INVESTMENT SUMMARY FOR PROGRAMS/PROJECTS IN EXCESS OF $3 MILLION

(1)

Filed: September 30, 2008

EB-2008-0272

Exhibit D2

Tab 2

Schedule 3

Page 1 of 80

1 2 3 4 5 6 7 8

INVESTMENT SUMMARY FOR PROGRAMS/PROJECTS IN

EXCESS OF $3 MILLION

Sustaining

Capital

S1

to

S36

Development

Capital

D1

to

D38

Operations

Capital

O1

to

O3

Shared Services and Other Capital

IT1 to IT 3

C1 to C3

(2)

Hydro One Networks – Investment Summary Document

Investment Category: Sustaining Capital – Stations - Circuit Breakers

Reference # Investment Name Gross Cost In-Service Date

S1 2009/2010 Oil Circuit Breaker Replacements $8.5 M Late 2010

Please see Exhibit D1, Tab 3, Schedule 2 for cash flows.

Need:

This investment is required to address end of life issues of the aging population of oil circuit breakers (OCBs) by way of proactive replacement of those that represent the highest risk to system security and customer connection reliability.

Implications of not proactively managing this population of breakers include overall decline of health of the OCB population and employee safety. Inaction will result in a trend of equipment unavailability, inadequate equipment fault ratings, an increase in probability of failure and equipment outages (both customer and network connected) and an increased risk to Hydro One's Safety & Environment business values.

Summary:

Hydro One currently owns and manages over 4,000 circuit breakers of which oil circuit breakers account for greater than 50% of the total population. These bulk oil circuit breakers, which utilize organic insulating fluids for extinguishing arc produced during opening sequences, are no longer commercially available and are being replaced with new SF6 Circuit Breaker (CB) technology at end of life. Historically, OCBs have provided excellent in-service performance but a portion of the entire population reaches end of life each year. Based on various studies conducted since 1990 to assess the condition of OCBs, both refurbishment and replacement programs had been developed. As a result, an overall replacement strategy was developed by Hydro One to address the condition and ratings of OCBs on a prioritized basis. The strategy takes into account age, physical condition, parts obsolescence and equipment ratings. These criteria are used to assess the replacement candidates, and to put into motion the recommendations of the strategy.

Current performance measures have steadily improved from 13 catastrophic failures during 1992-1996 to only 3 catastrophic failures during 1997- 2004 since the onset of annual replacement and refurbishment programs. As a result of program success, future overall performance trends are expected to remain stable at the current levels of funding. The OCB replacement program as of 2005 will have addressed a total of 873 end of life oil circuit breakers throughout the province.

In summary, the strategy identifies candidates for replacement based on assessed condition and switching duty-cycle requirements, equipment health index reports, the needs database, equipment defects reports and other localized special studies. Prioritization is based on risk as it relates to the HONI Business Values and Key Performance Indicators. The transmission system development and transmission load connections departments have reviewed the replacement candidates included in this investment for integration opportunities, and have concurred with the program prioritization.

Results:

This plan will replace end of life OCBs in 2009 and 2010. Project Classification per OEB Filing Guidelines:

Project Class: Sustaining

(3)

Hydro One Networks – Investment Summary Document

Investment Category: Sustaining Capital – Stations - Circuit Breakers

Reference # Investment Name Gross Cost In-Service Date

S2 2009/2010 Metalclad Circuit Breakers Replacement - GTA

$8.0 M Late 2010

Need:

This investment is required to address the end of life (EOL) condition of the low-voltage metalclad switchgear in the Greater Toronto Area (GTA) and the lack of arc proofing on these units.

The implications of not proactively replacing EOL metalclad equipment are:

• A reliability reduction to Toronto Hydro and its customers resulting in a negative impact on reputation

• Increased maintenance expenditures and difficulty in obtaining or fabricating technically obsolete spare parts

• GTA metalclads are not arc proofed which creates a safety risk

Summary:

Thirty one (31) of the 100 metalclad line-ups in the GTA are currently exceeding manufacturer's life expectancy of 40 years. Three (3) Metalclad line-ups have been replaced since 1992. Toronto Hydro (THESL) and Hydro One (HONI) have recently identified 4 locations in the GTA for replacement over the next two years. They are at EOL based on age, parts availability, reliability and safety considerations. The supporting information is obtained from consultations with THESL, asset condition assessment, data

registries, routine diagnostics, inspection results, system analysis and outage logs.

This existing switchgear is not built to present day arc proof type C standards which results in safety and reliability concerns. HONl has experienced, on average, 2 major faults per year with inadequate metalclad arc proofing design. This can result in damages to the adjacent feeders and a potentially hazardous situation for personnel. The switchgear includes feeder breakers that are owned by THESL and bank breakers that are owned by HONI. THESL and HONl have agreed to purchase switchgear from the same manufacturer for technical and logistic reasons and to allow for easier installation, maintenance, stocking of parts, training, and to retain common system spare breakers. Switchgear from the same manufacturer also eliminates the limited space issues at these stations. The program includes new protections and the 15 kV cables that supply the switchgear.

Results:

• Reduce the life cycle cost and maintain customer reliability

• Provide up to date maintenance practices with the addition of a modern design and safety interlocks

• Upgrade breakers to current safety standards by the addition of arc proofing

Project Classification per OEB Filing Guidelines:

(4)

Hydro One Networks – Investment Summary Document

Investment Category: Sustaining Capital - Stations - System Re-Investment

S3 Abitibi Canyon Switching Station (SS) and Pinard Transformer Station (TS) - Replace EOL Components

$20.2 M Late 2012

Need:

This investment is required to replace Oil Circuit Breakers (OCB’s) and other equipment that is reaching end of life at these stations to minimize life cycle costs and to de-merge Hydro One assets from Ontario Power Generation’s (OPG) powerhouse.

If this work is not completed, there is significant risk of a system decline in the health and reliability of the OCB population and other EOL components, a reduction in system reliability and a decrease in customer reliability.

Summary:

Originally built in the early 1930’s, Abitibi Canyon SS facilitates 350 MW of hydraulic generation and bulk power flows on the 230 kV and 115 kV networks. There are one 230 kV and three 115 kV circuits connected at Abitibi Canyon SS. The 115 kV oil circuit breakers are used for both ring bus switching and generation unit synchronization. Hydro One’s 115 kV ring bus arrangement is situated on the OPG owned powerhouse dam. All the ancillary services and protection and control systems are within the powerhouse dam.

