D1 T08 S01 SUSTAINING V04 - Toronto Hydro · 9 the condition of in-service assets described in ... 1 Assets considered for replacement are assessed according to specific ... 5 relative

Toronto Hydro-Electric System Limited EB-2007-0680

Exhibit D1 Tab 8

Schedule 1 Filed: 2007 Aug 2

Page 1 of 26

DISTRIBUTION CAPITAL 1

2

SUSTAINING CAPITAL 3

The sustaining capital investments are needs based and delivered as required to maintain 4

existing levels of service and reliability to our customers. 5

6

The sustaining capital expenditures presented in Table 1 below, follow THESL’s 2007-7

2016 Electrical Distribution Capital Plan, Work Prioritization Model, and are based on 8

the condition of in-service assets described in the ACA filed in Exhibit D1, Tab 8, 9

Schedule 9, and an age-based study. These studies identified a pressing need to renew 10

THESL’s underground direct buried distribution system with modern plant. 11

12

Table 1: Five-Year Plan – Sustaining Capital ($000s) 13

2006

Historical 2007 Bridge 2008 Test 2009 Test 2010 Test

Sustaining Capital

Underground Direct Buried 7,327 31,961 45,424 54,565 67,101

Underground Rehabilitation 33,112 31,327 30,514 27,188 24,295

Overhead 19,040 22,703 17,339 18,912 21,293

Network 5,625 3,996 4,514 6,187 7,010

Transformer Station 745 9,377 9,304 10,673 10,508

Municipal Substation Investment 5,977 7,008 8,090 6,454 6,568

Sub Total Sustaining Capital 71,826 106,372 115,185 123,979 136,775

14

The following Figure 1 represents graphically, the proportion of the investments across 15

the major portfolios. 16


Exhibit D1 Tab 8


Page 2 of 26

45%

22%

15%

5%8% 6%

0%

10%

20%

30%

40%

50%

Portfolio

Perc

enta

ge (%

)

Underground Direct Buried Underground Rehabilitation Overhead

Network Transformer Station Municipal Substation

1

Figure 1: Investment Distribution 2

3

Asset condition for major asset classes was quantified through use of Health Indices. In 4

the case of a few specific assets classes at THESL, there are indications that assets may 5

be deteriorating faster than they are being replaced and these require actions beyond 6

routine replacement. Indications of the need for immediate replacement include the 7

increasing failure rates and the poor Health Indices of some classes of asset. For 8

example, direct buried underground cables are a major component that suffers from this 9

deterioration. The assets that require the most significant replacement programs in the 10

next ten years are: 11

• Direct buried underground cable (61% of the population) 12

• Underground cable in-duct (31%) 13

• Automatic transfer switches (63%) 14

• Station transformers (50%). 15

• Pole mounted transformers (35%) 16

• Network transformer/protector units (32%) 17

18


Exhibit D1 Tab 8


Page 3 of 26

Asset age is also a useful measure to indicate the state of the assets and in particular it is 1

useful to determine the geographic concentration of areas requiring investment. Figure 2 2

below demonstrates the equipment age in the city in 20-year categories. 3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

Figure 2: Equipment Age Distribution 19

20

Performance statistics such as failure frequency, outage duration, and total customer 21

interruptions are recorded for distribution circuits and equipment. Over the past five 22

years, equipment failures have continued to be the largest outage cause. The following 23

Table 2 illustrates the deteriorating System Average Interruption Frequency (“SAIFI”) 24

trend over the last five years due to equipment-related outages: 25

26


Exhibit D1 Tab 8


Page 4 of 26

Table 2: SAIFI Trend (Equipment-Related Outages) 1

2002 2003 2004 2005 2006

SAIFI 0.61 0.62 0.70 0.86 0.85

2

As indicated in the “CEA 2005 Service Continuity Report” (study on Canadian electrical 3

utilities), the average contribution of Defective Equipment to SAIFI during 2005 is 0.48. 4

Comparatively, THESL’s Defective Equipment contribution is almost twice as high at 5

