1 investment summary for · pdf fileare being replaced with new sf6 circuit breaker (cb)...

Filed: September 30, 2008 EB-2008-0272 Exhibit D2 Tab 2 Schedule 3 of 80

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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

Hydro One Networks – Investment Summary Document

Investment Category: Sustaining Capital – Stations - Circuit Breakers

Reference # Investment Name Gross Cost In-Service DateS1 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 Project Need: Non-Discretionary


Investment Category: Sustaining Capital – Stations - Circuit Breakers

Reference # Investment Name Gross Cost In-Service DateS2 2009/2010 Metalclad Circuit Breakers Replacement -

GTA $8.0 M Late 2010

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

Project Class: Sustaining Project Need: Non-Discretionary


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

Reference # Investment Name Gross Cost In-Service DateS3 Abitibi Canyon Switching Station (SS) and Pinard

Transformer Station (TS) - Replace EOL Components $20.2 M Late 2012

Please see Exhibit D1, Tab 3, Schedule 2 for cash flows. 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: Project Class: Sustaining Project Need: Non-Discretionary



Reference # Investment Name Gross Cost In-Service DateS4 Beck #1 SS: Air Blast Circuit Breaker (ABCB) Re-

Investment $35.0 M Late 2011

Please see Exhibit D1, Tab 3, Schedule 2 for cash flows. 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: Project Class: Sustaining Project Need: Non-Discretionary



Reference # Investment Name Gross Cost In-Service DateS5 Orangeville TS: Air Blast Circuit Breaker (ABCB) Re-


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



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

Reference # Investment Name Gross Cost In-Service DateS6 Beck #2 TS - Air Blast Circuit Breaker (ABCB) Re-


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.


Project Class: Sustaining

Project Need: Non-Discretionary



Reference # Investment Name Gross Cost In-Service DateS7 Nanticoke TS: Air Blast Circuit Breaker (ABCB) Re-

Investment $35.0 M Mid 2011

Please see Exhibit D1, Tab 3, Schedule 2 for cash flows. 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: Project Class: Sustaining Project Need: Non-Discretionary



Reference # Investment Name Gross Cost In-Service DateS8 Claireville TS - Replace 230 kV ‘ITE’ Gas Insulated

Switchgear (GIS) $122.7 M Late 2009


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.





Reference # Investment Name Gross Cost In-Service DateS9 Gage TS – Replace End of Life Components $40.0 M Late 2012

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




Investment Category: : Sustaining Capital - Stations – Power Transformers

Reference # Investment Name Gross Cost In-Service DateS10 Birmingham TS - Replace EOL Large Transformers

T2/T3 $8.2 M Mid 2010

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



Investment Category: Sustaining Capital - Stations – Power Transformers

Reference # Investment Name Gross Cost In-Service DateS11 Elgin TS – Replace EOL Large Transformers T3/T4 $10.3 M Late 2010

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

• Reduce operational risks and life cycle costs. • Improve bulk system equipment availability and the reliability of supply to area customers.




Reference # Investment Name Gross Cost In-Service Date

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

$10.2 M Late 2009

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





Reference # Investment Name Gross Cost In-Service DateS13 Glengrove TS - Replace EOL Transformers T1/T4 $6.4 M Late 2009


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: • 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: Project Class: Sustaining Project Need: Non-Discretionary


Investment Category: Sustaining Capital – Stations – Power Transformers

Reference # Investment Name Gross Cost In-Service DateS14 Woodroffe TS – Replace EOL Transformers T1/T2/T3/T4 $12.5 M Early 2010

Please see Exhibit D1, Tab 3, Schedule 2 for cash flows. 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: Project Class: Sustaining Project Need: Non-Discretionary



Reference # Investment Name Gross Cost In-Service DateS15 Richview TS - Replace EOL Transformers T7/T8

$9.5 M Late 2010

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





Reference # Investment Name Gross Cost In-Service DateS16 Kingsville TS - Replace EOL Transformers T1, T2 and

T4 $8.3 M Late 2010

Please see Exhibit D1, Tab 3, Schedule 2 for cash flows. 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: • Reduce operational risks and life cycle costs. • Improve bulk system equipment availability and the reliability of supply to area customers.