The 115 kV breakers at Abitibi Canyon SS are 60 years old and rank amongst the top 30 worst breakers in the Hydro One system. Furthermore, the sole provider of spare parts for these breakers has indicated that they no longer support the breaker type. In addition to the breakers, the insulation systems, switches, protection and control facilities, foundations and ancillary systems have all reached end of life.

An asset condition and risk assessment has determined that the 5 - 115 kV OCB’s at Abitibi Canyon SS have reached end of life and have been prioritized for replacement with new SF6 breakers. The investments contained in this proposal primarily focus on the end of life 115 kV power equipment and the required 115 kV system reconfigurations. In addition, investments are required to fully de-merge the integrated control, metering, relaying, annunciation and ancillary systems for both the 230 kV and 115 kV systems.

Results:

• Reduce the operational risks, minimize life cycle costs, eliminate safety and environmental issues, and improve the bulk system equipment reliability.

• De-merger of Hydro One assets from the OPG powerhouse and the resulting reduction in business liability.

Project Classification per OEB Filing Guidelines:

(5)

Hydro One Networks – Investment Summary Document

Investment Category: Sustaining Capital - Stations - System Re-Investment

S4 Beck #1 SS: Air Blast Circuit Breaker (ABCB) Re-Investment

$35.0 M Late 2011

Need:

This investment is required to replace Air Blast Circuit Breakers (ABCB’s) and other equipment that is approaching end of life to minimize the life cycle costs, to de-merge Hydro One assets from the Ontario Power Generation (OPG) powerhouse and to reduce regulatory maintenance requirements from the Technical Standards and Safety Authority (TSSA)

If this work is not completed, there will be a continued decline in the health and reliability of the ABCB population and associated End of Life (EOL) components, and reduced system reliability and customer reliability in the area.

Summary:

Originally built in the 1920’s, Beck #1 SS facilitates bulk power transfers on the 115 kV network, and connects 563 MW of hydroelectric generation at Beck #1 GS. In addition to providing a major network path, the 115 kV circuits supply several load stations and large customers including Allanburg TS, Niagara TS, Gage TS, Stanley TS, Murray TS, Decew Falls SS, Beamsville TS and Niagara on the Lake Hydro (2 TSs). There are twelve 115 kV circuits connected at Beck #1 SS including two circuits to USA Niagara Mohawk. Seven of the circuits operate at 60 cycle and the remaining five at 25 cycle. Ten of the breakers are owned by Hydro One. At the present time discussions are underway between OPG and Hydro One, which will result in Hydro One acquiring additional breaker(s) and other equipment.

The 115 kV air blast circuit breakers include six English Electric (EE) type OBN8G / OBN9G built in 1950 (5) and 1954 (1). The breakers are 56 and 52 years old. The original breaker manufacturer is no longer in business. Technical support and spare parts are no longer available. This investment is required to address the deteriorating condition of the four in-service EE breakers. Air blast circuit breakers employ high pressure air as an interrupting and insulating medium. At this point the o-rings and seals have deteriorated to such an extent that the breakers are unable to contain the insulating air properly resulting in an increased risk of failure. Two of the EE breakers are out of service at this time due to air system capacity issues.

In 2006, a site assessment identified 6 - 115 kV ABCB's to be replaced with new SF6 breakers, as well as replacement of 32 high voltage switches, 2 high voltage ground switches, and 12 high voltage instrument transformers. This investment will also enable a staged de-merger from the common systems including high-pressure air systems that are shared with OPG.

Results:

• Reduce operational risks, minimize life cycle costs, and improve system reliability.

• De-merger of Hydro One assets from the OPG powerhouse and resulting reduction in business liability.

Project Classification per OEB Filing Guidelines:

(6)

Hydro One Networks – Investment Summary Document

Investment Category: Sustaining Capital - Stations - System Re-Investment

S5 Orangeville TS: Air Blast Circuit Breaker (ABCB) Re-Investment

$17.7 M Late 2010

Need:

This investment is required to replace end of life Air Blast Circuit Breakers (ABCB's) and other end of life station components and reduce regulatory maintenance requirements from the Technical Standards and Safety Authority (TSSA).

If this work is not completed, there is significant risk of the decline in the health and reliability of the ABCB population and associated End of Life (EOL) components, and reduced system reliability and customer load security impacts.

Summary:

Originally built in the 1960’s, Orangeville TS facilitates bulk power transfers on the 230 kV network between Bruce NGS, Detweiler TS and Essa TS. In addition to providing a major network path, the 230 kV circuits supply several load stations and large customers including Alliston TS, Hanover TS, Fergus TS, Campbell TS, Detweiler TS, Amaranth CTS / Melancthon Grey Wind NUG, Waterloo North MTS and Scheifelle MTS. There are six 230 kV circuits connected at Orangeville TS.

The 230kV ABCBs at Orangeville TS were built in 1968 and 1969 and were originally installed at Beck #2 TS. These breakers are at end of life based on their condition, performance and availability of spare parts. The interrupter contacts have been a source of problems since the breakers were installed at Orangeville in 1983. The contact fingers develop cracks after 1200 breaker operations, a major design problem. Other major problems include premature mechanical and electrical wear to the stationary and moving contact fingers. Forced outage rates for air blast breakers have been increasing and the sole provider of spare parts for these breakers has indicated that they no longer support this type of breaker. Once the air blast circuit breakers are retired the related high pressure air system will be decommissioned and the major components (i.e. compressors, dryers) will be used at other Hydro One stations.

In 2006, a team conducted a site assessment to identify EOL components within the 230 kV switchyard, with the intention of bundling the work into a single efficient work package. The identified work within this investment includes replacement of 6 – 230 kV ABCB's with new SF6 breakers and associated replacement of 20 High Voltage (HV) Switches, 6 high voltage line ground switches, 4 High Voltage Instrument Transformers and the main AC transfer schemes and switchgear.

Results:

• Reduce operational risks and life cycle costs and regulatory maintenance requirements (TSSA).

• Improve the bulk system equipment availability indices and the reliability of supply to area customers.

Project Classification per OEB Filing Guidelines:

(7)

Hydro One Networks – Investment Summary Document

Investment Category: Sustaining Capital – Stations - System Re-Investment

S6 Beck #2 TS - Air Blast Circuit Breaker (ABCB) Re-Investment

$35.0 M Late 2012

Please see Exhibit D1, Tab 3, Schedule 2 for cash flows. Need:

This investment is required to replace End of Life (EOL) Air Blast Circuit Breakers (ABCB's) and other associated EOL assets (i.e. switches, insulators, instrument transformers, infrastructure) in order to optimize the life cycle costs, improve the bulk system equipment availability index by replacing other associated EOL components and to reduce regulatory maintenance requirements from the Technical Standards and Safety Authority (TSSA).

