection, and submits to the customer with an offer to connect (OTC). The CCA/OTC fee is
levied from the customer before connection. This is conditional offer either for a rebate by
THESL to the customer or additional payment by the customer to THESL, depending on the
actual cost.
When a FIT project is assessed that requires expansion of the existing distribution system, the
customer pays a capital contribution towards the expansion costs in excess of $90/kW, in
addition to the connection cost. The capital contribution is shared amongst other FIT customers
who are connected to the same expansion in the future as per OEB guidelines and DSC rules.
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Unfortunately, many FIT projects are unable to get connected due to the constraints in the
transmission system and THESL distribution system as described in Section 2. However, these
may be achieved under the renewable enabling cost provisions as per OEB guidelines and DSC
rules.
When renewable enabling improvements are made for connecting FIT projects, any work or
part of the work that is recognized as connection or expansion will be cost estimated
accordingly and levied from the customer as shown below.
The projects and activities described in this section are of demand recoverable, where capital
costs recoverable from customer and enabling improvements by LDC. The following are
activities that will be involved in renewable generation connection, based on forecast
interconnection requests and the Demand Recoverable component from MicroFIT and FIT
projects has been projected. The fees are collected from customers at the assessment stage and
later during the connection process and agreement. For MicroFIT projects the pre-assessment is
currently $400 per project and $1600 for the related connection work such as metering and
service isolation. For FIT projects the CIA fee is currently $1500 per project and currently the
Offer to Connect/Connection Cost Agreement averages $4200 per project for capital work
including metering equipment and service isolation work. The overall annual fees are
estimated at $960,000. These fees do not relate to area reinforcements to accommodate
generation.
MicroFIT and FIT Interconnection Fees
Project Type
Description
2012
Yr 1 ($)
2013
Yr 2 ($)
MicroFIT
Connection Assessment Fee
96,000
96,000
384,000
Estimate
2014
Yr 3 ($)
2015
Yr 4 ($)
2016
Yr 5 ($)
96,000
96,000
96,000
384,000
384,000
384,000
384,000
126,000
126,000
126,000
126,000
126,000
354,000
354,000
354,000
354,000
354,000
Total
960,000
960,000
960,000
960,000
960,000
Annual Demand
Recoverable Work
from Assessments
222,000
222,000
222,000
222,000
222,000
Annual Capital Work
from Agreements
738,000
738,000
738,000
738,000
738,000
Connection Cost Estimate &
MicroFIT
Connection Agreement Fee
FIT
Connection Impact Assessment
Offer to Connect &
FIT
Connection Cost Agreement Fee
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