0.85 in 2006. Furthermore, as indicated in the above-mentioned CEA report, defective 6

equipment contributed to 23% of the overall SAIFI figure. In the case of THESL, 7

defective equipment contributed to 43% of the overall SAIFI figure during 2005. 8

9

The following Figure 3 illustrates, for comparison purposes, the SAIFI performance of 10

THESL over the last five years. 11

12

13

14

15

16

17

18

19

20

21

22

23

24

Figure 3: SAIFI Trend 25

26

0

0.5

1

1.5

2

2.5

2002 2003 2004 2005 2006 2007forecastYEAR

# of

Inte

rrup

tions

per

Cus

tom

er

0

0.5

1

1.5

2

2.5

2002 2003 2004 2005 2006 2007forecastYEAR

# of

Inte

rrup

tions

per

Cus

tom

er


Exhibit D1 Tab 8


Page 5 of 26

Sustaining capital expenditures for each budget year are derived from a compilation of 1

projects and asset investment requirements using a Work Prioritization Model, and a 2

Long-Term System Planning Process. See Exhibit C1, Tab 6, and Tab 7 for details of the 3

model and the process. 4

5

In general, to provide a balanced view of investment requirements, the following factors 6

are considered: 7

• Corporate Strategic Direction; 8

• Capital Investment plans; 9

• Reactive Capital Investment plans; 10

• Asset Condition Assessment (“ACA”) reports; 11

• Station and feeder load forecasts; 12

• System reliability data; 13

• Safety initiatives; and 14

• Environmental impacts. 15

16

In addition, risk analyses were performed which factor in both the potential for and 17

consequence of component failure as equipment reaches the end of its life. Reliability, 18

safety, and the environment are considered as follows: 19

20

• Reliability consequences include increasing failure rates and number of customers 21

affected. 22

• Safety consequences to the public and employees include potential injury or death 23

from equipment failures. 24

• Environmental consequences include potential damage to the atmosphere, water 25

or soil. 26

27


Exhibit D1 Tab 8


Page 6 of 26

Assets considered for replacement are assessed according to specific criteria embedded in 1

the Work Prioritization Model. Briefly, these criteria include assessments based upon 2

potential reliability improvements (Customer Minutes Out and Customer Interruptions), 3

grid operational flexibility, safety improvements, and cost to repair/install. Once a 4

relative ranking is determined, consideration is given to resource availability and to 5

scheduling logistics. Capacity planning needs are also taken into consideration when 6

determining priorities for replacement areas/circuits, as well as external utility and City-7

mandated requirements such as distribution plant relocations for road closures. 8

9

When projects are under construction, THESL attempts to minimize customer impacts 10

via communication plans to affected neighbourhoods. Typical communication media 11

include community information sessions and project notification letters. In 2007, 12

THESL’s “Project Rebuild” campaign was launched as a communication medium for 13

affected neighbourhoods and THESL will likely continue with similar campaigns. 14

15

UNDERGROUND DIRECT BURIED CABLE 16

Generally, underground distribution cables have better reliability than overhead lines 17

since they are not exposed to mechanical or electrical damage from extreme weather, tree 18

contacts or vehicle accidents. Faults on underground cables are usually caused by 19

localized insulation failures. When failures occur, underground cable repair is usually 20

cheaper than replacement. However, as the frequency of failure increases in a given 21

segment, reliability and cost considerations often make replacement the prudent choice, 22

since repair of direct buried cable entails trenching, ground movements, uncertainty 23

around locates, landscaping repairs to roads, sidewalk, boulevard, private property, traffic 24

congestion, and potential public hazards. 25

26

During the 1970s, cross-linked polyethylene (“XLPE”) cables were commonly used in 27

new installations due to their lower costs and easier handling characteristics relative to 28


Exhibit D1 Tab 8


Page 7 of 26

other high voltage cable types. However, early generation XLPE cable installations were 1

less reliable due to manufacturing defects and cable joint related issues. Water 2

penetrating into the insulation/conductor barrier (water treeing) was found to be a 3

principal cause of cable failure. Exposing these cables to direct buried environments 4

without the protection of ducts or concrete encasement, further accentuated the 5

deterioration of these cables. 6

7

Over the past 30 years many of these problems have been addressed as part of equipment 8

modernization, and modern tree-retardant XLPE cables and accessories are generally 9

considered more reliable. THESL’s current practice is to replace old, unreliable direct 10

buried XLPE cable with tree retardant XLPE cables that incorporate designs with metal 11

foil barriers and water migration controls to further reduce the rate of deterioration from 12