Implications of not executing this investment include the decline in the health and reliability of the ABCB population and associated End of Life (EOL) components, and reduced system reliability and customer load security.

Summary:

Originally built in the 1950’s, Beck #2 TS is a critical station that facilitates bulk power transfers on the 230 kV network and connects 1,775 MW of hydroelectric generation from Beck #2 GS and Pump GS. In addition to providing a major network path, the 230 kV circuits supply several load stations and large customers including (4) circuits to the USA (two at 345kv).

There are 20 air blast circuit breakers at this station. This investment is required to address the deteriorating condition of the air blast circuit breakers. Air blast circuit breakers employ high pressure air as an interrupting and insulating medium. The breaker manufacturer recommends that the breakers require re-gasketing and rebuilding mid-way through their 40-year life. At this point the o-rings and seals have deteriorated to such an extent that the breakers will not contain the air properly resulting in an increased risk of failure. Hydro One has experienced five explosive failures on the Delle type PK breaker. The explosive failures resulted in porcelain fragments landing 80 feet away. Quebec Hydro, BC Hydro and Manitoba Hydro have experienced similar failures over the last 25 years. Most utilities worldwide have programs in place to replace airblast circuit breakers.

The identified work within this investment includes replacement of 20 - 230 kV ABCB's with new SF6 breakers and associated replacement of insulators on 24 high voltage breaker disconnect switches and 25 high voltage Instrument transformers.

Results:

• Reduce the operational risks, minimize life cycle costs, reduce regulatory requirements (TSSA). • Improve the bulk system equipment availability indices and the reliability of supply to area customers.

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Hydro One Networks – Investment Summary Document

Investment Category: Sustaining Capital - Stations - System Re-Investment

S7 Nanticoke TS: Air Blast Circuit Breaker (ABCB) Re-Investment

$35.0 M Mid 2011

Need:

This investment is required to replace end of life Air Blast Circuit Breakers (ABCB's) and other end of life station components, and de-merge Hydro One assets from the Ontario Power Generation (OPG) facilities. If this work is not completed, there is significant risk of the decline in the health and reliability of the ABCB population and associated End of Life (EOL) components, and reduced system reliability and customer reliability in the area.

Summary:

Originally built in the early 1970’s, Nanticoke TS is a station that facilitates bulk power transfers on the 500 kV and 230 kV network, and connects 4000 MW of coal-fired generation at Nanticoke GS. There are three 500 kV and six 230kV circuits connected at Nanticoke TS. The 230 kV breakers at Nanticoke TS are approximately 35 years old, partially rebuilt in the mid-1990’s and are no longer supported by the original equipment manufacturer. The high-pressure air system was also partially refurbished to support the ABCB population. In addition to providing a major network path, the 230 kV circuits supply several load stations including Jarvis TS, Caledonia TS and large customers. As part of the Ontario Government’s coal replacement initiative, Nanticoke GS is planned to be shutdown in phases during the 2011 to 2014 period. Even without the Nanticoke generation, the transmission facilities at Nanticoke TS are required for ongoing system and customer load security.

Fourteen 230 kV ABCB’s, which are at end of life, will be replaced at Nanticoke TS with new SF6 breakers. The sole provider of spare parts for these ABCB breakers has indicated that they no longer support this breaker type. The 230 kV breakers at Nanticoke TS are unique within Hydro One in so far as the parts are not interchangeable with any other ABCB on the system.

End of life components within the 230 kV switchyard have been identified for replacement. These components include 34 High Voltage Switches, 27 High Voltage Instrument Transformers and the main AC/DC transfer schemes and switchgear. The 230 kV yard perimeter fence will also be replaced in order to address site security and safety issues. This investment will also enable a staged demerger from the common systems including AC station service and high-pressure air systems that are shared with OPG (230 kV only, as 500kV systems remain integrated with OPG).

Results:

• Reduce the operational risks, minimize life cycle costs, and satisfy regulatory requirements.

• The de-merger of the Hydro One assets from the OPG powerhouse will also be accomplished thereby reducing business liability and risk.

Project Classification per OEB Filing Guidelines:

(9)

Hydro One Networks – Investment Summary Document

Investment Category: Sustaining Capital - Stations - System Re-Investment

S8 Claireville TS - Replace 230 kV ‘ITE’ Gas Insulated Switchgear (GIS)

$122.7 M Late 2009

Need:

This investment is required to replace 230 kV ‘ITE’ gas insulated switchgear (GIS) and other equipment that is approaching end of life to minimize the life cycle costs, improve customer reliability through reconfiguration of the 230 kV supply circuits and to provide one new diameter and nine new breakers to accommodate new local generation and future network expansions.

Summary:

Claireville TS was originally built in the late 1970’s and has experienced system expansions during the 1980’s and early 1990’s. Claireville TS is at the electrical centre of Hydro One’s high voltage network and supplies 33% of the bulk system transfers between the 500 kV and 230 kV systems in the Greater Toronto Area (GTA). Claireville TS has 4 x 500 kV autotransformers, 16 x 500 kV GIS circuit breakers, 8 x 500 kV circuits, 17 x 230 kV GIS circuit breakers and 8 x 230 kV circuits. An asset condition and risk assessment determined that 6 x 230 kV GIS circuit breakers at Claireville TS had reached end of life and were prioritized from the entire population for replacement starting in 2006. The investments contained in this proposal primarily focus on the EOL 230 kV ‘ITE’ GIS power equipment assets and the required 230 kV system reconfigurations. In addition, investments are required to the integrated control, metering, relaying and annunciation (CMR&A) assets for both the 500 kV and 230 kV systems.

The 6 x 230 kV ‘ITE’ GIS first-generation breakers were installed in 1980. The GIS circuit breakers are at EOL due to spare parts unavailability, high maintenance costs, poor performance and technical obsolescence. The original equipment manufacturer ceased production of the ‘ITE’ breakers in the mid 1980’s and subsequently spare parts and technical support has become a significant issue. The first generation ‘ITE’ GIS is being phased out by all other similar sized utilities.

All major electrical faults at Claireville TS have the potential for widespread impact due to voltage “sags” and subsequent customer process disruptions. ‘ITE’ equipment outages due to SF6 gas leaks and major catastrophic failures are an issue in maintaining system reliability, minimizing customer impacts and mitigating health, safety and environmental risks.