Reference # Investment Name Gross Cost In-Service DateS17 Purchase New 230 kV 400 MVA Regulator for Sir

Adam Beck TS $5.2 M Late 2010


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.




Reference # Investment Name Gross Cost In-Service DateS18 Purchase Spare 750 MVA Autotransformer $7.6 M Late 2010

Please see Exhibit D1, Tab 3, Schedule 2 for cash flows. 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. Not proceeding with this investment will increase risks to customer supply reliability and system security. 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.




Reference # Investment Name Gross Cost In-Service DateS19 Purchase Three (3) Spare 83 MVA Transformer $6.8 M Early 2010


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



Investment Category: Sustaining Capital – Stations – Other Power Equipment

Reference # Investment Name Gross Cost In-Service DateS20 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. Project Classification per OEB Filing Guidelines:



Investment Category: Sustaining Capital - Stations – Other Power Equipment

Reference # Investment Name Gross Cost In-Service DateS21 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.



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

Reference # Investment Name Gross Cost In-Service DateS22 Replace Protection & Control Systems - Pickering NGS A $23.7 M Late 2010

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



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


S23 2009 – 2010 Station P&C Replacement $24.7 M Late 2010 Please see Exhibit D1, Tab 3, Schedule 2 for cash flows. 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. Project Classification per OEB Filing Guidelines:



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

Reference # Investment Name Gross Cost In-Service DateS24 2009/2010 RTU Replacement $12.4 M Late 2010

Please see Exhibit D1, Tab 3, Schedule 2 for cash flows. 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: Project Class: Sustaining Project Need: Non-Discretionary


Investment Category: Sustaining Capital – Stations – Cyber Security

Reference # Investment Name Gross Cost In-Service DateS25 Cyber Security Readiness – Systems Management $23.1 M Mid 2009

Please see Exhibit D1, Tab 3, Schedule 2 for cash flows. 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 Classification per OEB Filing Guidelines:


1 Chapter 5, Section 3.4.2 2 CIP-003, CIP-004, CIP-005, CIP-007, CIP-008 and CIP-009


Investment Category: Sustaining Capital – Stations - Cyber Security


S26 Cyber Security – Telecommunications Separation $22.3 M Late 2012

Please see Exhibit D1, Tab 3, Schedule 2 for cash flows. 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. Project Classification per OEB Filing Guidelines:


3 Chapter 5, Section 3.4.2


Investment Category: Sustaining Capital - Stations - Ancillary Systems

Reference # Investment Name Gross Cost In-Service DateS27 2009/2010 Station Service Upgrades – Network Stations $16.6 M Late 2010


This investment is required to address the condition of the aging population of station service transfer schemes through replacement of those that present a high risk to system security and reliability. Failure to proactively manage this population will result in the inability to operate station equipment as a result of loss of AC or DC power. Summary:

Station service systems comprise all equipment necessary to provide AC or DC power to station facilities. The AC station service supplies power for transformer cooling, tap changer control, switchgear heating, battery chargers, HVAC, etc., all of which are essential to the provision of reliable power by the transmission stations and to connected loads. The DC station service supplies power for protection, control and communication systems, which protect and provide remote control of station equipment. In the event of a power supply failure, the station service transfer system is designed to enable the transfer of loads over to the second station service supply. If the transfer fails, transmission elements at the station could be forced out of service or de-rated. There are 96 – 600V AC station service transfer schemes and 59 - 125/250 V DC station service transfer schemes in-service, with average ages of 33 and 34 years respectively. The deterioration of the transfer schemes has been evident for several years. Restoring reliability to these systems through increased maintenance continues to be a challenge due to the lack of spare parts and inability to obtain replacement parts from the manufacturer. Further compounding the reliability issues, the AC transfer schemes are housed within poorly insulated outdoor cubicles and are deteriorating due to corrosion. The Hinchinbrooke TS and Hanmer TS transfer schemes have exceeded the manufacturers intended life expectancy of 30 years, and have experienced difficulties with the transfer capability both with switchgear and control. The upgrade will include the replacement of the station service transfer schemes at Hinchinbrooke SS (AC & DC) and Hanmer TS (AC). The equipment associated with the transfer schemes (LV fuses, cables, enclosures, and distribution panels) will also be addressed at both locations. This investment will result in installation of reliable transfer schemes that will mitigate the problems discussed above. Results:

The reliability of the station service transfer schemes will be improved by replacing end-of-life station service equipment. Project Classification per OEB Filing Guidelines:



Investment Category: Sustaining Capital – Stations – Ancillary Systems

Reference # Investment Name Gross Cost In-Service DateS28 2009/2010 Station Service Upgrades – Customer (DESN)

Stations $3.4 M Late 2010

Please see Exhibit D1, Tab 3, Schedule 2 for cash flows. Need: This investment is required to address the condition of the aging population of station service transfer schemes through replacement of those that present a high risk to system security and reliability. Failure to proactively manage this population will result in the inability to operate station equipment as a result of loss of AC or DC power. Summary: Station service systems comprise all equipment necessary to provide AC or DC power to station facilities. The 208 V AC station service supply provides the necessary power at DESN stations for transformer cooling, tap changer control, switchgear heating, battery chargers, HVAC, station lighting etc., all of which are essential to the provision of reliable power by the transmission stations to connected loads. In the event of a power supply failure, the station service transfer system is designed to enable the transfer of loads over to the second station service supply. If the transfer fails, transmission elements at the station could be forced out of service or de-rated. For example, when AC is lost to transformer cooling systems the transformer’s capacity is reduced and potential for customer interruption exists. The need to replace station service transfer schemes is based on a set of criteria (i.e. age, condition, criticality, parts availability, reliability, and operability). There are 179 – 208V AC station service transfer schemes in-service, with an average age of 22 years. In order to address the replacements over the expected in service life, an annual program of approximately 5 units a year is required. Through the assessment of condition and risks, five transfer schemes have been identified for replacement; Hinchey TS, Orillia TS, Sheppard TS, Stanley TS and Walker #1TS. These station service transfer schemes have an average age which exceeds the manufacturer’s life expectancy. The deterioration of the transfer schemes, while still within acceptable parameters, has been evident for several years. The condition of the equipment at these sites is deteriorated as field specialists have experienced difficulties with the auto-transfer capability of these systems not operating as designed. Restoring reliability to these systems through increased maintenance continues to be a challenge due to the lack of spare parts and inability to obtain replacement parts from the manufacturer. Further compounding the reliability issues, the AC transfer schemes are housed within poorly insulated outdoor cubicles and are deteriorating due to corrosion.

Results: The replacement of the 208 V AC station service systems will improve the reliability of the station service transfer schemes by changing out end of life equipment, ensure an adequate level of system security is maintained and ensure the performance of the station is not hindered by ancillary system unreliability. Project Classification per OEB Filing Guidelines: Project Class: Sustaining Project Need: Non-Discretionary


Investment Category: Sustaining Capital – Stations – Stations Environment

Reference # Investment Name Gross Cost In-Service DateS29 2009/2010 Spill Containment Refurbishment - Major $6.1 M Late 2010

Please see Exhibit D1, Tab 3, Schedule 2 for cash flows. Need: This investment is required to address the risk of releasing oil off site at various TS sites. This risk is present because the transformer oil spill containment system is at end of life and no longer provides adequate protection. Not proceeding with this investment will not address an unacceptable risk of releasing transformer oil into the environment, leading to negative environmental impact and potential regulatory action by the Ministry of Environment (MOE) under the powers of the Environmental Protection Act R.S.O. 1990, c. E. 19. Summary: Transformers contain large volumes (up to 240,000L) of insulating oil (PCBs are within allowable Environment Canada Standards). Periodically, transformers leak and or fail catastrophically releasing large volumes of oil. Spill containment systems are designed to capture the oil contained within one transformer on site. They also are designed to take into account significant accumulations or rain in the event of a severe rain storm. Oil water separators (OWS) are used to prevent spilled oil from leaving the station while allowing rainwater to drain offsite. The combination of leaking spill containment pits and severe transformer oil leaks present a serious environmental concern. Oil spill containment systems with chronic oil leaks have been identified within this project. The amount of oil that has leaked from the subject transformers is tracked using oil volume top-up records. Problems with traces of oil leaching into the drainage ditch are typically identified. It is suspected this is caused by a lack of integrity of the original plastic containment unit liners. Due to the inability of the containment pits to prevent oil from seeping into the soil below the containment units, oil can migrate from the failed pits into the station storm water drainage system. This is a serious problem as many TS’s are located immediate to adjacent tributaries. To prevent oil from entering the waterway, maintenance staff installs temporary berms to isolate the leached oil in the station’s drainage system. This investment covers the installation of a passive oil water separator as well as refurbishment of the existing containment pits. Refurbishing the spill containment system mitigates the risk of releasing oil to the environment and reduces resources required to operate the oil water separation units by eliminating the need to manually pump out the containment units of rain and melt water. Results: • Reduce the risk of off-site pollutant migration and subsequent impacts to the environment. • Minimize the potential for punitive action by the MOE as a result of oil spills and leaks to the