“water treeing”. According to current standards, cable is installed in duct or newly 13

constructed concrete-encased ducts in order to improve reliability of the cable. Cable in 14

duct and concrete-encased ducts enable quicker repair times of faults, thereby reducing 15

the outage duration associated with any future faults. 16

17

Although new technologies have addressed many of the concerns with earlier vintage 18

XLPE cable, many of the early installations still remain throughout parts of the City; 19

mainly in suburban subdivisions in northeast Toronto. Over the last four years, many 20

direct buried circuits have failed upwards of five times each, causing large numbers of 21

customers to experience outages, with some outages contributing close to one million 22

customer-minutes out. The condition of these cables continues to deteriorate and 23

replacement is indicated. Over the past five years, underground equipment failures have 24

continued to worsen. The following table illustrates the worsening SAIFI trend over the 25

last five years due to underground equipment related outages: 26

27


Exhibit D1 Tab 8


Page 8 of 26

Table 3: SAIFI Trend (Underground Equipment-Related Outages) 1

2002 2003 2004 2005 2006

SAIFI (Underground Equipment) 0.35 0.38 0.38 0.49 0.44

2

THESL used two key criteria to assess the circuits/areas in need of replacement; the 3

number of failures per unit length of installation, and the age of each direct buried cable 4

circuit. As illustrated in the ACA, the average age of the direct buried XLPE cable in 5

Toronto is approximately 30 years. More critical is the fact that about half of this asset 6

class is past its theoretical end-of-life. The ACA also illustrates that presently about two-7

thirds or almost 800 kilometers of direct buried cable requires replacement over the next 8

ten years. Specifically over the next three years, almost 300 kilometers of direct buried 9

cable is in need of replacement. 10

11

In addition to evidence in the ACA, evidence from THESL’s “worst feeder list” shows 12

that the majority of the worst ranking circuits are direct buried XLPE cables located in 13

the northeast portion of the city. The worst feeder list is a compilation of circuits with 14

poor historical reliability performance (measured in Total Customer Minutes Out and 15

Total Customer Interruptions). 16

17

Replacing direct buried XLPE cable in target areas over the next ten years will contribute 18

significantly to reliability improvement. The areas will be rebuilt using concrete-encased 19

ducts in order to provide better protection for the cable as well as reducing costs and 20

outage duration during future repairs. 21

22

In conjunction with the installation of new concrete-encased primary distribution, 23

consideration is also given to the replacement of other aging assets such as transformers, 24

elbows, fault interrupters, pad-mounted switches, and other assets that are becoming 25

unreliable in order to take advantage of economies of scale and to minimize public 26

disturbances in the future. In addition to infrastructure improvements, target areas will be 27


Exhibit D1 Tab 8


Page 9 of 26

redesigned in order to reduce the number of customers experiencing outages when 1

failures occur. For example, circuits utilizing fault interrupters (predominantly in the 2

northeast quadrant of the City) will be redesigned with newer, more reliable, fuses and 3

switchgear. 4

5

Table 4 summarizes the total capital requirements for underground direct buried capital 6

investments for the 2008, 2009, and 2010 test years, as well as the historical and bridge 7

years. 8

9

Table 4: Underground Direct Buried Capital Requirements Summary ($000s) 10

2006 Historical 2007 Bridge 2008 Test 2009 Test 2010 Test

Underground Direct Buried 7,327 31,961 45,424 54,565 67,101

11

The capital requirements increase throughout the bridge and test years. 12

13

A total of $564M is required over the next ten years for capital rehabilitation of 14

underground direct buried cables. Ideally, this would be spread over the ten-year horizon 15

by investing $55M - $60M yearly. However due to resource constraints and the time 16

required to hire the necessary trades and technical staff, and provide the required training, 17

the investment gradually increases over the ten-year period. 18

19

The highest priority projects will be undertaken first. Logical project boundaries are 20

taken into account in order to take advantage of economies of scale. The following 21