With the Ontario Government’s Coal Replacement initiative, the GTA and its western boundaries are experiencing additional power demand which requires transmission system upgrades and new installations to accommodate the load and generation requirements. Claireville TS is a critical station to these areas and the proposed investments are essential to accommodate the future works without network constraints.

Results:

• Replacement of the EOL 230 kV ‘ITE’ GIS will reduce the operational risks, minimize life cycle costs, reduce maintenance and lessen health, safety and environmental concerns.

• Reconfiguration of the 230 kV circuits will improve the customer supply reliability, limit the available system fault levels as well as accommodate the upcoming transmission upgrades and new generation connections while maintaining the integrity and reliability of the system.

(10)

Hydro One Networks – Investment Summary Document

Investment Category: Sustaining Capital - Stations - System Re-Investment

S9 Gage TS – Replace End of Life Components $40.0 M Late 2012

This investment is required to optimize the life cycle costs of Hamilton Gage TS by reducing the operating and maintenance expenditures and the outage requirements through integration of the component replacement programs in order to maintain the current load base through load retention initiatives, to address the safety and maintenance issues and to improve the security to the 115 kV area supply.

Implications of not proactively managing the end of life issues of Transmission facilities include increased risk to employees to known deficiencies, an increase in customer complaints, and a decline in reliability.

Summary:

Hamilton Gage TS is a complex facility and unique in its configuration. The station is comprised of an original switchyard built in the 1940’s, with a further capacity increase in the 1960’s. The site is located in the heart of a highly industrial setting with close proximity to a number of steel mills and other heavy industry. The station is supplied by four 115 kV 60 Hz network circuits and two 115 kV 25 Hz radial circuits from Niagara area generation. The transformation load station supplies critical steel industry load.

An asset condition and risk assessment has determined that many of the assets currently utilized at this station are at or near end of life. Included in this population of assets are the transformers, insulators, switches, surge arresters, breakers, station service and protection schemes. The low voltage oil circuit breakers have been prioritized from the entire provincial population as being in the worst condition. Operating restrictions are currently in place on the circuit breakers due to their operating ratings and the available fault current concerns that could cause the breaker to fail catastrophically. The need for reinforced and corrective maintenance has been increasing in recent years. With the increasing failure rates the time from defect identification to repair completion is increasing primarily due to the accessibility of spare parts and the outage restrictions imposed by the load customers and the system. Much of the low voltage equipment has insufficient safe working clearance to facilitate routine maintenance.

There is a very restricted window during short periods in the year when outages can be arranged in order to facilitate load transfers to neighboring stations. Repair and preventative maintenance work has to be delayed for several months before an outage can be arranged which increases the risk of cascading failures due to multiple failures. Pollution from environmental contaminants has an extreme negative impact on the operability of the equipment. Electrical flashover due to high levels of pollution is common. Atmospheric corrosion degrades the equipment protective coatings and allows the ingress of moisture. The operating costs exceed those expected of a similar sized facility. The lead and execution time of any investment will be significant (estimated at >50% longer) due to the complexity of the station layout and the outage restrictions.

Included in the work is refurbishment of the end of life station components, installation of new transformers, and reconfiguration of the 115 kV supply circuits.

Results:

• Reduce the operational risks, minimize life cycle costs, reduce regulatory requirements (TSSA) • Improve the bulk system equipment availability indices and the reliability of supply to area customers.

Project Class: Sustaining Project Need: Non-Discretionary

(11)

Hydro One Networks – Investment Summary Document

Investment Category: : Sustaining Capital - Stations – Power Transformers

S10 Birmingham TS - Replace EOL Large Transformers T2/T3

$8.2 M Mid 2010

Need:

This investment is required to replace the end-of-life (EOL) equipment at Birmingham TS. The EOL equipment includes the T2 and T3 transformers, transformer rod gaps, high voltage (HV) switches, auto ground switches and, cap and pin insulators.

If this work is not completed, there is significant risk of transformer failure that may cause: (1) increased risk of customer impact, (2) potential high cost corrective action after a catastrophic failure, (3) reduced

availability and increased operational constraints.

Summary:

Birmingham TS is located in Hamilton. It has a peak loading of 98 MVA and is connected to 115 kV circuits HL3 and HL4 through four transformers. TI and T2 operate as a pair, and T3 and T4 operate as another pair supplying a local distribution company and local industrial customers. TI is 35 years old and T2 is 41 years old. They are both 75 MVA 115/14/14 kV units. T3 is a 48 year old, 66 MVA 11 5/14/14 kV unit and T4 is a 12 year old 75 MVA 1 15/14/14 kV unit.

EOL for power transformers is typically between 40 to 60 years. In addition to its advanced age, outages for T2 average 1.4 / yr, which is more than 5 times the provincial norm and unavailability averages 43 hrs/yr, which is more than 1.5 times the norm. As well, T2 undergoes more frequently scheduled maintenance due to a known tap changer deficiency associated with Pioneer manufactured transformers. In addition to its advanced age T3 is a sister unit to the former Birmingham T4 which was replaced after a failure in 2006. Insulation deterioration consistent with carrying heavy loads over 45 years was found during tear down of the failed T4 unit. The T3 unit is expected to be in similar condition to the former T4 as it is the same design and it is operating under the same operating conditions.

These replacements are consistent with the current Asset Management Strategy to manage an aging transformer fleet through programmed replacements based on asset performance and condition information.

Results:

• Reduce operational risks and life cycle costs.

• Improve bulk system equipment availability and the reliability of supply to area customers.

Project Classification per OEB Filing Guidelines:

(12)

Hydro One Networks – Investment Summary Document

Investment Category: Sustaining Capital - Stations – Power Transformers

S11 Elgin TS – Replace EOL Large Transformers T3/T4 $10.3 M Late 2010

Need:

This investment is required to replace End-of-Life (EOL) equipment at Elgin TS including T3 and T4 transformers and associated equipment.

If this work is not completed, there is significant risk of transformer failure that may cause: (1) load interruptions, (2) high corrective costs, (3) increased operational constraints and (4) adverse environmental effects.

Summary:

Elgin TS is located in downtown Hamilton. It is fed by 115 kV underground cables HL3/HL4. It consists of 2 – 33 MVA 115/14 kV transformers T3/T4, 2 – Grounding Transformers GT3 /GT4, 2 – 75 MVA 115/14/14 kV transformers T1/T2, plus associated HV and LV switchgear. Elgin TS is the main supply point for the downtown Hamilton load.

Elgin T3/T4 are English Electric units built in 1956. Condition assessment test (DGA and furan analysis) show that the insulation in these transformers is reaching its EOL. These transformers were first installed at Strachan TS in 1956. It was known then that the transformers in this family could not withstand full vacuum. Elgin T4 failed at Strachan in 1980 following several gas accumulation alarms. Both units were replaced at Strachan and moved into the Central Maintenance Shop in 1982. They were then installed at Elgin in 1985. Since then the numerous gas accumulation alarms incidents have continued. So far, they have been false alarms caused by air ingress. Numerous modifications have been over the life of these transformers to deal with these alarms. An on-line Hydrogen monitor is presently installed on T4 supervising the gas accumulation alarm.

Results:

Project Classification per OEB Filing Guidelines:

(13)

Hydro One Networks – Investment Summary Document

Investment Category: Sustaining Capital - Stations – Power Transformers

Reference # Investment Name Gross Cost In-Service

Date

S12 Leaside TS - Replace EOL Transformers T19, T20 and T21

$10.2 M Late 2009

Need:

This investment is required to address replace End-of-Life (EOL) equipment at Leaside TS including T19, T20 and T21 transformers, associated transformer protections and all cap and pin insulators in the transformer zone.

If this work is not completed, there is significant risk of transformer failure that may cause: (1) increased risk of customer impact, (2) potential high cost corrective action after a catastrophic failure, (3) reduced availability and increased operational constraints.

Summary:

Leaside TS is located in the city of Toronto. T19/T20/T21 operate in parallel and are unique, non-standard, 83 MVA 230128114 kV units which supply THES. In the summer of 2007, an on line monitor on T21 indicated an increasing trend in the build up of internal fault gasses. An internal inspection confirmed that T21 should be replaced and off-loaded. T21 is presently available for emergency use only.

EOL for power transformers is typically between 40 to 60 years. TI9 and T20 are 49 years old and T21 is 46 years old. Transformer population demographics coupled with condition assessments indicate that failure rates are expected to increase among all transformer groups due to natural insulation degradation found on both failed sister units. Both transformers suffered internal winding failures.

This plan includes the replacement of associated transformer protections and all cap and pin insulators in the transformer zone.

Results:

Project Classification per OEB Filing Guidelines:

(14)

Hydro One Networks – Investment Summary Document

Investment Category: Sustaining Capital - Stations – Power Transformers

S13 Glengrove TS - Replace EOL Transformers T1/T4 $6.4 M Late 2009

Need

:

This investment is required to address replace End-of-Life (EOL) equipment at Glengrove TS including TI and T4 transformers, their associated protections and redundant GT2 and GT4 grounding transformers. If this work is not completed, there is significant risk of transformer failure that may cause: (1) increased risk of customer impact, (2) potential high cost corrective action after a catastrophic failure, (3) reduced availability and increased operational constraints.

Summary

:

Glengrove TS is located in the City of Toronto and was built in the 1950's. It has a peak loading of 63 MVA and it is connected to 115 kV circuits DY6 and L2Y through four 33 MVA transformers. TI and T3 operate as a pair and supply Toronto Hydro (THES) A1 - A2 busses. T2 and T4 operate as another pair and supply THES A5-A6 busses.

EOL for power transformers is typically between 40 to 60 years old. TI is 50 years old and T4 is 54 years old. The EOL condition of these transformers is confirmed by the severe insulation degradation found on two sister units to these transformers (T2 and T3), which previously failed and were replaced in 2006 and 2003. Both transformers suffered internal winding failures.

This plan also includes the removal of redundant oil filled grounding transformers GT2lGT4 as the new transformers are equipped with standard secondary neutral reactors for grounding purposes. Other than protection changes due to the removal of grounding transformers, no other upgrades are required.

Results:

Project Classification per OEB Filing Guidelines:

(15)

Hydro One Networks – Investment Summary Document

Investment Category: Sustaining Capital – Stations – Power Transformers

S14 Woodroffe TS – Replace EOL Transformers T1/T2/T3/T4 $12.5 M Early 2010

Need:

This investment is required to replace End-of-Life (EOL) equipment at Woodroffe TS including TI, T2, T3 and T4 transformers, transformer rod gaps, high voltage (HV) switches and insulators, existing transformer low voltage power cables and protections. Install transformer spill containment and sound barrier; remove grounding transformers GTlI GT21 GT31 and GT4 that become redundant as new transformers are equipped with secondary neutrals for grounding purposes.

Delaying the replacement of these EOL transformers results in an unacceptable risk of a transformer failure which may cause: load interruptions, high corrective costs, increased operational constraints and adverse environmental effects.

Summary:

Woodroffe TS is located in Ottawa and was built in the 1950's. It has a peak loading of 40 MVA and is connected to 115 KV circuits C7BM and F1OMV through four 33 MVA transformers. T1 and T2, which are operated as a pair, and T3 and T4, which are also operated as another pair. Each pair supplies two separate busses. EOL for power transformers is typically between 40 to 60 years. TI and T2 are both 49 years old whereas T3 and T4 are 53 and 51 years old respectively. All four transformers are leaking, exhibit excessive vibration and are very noisy. In addition, post mortems conducted on failed units, similar to the T1 and T2 units, indicate significant insulation degradation. T4's tapchanger is not compatible with T3 and therefore cannot be operated in parallel. T4 is used only as a back-up supply in case of a T3 failure. T3 has no self-cooled rating and must be removed from service upon a sustained interruption to the AC station service supply. The transformer breakers and bus tie breakers are housed as indoor metalclad switchgear and were refurbished in the1990's, to extend their life expectancy by 10- 15 years.

Ottawa Hydro's (OHEC) metalclad facilities (feeder breakers, switches and metering) are located in a separate building and are scheduled for replacement in the 2010 timeframe. There is no spill containment under the existing transformers. An oil spill resulting from a transformer failure could flow directly into an adjacent school yard and/or the city sewer system. A school adjacent to the site has formally complained about the noise. A noise study done in response to the complaint recorded noise levels above those allowed under Ministry of the Environment limits (NPC-205).

Results:

Reduce the risk of equipment failure by replacing four EOL Woodroffe TIT2/T3/T4 transformers with two standard 75 MVA 115/14/14 kV units. This is the smallest standard transformer size equipped with dual secondary windings to enable connection to the two OHEC metalclads. The increased capacity will also meet the needs of the load area for the foreseeable future as load growth. EOL transformer rod gaps with surge arresters, EOL HV switches and LV power cables and transformer protections will also be replaced. Adding spill containment and upgrading noise barriers will reduce potential environmental impacts.