Figure 5 illustrates the location of projects for the period of 2008-2010. 22

23


Exhibit D1 Tab 8


Page 10 of 26

1

2

3

4

5

6

7

8

9

10

11

12

13

14

Figure 5: Underground Direct-Buried Projects, 2008-2010 15

16

The assets to be replaced in the first three years have demonstrated poor levels of 17

reliability and have aged beyond their serviceable life. 18

19

UNDERGROUND REHABILITATION 20

In many areas in the city and especially in the downtown core, underground cable was 21

installed in concrete-encased ducts. Both paper insulated lead covered (“PILC”) and 22

XLPE-type cables have been installed in duct systems throughout the city with majority 23

of the PILC cable installed in the core of the city. For PILC-type cable, the corrosion of 24

the metal sheath and degradation of the oil impregnated paper insulation, and eventual 25

splitting of the lead sheath due to load cycling, creates adverse reliability and 26

environmental impacts. 27

28


Exhibit D1 Tab 8


Page 11 of 26

As noted earlier, as long as the reliability is within acceptable levels, it is virtually always 1

less expensive to repair than to replace cables. In some areas of the city, the reliability 2

has deteriorated, and continued repair has become a costly and unreliable alternative. 3

4

THESL used two key criteria to assess the circuits/areas in need of replacement: the 5

number of failures per unit length of installation and the age of each cable circuit. Life 6

expectancy of PILC-type cables is between 50 to 70 years depending on loading and in-7

service conditions. The ACA suggests that currently approximately one-third (almost 8

400 kilometers) of PILC cable-in-duct requires replacement over the next ten years. 9

Specifically, over the next three years, 75 kilometers of PILC cable-in-duct is in need of 10

replacement. Although the ACA illustrates the average age of cable-in-duct across the 11

city is about 20 years old, in older areas of the city, the age of cable-in-duct is well above 12

the average. 13

14

Due to congestion and aging of the associated cable chambers, a portion of the civil 15

infrastructure will be required to be rebuilt during the replacement of the cable-in-duct. 16

By alleviating congestion, personnel safety will be improved. Furthermore, new 17

construction standards include the installation of a Petro-Barrier. This device will 18

prevent oil from entering storm drains, thereby also benefiting the environment. In 19

conjunction with the installation of new cable-in-ducts, consideration is also given to 20

replace other aging assets that are becoming unreliable such as transformers, elbows, and 21

other assets in order to avoid additional switching operations as well as to reduce multiple 22

work zone set-ups. This will result in minimizing additional future public disturbances. 23

24

Table 5 summarizes the total capital requirements for underground rehabilitation 25

investments for the 2008, 2009, and 2010 test years, as well as the historical and bridge 26

years: 27

28


Exhibit D1 Tab 8


Page 12 of 26

Table 5: Underground Rehabilitation Capital Requirements Summary ($000s) 1


Underground Rehabilitation 33,112 31,327 30,514 27,188 24,295

2

The 2007-2016 Electrical Distribution Capital Plan outlines the requirement for a $210M 3

investment over that ten year period for capital rehabilitation of underground cable in 4

duct systems. Ideally, this would be spread over the ten year horizon by investing $20M 5

to $22M yearly. However, as Apprentices build the required skills by directing their 6

effort to the less complex underground rehabilitation work in the early years, they will 7

then gradually re-direct their efforts to the more complex direct-buried cable replacement 8

work in the latter years. 9

10

To summarize priority, logistical end-to-end boundary considerations will be taken into 11

account in order to take advantage of economies of scale and obsolete assets will be 12

replaced with modernized equipment at the same time. The following Figure 6 illustrates 13

the location of projects for the period of 2008-2010. 14


Exhibit D1 Tab 8


Page 13 of 26

1

2

3

4

5

6

7

8

9

10

11

12

The assets to be replaced in the first three years of the program have demonstrated poor 13