Project Classification per OEB Filing Guidelines:

(16)

Hydro One Networks – Investment Summary Document

Investment Category: Sustaining Capital - Stations – Power Transformers

S15

Richview TS - Replace EOL Transformers T7/T8

$9.5 M Late 2010

Need:

This investment is required to replace End-of-Life (EOL) equipment at Richview TS including transformers T7 and T8.

If this work is not completed, there is significant risk of transformer failure that may cause load interruptions, high corrective costs, increased operational constraints and adverse environmental effects.

Summary:

There are 3 DESN stations on the Richview TS site: T1/T2 125 MVA 230/28/28 kV dating from 1969, T5/T6 125 MVA 230/28/28 dating from 1989 and T7/T8 83 MVA 230/28 kV dating from the late ‘50s. T7 was built in 1956, T8 in 1959. Both units are leaking oil. They are not equipped with spill containment. While T7 was undergoing refurbishment work, cracked pressure plates were found on all 3 phases. It appeared that these cracks were not recent. Replacing the cracked pressure plates cannot be done in the field. The refurbishment work has been scaled back in anticipation of the replacement of this unit. The unit will be returned to service and an on-line monitor will be connected to T7 to observe the gas in oil levels on a continuous basis. T8 has a cracked headboard that is also not field repairable.

Two alternatives are being considered to mitigate the problems with T7 and T8: 1) Like-for-like replacement of Richview T7/T8 or 2) Increase transformation capacity by replacing T7/T8 with 2 – 125 MVA 230/28/28 kV units. In addition, associated EOL equipment will be replaced and spill containment will be installed on T7 and T8.

Results:

Project Classification per OEB Filing Guidelines:

(17)

Hydro One Networks – Investment Summary Document

Investment Category: Sustaining Capital - Stations – Power Transformers

S16 Kingsville TS - Replace EOL Transformers T1, T2 and T4

$8.3 M Late 2010

Need:

This investment is required to replace End-of-Life (EOL) equipment at Kingsville TS including TI, T2 and T4 transformers, their associated protections and redundant GT1 and GT2 grounding transformers.

If this work is not completed, there is significant risk of transformer failure that may cause: (1) increased risk of customer impact, (2) potential high cost corrective action after a catastrophic failure, (3) reduced availability and increased operational constraints.

Summary:

Kingsville TS is located in South Western Ontario, in the outskirts of Leamington. It is connected to K2Z and K6Z from Kent and Lauzon. There are 4 stepdown transformers: T1/T2/T3/T4 and 2 grounding transformers: TG1/TG2 at Kingsville TS. The station is heavily loaded.

Kingsville T2 is a CGE transformer built in 1952. T4 is a Canadian Westinghouse transformer built in 1951. T2 was installed at Crowland TS from 1953 to 1968 and moved to Guelph Cedar TS in 1969 before arriving at Kingsville in 1979. T2 has a long history of off-load and underload tap changer problems and failures. T2 is also not suitable for vacuum. T4 was installed at Bathurst TS in 1953 and then moved to Kingsville in 1970. Two sister units to the T2 transformer have already failed at Essex TS in the last few years. Furthermore, condition data (furan levels) on both T2 and T4 show significant insulation degradation.

T1 is in better condition than T2 & T4. However, replacement is advisable at this time due to station congestion, the removal of the grounding transformers and the heavy load at the site. The existing T3 transformer will remain in-service.

Results:

(18)

Hydro One Networks – Investment Summary Document

Investment Category: Sustaining Capital - Stations – Power Transformers

S17 Purchase New 230 kV 400 MVA Regulator for Sir Adam Beck TS

$5.2 M Late 2010

Need:

To provide a new 230 kV, 400 MVA regulator to replace the failed unit at Beck TS.

Not proceeding with this investment will increase risks to customer supply reliability and system security.

Summary:

There are 2- 400 MVA 230 kV Regulators in the Beck TS 230 kV Switchyard. These units support the interconnection with New York State. These regulators are unique in the HONI system. There are no spares in inventory to replace a failed unit. R76 is an English Electric unit built in 1960. R76 failed on January 30, 2008. An internal inspection was conducted on February 8, 2008. Severe winding damage was found. It was determined that the unit could not be repaired in the field. Arrangements were made for a more detailed inspection by a manufacturer to determine whether this unit could be re-built. This inspection took place on February 29, 2008 and the unit was deemed not to be economically repairable.

Results:

To restore the regulation required at the inter connection with New York state.

Project Classification per OEB Filing Guidelines:

(19)

Hydro One Networks – Investment Summary Document

Investment Category: Sustaining Capital - Stations – Power Transformers

S18 Purchase Spare 750 MVA Autotransformer $7.6 M Late 2010

Need:

This investment is required to purchase one new 750 MVA, 500/230 kV autotransformer to ensure an optimal number of spares are in the inventory for power system restoration following a failure.

Summary:

750MVA, 500/230 kV autotransformers are a major component of the Hydro One bulk transmission system and connect the 500 kV system to the 230 kV system. An autotransformer failure has significant implications on transmission capability and system security and may prompt generation to be re-dispatched to keep system loading within limits leading to higher market prices. In extreme situations load may have to be curtailed.

Hydro One's transmission network has thirty, three phase 750 MVA, 500/230 kV autotransformers. Based on Hydro One's autotransformer population, the Class 1 failure rate (where the unit suffers non-repairable damage or a lengthy off site repair) for these types of transformers is about 0.01 / per year. Based on this failure rate, the size of Hydro One's autotransformer fleet and repair times, risk assessment studies recommend that Hydro One increase the number of available spare autotransformers from one to two.

Results:

Maintain spares inventory of 750 MVA, 500/230 kV autotransformers to necessary levels.

Project Classification per OEB Filing Guidelines:

(20)

Hydro One Networks – Investment Summary Document

Investment Category: Sustaining Capital - Stations – Power Transformers

S19 Purchase Three (3) Spare 83 MVA Transformer $6.8 M Early 2010

Need

:

To provide adequate spare coverage for timely replacement in the event of a severe failure within the 83 MVA 115 kV and 230 kV transformer group. This investment will bring the inventory of spares in this group to the optimum level as determined by risk analysis.

Summary:

The purpose of this investment is to purchase three new 83 MVA transformers as operating spares.

A spare 83 MVA 230/28 kV Transformer and a spare 83 MVA 115/44 kV Transformer will cover a transformer group of 16 units installed in 7 stations feeding loads located in Georgian Bay and along the Eastern shore of Lake Ontario. The third transformer is a non-standard 230-28-14 kV unit for use at Leaside TS in the GTA. This transformer is more expensive because of the special engineering, construction, type testing and commissioning required at the factory.

A probabilistic cost/risk analysis model, consistent with industry standards, has been used to determine the optimum number of spares required for each group. This analysis takes into consideration several factors such as demographics, failure rate and repair/replacement time.

Results:

To provide adequate spare group coverage and level of customer service in the event of a transformer failure.

Project Classification per OEB Filing Guidelines:

(21)

Hydro One Networks – Investment Summary Document

Investment Category: Sustaining Capital – Stations – Other Power Equipment

S20 2009/2010 Low Voltage Capacitor Bank Replacements $7.7 M Late 2010

This investment is required to address the condition of low-voltage (LV) capacitor banks at end of life, in order to optimize the life cycle costs of this population of assets.

Implications of not proactively managing this population of capacitor banks include the decline in the overall health, reliability, and deterioration in equipment availability. This would result in reduced system voltage support and customer power quality, as well as increase in the potential for an environment and/or safety impact in the event of failure.

Summary:

Capacitor banks are static devices that provide a source of capacitive reactive power for the transmission system. The primary purpose of capacitor banks is to improve the power factor and provide the necessary voltage support needed for efficient power transmission and customer power quality. A capacitor bank is made up of several capacitor units connected together in an appropriate series-parallel arrangement, which can range from 9 to 216 capacitor units depending on rating and design of LV capacitor banks. Each capacitor unit consists of two conductive plates with a dielectric material in between, where the distance between plates and type of dielectric material determines the amount of capacitance produced.

With the increasing need to provide voltage support and improve customer power quality, the LV capacitor bank population has increased by 20 banks over the past five years. There are now a total of 283 LV capacitor banks in-service throughout the transmission system. Overall the capacitor bank population is in good condition. The average age of the LV capacitor bank population is 15 years. Typical manufacturer's life expectancy is approximately 30 years. The need to replace capacitor banks is based on age, condition, operability, capability and criticality to the system. This assessment takes into consideration that end-of-life for a capacitor bank can be defined by either deterioration of individual capacitor units or by general deterioration of structure, insulators, fuses and capacitor units.

The units in this program are externally fused capacitor design, which are prone to explosive failures resulting in potential safety and environmental concerns. They have a history of leaking & bulging cans and have exhibited numerous hot spots. All three capacitor banks also show signs of corrosion that will lead to further deterioration and failures if the banks are not replaced.

Results:

The replacement of the low voltage capacitor banks will maintain overall health and performance of the capacitor bank population by replacing end-of-life capacitor banks in accordance with Hydro One Standards and improve the availability of reactive power for voltage support and improve customer power quality.

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Hydro One Networks – Investment Summary Document

Investment Category: Sustaining Capital - Stations – Other Power Equipment

S21

_{2009/2010 Station Cap and Pin Insulator}

Replacements

$11.6 M

Late 2010 Please see Exhibit D1, Tab 3, Schedule 2 for cash flows.

Need:

There are approximately a total of 96,000 cap and pin insulator stacks installed at many older Hydro One stations. Cap and Pin insulators form the majority of the station insulator population. Normal end of life for insulators is 30-50 years. Due to their design Cap and Pin insulators are prone to cement growth from moisture absorption resulting in premature failures. Cap and Pin insulators historically fail during movement of the switching device they support when cracks or loose caps cause the insulator to fail. This constitutes a safety hazard to personnel conducting switching below the device.

Not proceeding with this investment would allow increased risk to customer supply reliability and safety hazards to personnel. The number of units replaced yearly should equal or outpace the rate of units reaching end of life

Summary:

Station insulators perform essential roles in the power system. They are designed to mechanically support and electrically insulate the station equipment. The integrity of these insulators ensures station equipment can perform its duties under all conditions. When the mechanical and electrical integrity of the insulator is compromised due to cracking caused by premature or normal end of life, the equipment it supports is subjected to risk due to lack of adequate insulation.

Cap and Pin insulators are one of the oldest designs of insulators installed within the electrical system. These insulators are affected by a common condition referred to as cement growth. Moisture expands the cement used to bond the insulator skirts. This cement expansion causes cracking in the porcelain which reduces the mechanical strength of the insulator. Deterioration of mechanical strength causes the metal cap to separate from the porcelain either suddenly, or during mechanical loading resulting in possible catastrophic failure of the equipment they support. Safe operation of the equipment and personnel / public safety is compromised when this occurs.

Results:

• To improve reliability and system performance.

Project Classification per OEB Filing Guidelines:

(23)

Hydro One Networks – Investment Summary Document

Investment Category: Sustaining Capital – Stations – Protection, Control, Monitoring and

Telecommunications

S22 Replace Protection & Control Systems - Pickering NGS A $23.7 M Late 2010

Need:

On April 9th, 2006 a fire was detected in the bottom of a cable trench in the Pickering NGS A switchyard relay building. Approximately 125 to 150 cables serving both the A and B protection systems were damaged. Cable fire experts have advised the insulation on all the cables that were subjected to the heat of the fire will now rapidly deteriorate. New failures and arcing can be expected. In fact, arcing was heard in two cables which were being moved as part of the original assessment of damage and all cable movement was halted. There are two immediate concerns:

• First, both the A and B group protection systems on the Unit 1-2 ring bus can no longer be considered reliable. An uncleared fault on this bus would cause a widespread blackout.

• Second, there is risk that a fire could re-ignite. The section of cable trench that suffered the fire also contains some protection cables for the Unit 3-4 ring bus and the telecom cables for the Pickering B switchyard. Another fire in this location would disable the entire Pickering site.

Temporary measures are in place to address these two issues.

Summary:

This investment will implement a permanent solution. The existing damaged relay building will be replaced with two new fully separated relay buildings in accordance with NPCC standards. One building will contain the A protection scheme and one will contain the B protection scheme. The cutover from the existing to the new buildings has been deterred to coincide with a future Unit 1 outage, which is expected to occur in 2010.

The work under this program includes:

• New cable trenches and new cable will be installed in the switchyard.

• Two new relay buildings will be built installed and commissioned.

• Existing relay building will be retained for asset aging research.

• Telecommunication for Pickering A and B protections will be re-routed.