levels of reliability and have aged beyond their serviceable life. 14

Figure 6: Underground Rehabilitation Projects, 2008-2010 15

16

OVERHEAD SYSTEM 17

THESL’s overhead distribution system supplies power to customers at three primary 18

voltages; 27.6 kV, 13.8 kV, and 4.16 kV. The main components of the overhead system 19

include poles, conductors, switches, pole-top transformers, fuses, surge arresters, 20

insulators, and grounding devices. 21

22

The deteriorated condition of the overhead distribution plant along with obsolete non-23

standard equipment, and old poles play an integral part in the overall reliability of the 24

overhead distribution system. Over the past five years, overhead equipment failures have 25

continued to worsen. The following table illustrates the worsening SAIFI trend over the 26

last five years due to overhead equipment related outages: 27

28


Exhibit D1 Tab 8


Page 14 of 26

Table 6: SAIFI Trend (Overhead Equipment-Related Outages) 1

2002 2003 2004 2005 2006

SAIFI (Overhead Equipment) 0.24 0.21 0.30 0.33 0.29

2

In order to attain economic efficiencies, each individual component is not replaced in 3

isolation. Rather, the overhead components are predominantly assessed as areas/circuits. 4

5

As illustrated in table ES-1 of the ACA, based upon the condition of the poles, there are 6

almost 1100 poles requiring replacement over the next three years. These poles are 7

distributed relatively uniformly across the city. 8

9

Poles 10

In determining overhead capital expenditures when pole replacement is the primary 11

driver, other factors need to be considered. For example, consideration is given to 12

replace aging like-for-like assets and to convert to a higher primary voltage. Although 13

the conversion option is more expensive, if currently in-service 4 kV stations are 14

scheduled to be decommissioned within the next ten years, or system losses can be 15

reduced at the higher voltage, consideration will be given to voltage conversion. 16

17

Transformers 18

Pole-mounted transformers are used to step down power from primary voltages to 19

utilization voltage. The average age of these assets within THESL is about 40 years and 20

the theoretical end of life for these assets is approximately 50 years. According to the 21

ACA, about 350 pole-mounted transformers are required to be replaced over the next 22

three years. 23

24

Switches/Fault Sensing 25

Primary switches are used throughout the overhead distribution system to allow isolation 26

of line sections or equipment for maintenance, safety, or other operating requirements. 27


Exhibit D1 Tab 8


Page 15 of 26

Many of these switches are motor operated for remote operation to enhance speed of 1

switching and operating efficiency. Switches typically corrode around the mechanical 2

linkages or fail under fault conditions. Corrosion occurs primarily in major industrial 3

areas or where harsh environments cause corrosion. Although the environment 4

contributes to rust and corrosion resulting in a critical degradation factor, other conditions 5

such as the load duty, also impact the service life of primary switches. The average 6

service life of a primary switch is approximately 40 years. Existing remote switches in 7

the north central portion of the city are aging, and becoming obsolete and unreliable. 8

They have non-standard communications components, are not designed with fault 9

sensors, and spare parts are difficult to obtain. For these reasons, many of these switches 10

need to be replaced over the next three years. A reduction in the duration of outages on 11

circuits with upgraded switches is expected; Power System Controllers will be able to 12

ascertain the location of faults more quickly, and switch repairs can proceed with 13

standard components. 14

15

In general, as assets are replaced in accordance with new “standards” specifications 16

provide for better performance, reduced environmental impacts, and mitigate personnel 17

and public safety impacts. Consideration is also given to specifying assets that will 18

maximize life expectancy within their operating contexts. “Tree-proof” cable is used in 19

heavily treed areas across the city. This is beneficial to the environment since it greatly 20

reduces the extent of pruning required for the affected trees. 21

22

Table 7 summarizes the total capital requirements for overhead capital investments for 23

the 2008, 2009, and 2010 test years, as well as the historical and bridge years: 24

25

Table 7: Overhead Capital Investments Summary ($000s) 26


Overhead 19,040 22,703 17,339 18,912 21,293


Exhibit D1 Tab 8


Page 16 of 26

1


investment over that ten-year period for rehabilitation of overhead distribution. Ideally, 3

this would be spread over the ten-year horizon by investing $17M to $19M annually. 4

However, a focussed effort on deteriorated pole replacement is required in 2007 with 5

investments in overhead rehabilitation returning to more average levels over the test 6

years. 7

8

The highest priority projects will be undertaken first. Logistical end-to-end boundary 9

considerations will be taken into account in order to take advantage of economies of 10

scale, and focus will be in areas where there is limited or no remote switching capabilities 11

in order to improve restoration times and improve customer service. Presently, 12

approximately one-third of overhead switches have remote capabilities. The following 13

Figure 7 illustrates the location of projects for the period of 2008-2010. 14


Exhibit D1 Tab 8


Page 17 of 26

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

Figure 7: Overhead Projects, 2008-2010 16

17

Network Transformers 18

The network distribution system is a system of secondary cables (below 600V) designed 19

in an interconnected grid, supplied by a number of network transformers. Services fed 20

from the network system are therefore supplied by multiple transformers. This design 21

allows for first contingency operation. That is, one feeder and all associated transformer 22

units can be taken out of service and no other units or cables will become overloaded. 23

The network system is most effectively used to supply urban downtown core areas where 24

the load density is very high, such as along Yonge Street, or Bloor/Danforth. 25

26

Network transformers are installed in below grade, self-ventilated concrete vaults. 27

Network transformers have provision for mounting network protectors and are used in the 28

core of the city in a secondary network distribution system. The network protector is a 29


Exhibit D1 Tab 8


Page 18 of 26

low voltage, reverse current sensing, auto-reset circuit breaker. It is mounted on the front 1

of the network transformer. The function of the protector is to isolate the transformer 2

from the network when the protector relay senses any reverse current flow. 3

4

Protected from most of the natural elements, and able to tolerate partially submerged 5

operation, these units see a longer service life than above-grade units. The end of life for 6

network transformers is usually determined by the extent of the breakdown of core 7

winding insulation and transformer oil leaks through deteriorated gaskets. The life 8

expectancy of a network transformer and protector combination is 30 to 50 years 9

depending upon the number of short circuit operations experienced by the components. 10

Network protector failures that lead to improper fault isolation, may lead to catastrophic 11

transformer failure or a vault fire and may result in widespread outages to commercial 12

customers. 13

14

Replacement of aging network transformers and protectors will help to improve service 15

reliability, and reduce the likelihood of environmental and public safety impacts. As 16

illustrated by the ACA, almost 200 units (approximately ten percent) are required to be 17

replaced over the next three years. 18

19

Table 8 summarizes the total capital requirements for network capital investments for the 20

2008, 2009, and 2010 test years, as well as the historical and bridge years: 21

22

Table 8: Network Capital Investments Summary ($000s) 23


Network 5,625 3,996 4,514 6,187 7,010

24

The 2007-2016 Electrical Distribution Capital Plan outlines the requirement for a $58.5M 25

investment over that ten-year period for rehabilitation of network assets. Although there 26


Exhibit D1 Tab 8


Page 19 of 26

is variability in spending over the bridge and test years that reflects the age profile of the 1

assets, the expected average investment is about $6M annually. 2

3

The highest priority projects are intended to mitigate risk by targeting locations 4

susceptible to high impact events or that contain non-standard equipment. Over 90% of 5

the 200 units to be replaced by 2010 meet these criteria. In order to avoid environmental 6

hazards and to mitigate reliability concerns, further criteria for immediate replacement of 7

this asset class include any locations where the units are found to be leaking oil. The 8

following Figure 8 illustrates the location of projects for the period of 2008-2010. 9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

Figure 8: Network Projects, 2008-2010 25

26


Exhibit D1 Tab 8


Page 20 of 26

TRANSFORMER STATIONS (HONI SUPPLY POINTS) 1

THESL receives power at 35 transformer stations. Of the 35 transformer stations, 19 are 2

owned by HONI, 15 have a mixed ownership of power equipment between HONI and 3

THESL, and one is owned solely by THESL. Seventeen of the stations are supplied at 4