Results:

• Will address reliability and safety concern at the Pickering NGSA switchyard.

Project Classification per OEB Filing Guidelines:

(24)

Hydro One Networks – Investment Summary Document

Investment Category: Sustaining Capital – Stations - Protection, Control, and Metering

S23 2009 – 2010 Station P&C Replacement $24.7 M Late 2010

Need:

Hydro One has identified 6 load supply stations at which most of the P&C systems have reached end of life as determined by asset condition assessment. Replacement of these systems must take place with the next five years in order to avoid growing rates of failures which will result in deteriorating supply reliability from these stations.

Summary:

All protection and control systems for load supply stations are generally housed in a single building. Hydro One has developed a standardized design whereby the entire building is replaced with all protection and control racks pre-built, installed and wired at the factory. For cases where most of the components in the protection systems are at end of life, it is more cost effective and simpler from the perspectives both of design and staging into service to replace the entire relay building using this standard design rather than replace individual components.

Results:

To maintain reliability at customer supply stations.

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Hydro One Networks – Investment Summary Document

Investment Category: Sustaining Capital – Stations – Protection, Control & Monitoring

S24 2009/2010 RTU Replacement $12.4 M Late 2010

Need:

Remote Terminal Units (RTUs) are essential components for the central operation of the transmission network. The RTU provides remote monitoring and operational control of all transmission stations to the Ontario Grid Control Center (OGCC). The RTUs are also used to provide telemetry to the Independent Electricity System Operator (the IESO) and transmission-connected customers in accordance with the obligations of the Market Rules and the Transmission System Code respectively. The Market Rules provide specific performance levels for data accuracy, update time, and restoration upon failure.

A population of 160 RTUs have reached or are reaching end-of-life by 2011, as validated by condition assessments. Reliability of this population has failed to meet the Hydro One requirements and/or Market Rule target of one failure every 3 years. The failure rates are presently one failure every 1½ years and show a trend of decreasing reliability. Failure of an RTU results in complete loss of monitoring and control of a station. The consequences of this include delayed or no response to equipment alarms, delayed restoration of customer outages, delayed switching for planned work, and bottling of generation. There is no vendor support or supply of spare parts for these RTU’s.

Not proceeding with this work will expose Hydro One to large numbers of concurrent failures that would overwhelm available expert maintenance resources. The direct result would be serious reduction in the reliability of the assets, negative customer impacts, reduced operability, and numerous breaches of Market Rules.

Summary:

This investment is the continuation of the RTU Replacement Program. The program is focused on the 160 RTU’s that are reaching end of life and for which there is no redundancy. Sustainability modeling of this population demographics with known end of life failure rates has shown that, in order to keep ahead of accelerating failure rates and avoid engineering and maintenance resources being overwhelmed by failures, replacements must proceed at the rate of at least 40 RTU’s per year. The program was originally designed to achieve the replacement in 4 years by the end of 2011. Work capacity constraints require this risk to be weighed against the risks associated with deferral of other projects in contention for the same expert resources. The result of this risk balancing is a program to achieve completion by end of 2014. 7 RTU’s will be replaced in 2009 and 32 in 2010

Results:

• Maintain the required functionality and reliability of monitoring and control systems.

Project Classification per OEB Filing Guidelines:

(26)

Hydro One Networks – Investment Summary Document

Investment Category: Sustaining Capital – Stations – Cyber Security

S25

_Cyber

_Security

_{Readiness – Systems Management}

$23.1 M Mid 2009

Need:

The Federal governments (Canada and the US) categorize the energy sector, including the power grid, as a critical infrastructure. To ensure the grid is adequately protected, the North American Electric Reliability Corporation (NERC) developed an initial set of eight new Critical Infrastructure Protection standards (CIP002-CIP009). Hydro One has a regulatory obligation under the Market Rules1 to comply with all the reliability standards adopted by NERC. HONI must be in compliance with the CIP requirements by end of Q2 2009.

Many of the new NERC CIP Standards2 impose a range of systems management requirements on Critical Cyber Assets (CCA’s). A CCA is a device or system that allows critical grid assets to be remotely controlled by dial-up, or over a computer network. Critical grid assets include transmission stations connecting major generation or interconnecting major transmission lines. NERC CIP systems management requirements include: the creation of electronic security perimeters and firewalls, access controls, malware detection, configuration change control, intrusion detection, incident logging, recovery capabilities, securing the technical information about the CCA’s as well as a personnel training program. Compliance with these Standards will require a number of new systems to be implemented as well as modification to existing systems at the OGCC, the back-up centre, the control hub sites, and selected other transmission stations where CCA’s reside. This investment will deliver these to enable Hydro One to be fully compliant with the NERC CIP Standards.

Summary:

This release will implement electronic security perimeters, authentication management, electronic access control and monitoring, personnel training and awareness programs, intrusion and malware detection systems, change and patch management testing facilities, vulnerability assessment capability, network reconfigurations and event data retention facilities required to achieve compliance with CIP 004, CIP 005, 007, 008 and 009 and enable additional assets to be secured to tightening standards at minimal incremental cost.

Results:

This investment will bring Hydro One into compliance with the requirements of the NERC CIP standards approved by the US Federal Energy Regulatory Commission (FERC) in Jan 2008.

Project Class:

Sustaining

Project Need:

Non-Discretionary

1

Chapter 5, Section 3.4.2

2

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Hydro One Networks – Investment Summary Document

Investment Category: Sustaining Capital – Stations - Cyber Security

S26 Cyber Security – Telecommunications Separation $22.3 M Late 2012

Need:

The Federal governments (Canada and the US) categorize the energy sector, including the power grid, as a critical infrastructure. To ensure the grid is adequately protected, the North American Electric Reliability Corporation (NERC) developed an initial set of eight new Critical Infrastructure Protection standards (CIP002-CIP009). Hydro One has a regulatory obligation under the Market Rules3 to comply with all the reliability standards adopted by NERC.

The existing NERC CIP standards explicitly exclude telecommunications facilities. In its review of the standards the US Federal Energy Regulatory Commission (FERC), stated dissatisfaction with the exclusion of telecommunications. It is expected that future revision of the standards will address this gap. Telecommunications do represent a significant vulnerability and Hydro One has determined that it is appropriate to begin work to close this gap as soon a possible.

Summary:

This release will implement separation of the systems that are used for monitoring and configuring Hydro One’s administrative telecommunications from those used for monitoring and configuring the Power System Telecommunications System (PSTS).

Results:

Significant vulnerability to the protection and control of the grid will be eliminated.