115 kV and the other 18 are supplied at 230 kV. 5

6

These stations are used to obtain power from the transmission system and to transfer it to 7

the distribution system. Their primary function is voltage transformation and switching. 8

Station facilities contain many of the following components: power transformers, circuit 9

breakers, instrument devices, disconnect switches, bus, insulators, power cables, support 10

structures, cable terminators, surge arrestors, station service supplies, supervisory 11

equipment and grounding systems. In general, in cases of mixed station ownership, 12

THESL will own varying number of circuit breakers, and other equipment related to 13

switching functions. Power transformers are generally owned by HONI at these stations. 14

15

Circuit Breakers 16

THESL’s circuit breaker population consists of a variety of interrupting technologies: 17

oil, air-blast, air-magnetic, vacuum and sulphur-hexafluoride (“SF6”). As stated in the 18

ACA, there are many factors that affect the condition of a circuit breaker including 19

corrosion, moisture, bush/insulator deterioration, and mechanical wear and tear. The 20

useful life of a circuit breaker can vary between 25 to 50 years. There are almost 30 units 21

across THESL that will reach their end of useful life within the next three years. The 22

oldest technology, oil circuit breakers are one of the technologies targeted for 23

replacement. The units are expensive to maintain as they require the most frequent 24

maintenance intervals. Removal of these units from service decreases the amount of 25

flammable oil present in a station and reduces the amount of oil that may be spilled into 26

the environment. 27

28


Exhibit D1 Tab 8


Page 21 of 26

Switchgear 1

In indoor stations, circuit breakers are contained in metal-clad housings, called metal-clad 2

switchgear, to reduce space requirements and enhance operational flexibility. All new 3

metal-clad switchgear installations at THESL comply with arc-resistance standards so 4

that failure in one compartment will be contained to that compartment and not spread to 5

adjacent compartments. Personnel safety is increased as the containment prevents injury 6

to personnel in the vicinity. In non-arc-resistant switchgear, an eventful failure in a 7

compartment may damage adjacent compartments or the entire switchgear in an un-8

repairable way leading to a prolonged outage. Personnel in the proximity of an eventful 9

failure are at risk of injury. 10

11

Switchgear degradation is due to deterioration of mechanical mechanisms and interlocks, 12

deterioration of solid insulation, and corrosion. Other non-condition factors such as 13

obsolescence and capability also contribute significantly to the end of life for this asset 14

class. If the fault level on the distribution system rises beyond the rated interrupting 15

capacity of the switchgear for example, the switchgear must be upgraded regardless of its 16

age. The expected life for switchgear is 35 to 50 years under normal in-service 17

conditions. 18

19

Ancillary Equipment 20

Much of the ancillary equipment in the terminal stations is also old and replacement parts 21

are very difficult to source. Increasing the level of automation in order to diagnose and 22

respond to abnormal events is being considered in order to improve performance. 23

Currently, three to five stations per year are scheduled to be retro-fitted. 24

25

Plan 26

Station capital projects address planned refurbishment and component replacement, as 27

well as reactive work. The level of investment required for a selected station will vary as 28


Exhibit D1 Tab 8


Page 22 of 26

a function of the age/condition of the station, its performance and any safety and 1

environmental issues identified. 2

3

Station condition is determined using the ACA process and on-site reviews. THESL will 4

be replacing switchgear at a rate of three transformer stations per year. In addition to 5

switchgear, a number of other related components must be replaced. 6

7

The 2008 investment requirements broken down by component, listed in Table 9 below, 8

are representative of the bridge and test year spending requirements that are summarized 9

in Table 10. 10

11

Table 9: Transformer Station Investment Summary ($000s) 12

Asset Class 2008 Investment

Switchgear 7,562

Transformers (non-power) 215

Circuit breakers 1,169

Batteries and chargers 41

Station decommissioning -

Fire alarm system 43

Supervisory control/station automation 209

Other 69

13

Table 10: Transformer Station Capital Investments Summary ($000s) 14


Transformer Station 745 9,377 9,304 10,673 10,508

15


investment over that ten year period for replacement of station assets which is reflected in 17

the average spending over the bridge and test years. In 2006, investments were low and 18

no switchgear replacements were done. In 2007, two switchgear replacements were 19


Exhibit D1 Tab 8


Page 23 of 26

responsible for $5.6 million and one mobile switchgear unit for another $1 million along 1

with increased investments in other assets. 2

3

THESL is able to ramp up capital expenditures for Transformer Stations rapidly. The 4

largest investment type, switchgear replacements, involves significant equipment costs 5

and contract labour. 6

7

The highest priority projects will be undertaken first and obsolete assets will be replaced 8

with modernized equipment. The following Figure 9 illustrates the location of projects 9

for the period of 2008-2010. 10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

Figure 9: Transformer Station Projects, 2008-2010 25

26


Exhibit D1 Tab 8


Page 24 of 26

MUNICIPAL SUBSTATIONS 1

Municipal stations receive power from transformer stations via primary distribution 2

feeders and then transform the voltage to either 13.8 kV or 4.16 kV for further 3

distribution. Their primary functions are voltage transformation and switching. They 4

contain much of the same components as transformer stations. THESL operates 152 5

active municipal stations which are comprised of assets owned and maintained by 6

THESL. 7

8

Circuit Breakers and Switchgear 9

Circuit breakers and switchgear within municipal stations are similar to those in 10

transformer stations as described under Transformer Stations in this Schedule. 11

12

Transformers 13

Municipal station transformers are used to step down the higher distribution voltage 14

levels to lower distribution voltage levels. They are very critical assets from the view of 15

financial and operational risk. The expected end of life for this asset is determined to a 16

great extent by insulation failure. Other end-of-life indicators include condition of 17

bushings, transformer tanks, gaskets, and foundations. Consequences of failure may be 18

significant including customer interruptions for extended periods of time, loss of revenue, 19

and health and safety risks. There are also environmental risks due to oil spills during 20

tank failure. 21

22

The expected end of useful life for this asset is 40 to 50 years. As illustrated by the ACA, 23

approximately 30 units will reach their end of life within three years. 24

25


Exhibit D1 Tab 8


Page 25 of 26

Ancillary Equipment 1

Much of the ancillary equipment in the municipal substations is also old and spare parts 2

are very difficult to purchase for existing equipment. Automating many of these stations 3

is also being considered to improve on reliability and reduction of response time. 4

5

Plan 6

Station condition is determined using the ACA process and on-site reviews. THESL will 7

be refurbishing at least one switchgear and approximately six power transformers each 8

year. In addition, a number of other related components will be replaced. 9

10

The 2008 investment requirements broken down by component, listed in Table 11 below, 11

are representative of the bridge and test year spending requirements that are summarized 12

in Table 12. 13

14

Table 11: Municipal Station Investment Summary ($000s) 15

Asset Class 2008 Investment

Switchgear 552

Transformers 854

Circuit breakers 3,720

Batteries and chargers 323

Station decommissioning 159

Fire alarm system 175

Supervisory control/station automation 989

Demand Capital and Tools 625

16

Table 12: Municipal Substations Capital Investments Summary ($000s) 17


MS Investment 5,977 7,008 8,090 6,454 6,568

18


Exhibit D1 Tab 8


Page 26 of 26


investment over that ten-year period for rehabilitation of municipal substation assets 2

which is reflected in the average spending over the bridge and test years. 3

4

During 2007 and 2008, there is an increase in spending by $1M and $2M respectively in 5

order to address assets currently in very poor condition, representing potentially high 6

impact events to reliability of supply. 7

8

Much like transformer stations, the bulk of the investment is attributed to equipment 9

costs, the highest priority projects will be undertaken first, and obsolete assets will be 10

replaced with modernized equipment. The following Figure 10 illustrates the location of 11

projects for the period of 2008-2010. 12

13

14

15

16

17

18

19

20

21

22

23

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25

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Figure 10: Municipal Station Projects, 2008-2010 29

Documents

D1 T08 S01 SUSTAINING V04 - Toronto Hydro · 9 the condition of in-service assets described in ... 1 Assets considered for replacement are assessed according to specific ... 5 relative