environment. Project Classification per OEB Filing Guidelines: Project Class: Sustaining Project Need: Non-Discretionary


Investment Category: Sustaining Capital - Lines - O/H Lines Component Refurbishment and Replacement

Reference # Investment Name Gross Cost In-Service DateS30 2009/2010 Transmission Wood Pole Replacement

Program $66.8 M Late 2010

Please see Exhibit D1, Tab 3, Schedule 2 for cash flows. Need: This investment is required to address end-of-life components of transmission wood pole structures in order to maintain their reliability and safety in a cost-effective manner. If this work is not completed, there is significant risk of structure failure during adverse weather conditions with associated risks to public safety and transmission system reliability. Since the majority of wood pole lines are single supply, component failures on these lines usually cause supply interruptions to customers. Summary: Approximately 21,000 route kilometers (or 28,000 circuit km) of overhead transmission lines have been built in the province over the past 100 years. The transmission line system includes approximately 88,000 steel and wood structures. The wood structure lines consist of about 7,000 route km which includes 41,900 wood pole structures. The majority of the wood pole structure population is located in Northern Ontario and typically is in remote locations with difficult access. Wood structures deteriorate over time; the rate of deterioration depends on age, location, weather, type of wood, treatment, insects and wildlife. As a result, uniform deterioration does not occur and the condition of wood structures varies, even in the same location. Wood components are replaced when their condition has deteriorated to a point where there is a significant risk of failure under adverse weather conditions. When component replacement work is carried out on wood structures, the crossarms, poles, hardware, insulators and guy wires are repaired or replaced as necessary. Replacement candidates are based on on-going condition assessment programs. Based on the condition assessment carried out to date, 1,650 structures have been identified for replacement and refurbishment work in 2009 and 2010. Asset condition assessment work includes detailed helicopter inspection (DHI) and ground line inspection. DHI assesses the upper area of wood structures and ground line inspection assesses the lower part of wood structures. Results:

• Maintain transmission system security and customer delivery reliability. • Reduce the risk of a major interruption of supply to customers. • Reduce safety hazards to the public from potential component failure. • Replace 1650 sub-standard structures that have reached end of life.




Reference # Investment Name Gross Cost In-Service DateS31 2009/2010 Steel Structure Coating Program $6.9 M Late 2010


This investment addresses the need to restore identified steel lattice towers to their original design requirements and to extend their service lives. Tower coating is used to cost effectively manage the life cycle of these structures. Not proceeding with this investment will result in further deterioration of the steel towers and eventually lead to advancing the replacement of towers at a substantially greater cost. Summary: Hydro One’s transmission system consists of about 21,000 route kilometers (about 28,000 circuit kilometers) of overhead transmission lines. The system is almost exclusively made up of overhead lines and a large part of the system is supported by approximately 47,000 steel structures. Hydro One’s steel towers are manufactured with a zinc-based galvanized coating that protects the underlying steel against corrosion. The coating will generally last from 30 to 60 years, with the more corrosive environments depleting the galvanizing at a quicker rate. Once the galvanizing has depleted, bare metal is exposed to the atmosphere and the steel will corrode at a rate up to 25 times faster than the galvanized coating. The accelerated corrosion of the base metal increases the risk of structural damage to tower members, which will eventually need to be replaced if left unchecked. Asset condition assessment is carried out on an annual basis with a focus on line sections with in-service dates greater than 30 years that are located in highly corrosive areas and in locations where known problems exist. The assessments determine the amount of galvanizing that remains on the structure, or in the case where the coating is depleted, the amount of metal loss that has occurred. Recent condition assessments have shown that 270 structures on several line sections have, to a large part, lost their galvanized coating and need to have the corrosion protection re-instated. Tower asset condition assessment is an ongoing program that requires field inspections with follow-up analysis to determine if any structural damage has taken place. Current detailed condition information and further analysis suggests that within the next 10 years, about 2,000 towers will need to have their corrosion protection re-instated in order to stem the deterioration of Hydro One’s steel towers. As such, tower coating will be an ongoing annual program which will coat 100 to 200 structures a year. The proposed 270 towers over two years are aligned with the annual requirements. Results:

• Apply the protective coating on the identified steel towers to ensure that their expected economic life is realized.

• Optimize the life-cycle costs of these 270 steel transmission towers. Project Classification per OEB Filing Guidelines:

Project Class: Sustaining

Project Need: Non-Discretionary



Reference # Investment Name Gross Cost In-Service DateS32 2009/2010 Shieldwire Replacement Program $8.8 M Late 2010


This investment is required to replace shieldwire that has reached end-of-life. Not proceeding with this investment will jeopardize system reliability, cause an increased number of customer interruptions, and will increase public and employee safety risks. Summary:

Hydro One’s transmission system consists of about 21,000 route kilometres (about 28,000 circuit kilometres) of overhead transmission lines. Almost all of these lines have shieldwire strung above the conductor to protect against lightning strikes and provide grounding continuity. The majority of shieldwire in Hydro One’s system is made of galvanized steel wire, whose protective zinc coating deteriorates over time. When the galvanizing corrosion protection has depleted, the underlying steel begins to corrode resulting in loss of metal, reduction in strength, and eventual failure of the shieldwire. When failure does occur, the broken shieldwire usually makes contact with the conductors before falling to the ground. To mitigate the risk of shieldwire failure, Hydro One has implemented an annual shieldwire-testing program which selects samples from line sections situated in corrosive environments that exhibit signs of deterioration and/or have a history of forced outages due to failed shieldwire. Shieldwire samples are removed and sent to a laboratory for ductility and tensile strength testing to gather additional data on its condition. If the test data for a particular shieldwire meets end-of-life criteria, then that shieldwire is replaced. Hydro One has established end-of-life criteria for shieldwire that considers Canadian Standards Association tensile strength requirements and Hydro One torsional ductility requirements. Shieldwire test results indicate that there are currently about 400 km of galvanized shieldwire that are close to end-of-life and will be scheduled for future replacement based on risk assessment. Therefore, it is estimated that future shieldwire replacement will need to average about 100 km per year for the next four years to replace shieldwire that has reached end-of-life. This investment proposes the replacement of 215 km of end of life shieldwire, 95 km during 2009 and 120 km during 2010. The length of replacement is determined by the length of the line section that needs to be addressed, as such replacement rates will vary to some degree form one year to the next. Results:

• Eliminate 215 km of the identified shieldwire that has reached end-of-life. • Maintain system security and customer delivery reliability. • Eliminate worker and public safety risks associated with shieldwire failures.





Reference # Investment Name Gross Cost In-Service DateS33 2009/2010 Transmission Lines Emergency Restoration

$13.0 M Late 2010

Please see Exhibit D1, Tab 3, Schedule 2 for cash flows. Need: These investments are required to maintain the reliability of the transmission lines system and ensure public and employee safety. Not proceeding with these investments would result in a significant reduction in reliability and increased reputation and regulatory risks, as well as an increase in public and employee safety risks. Summary: A number of transmission line components fail each year due to adverse weather, component deterioration, vandalism, or through accidents caused by public activity. These failures can cause unsafe conditions and create disruptions to the power system. A prompt response is required to restore the system to its normal state including restoration of customer load and eliminating unsafe conditions. This is a demand program needed to restore power following transmission line failures and to replace or repair those line components where there is an imminent danger of failure as identified through line patrols or asset condition assessment. This investment is essential to the operation of the transmission business though expedient response to failures and elimination of public and employee safety issues. Emergency work under this release includes the replacement of failed or defective transmission line components such as wood structures, wood crossarms, towers, insulators, conductor, shieldwire and hardware. Funding allocation is based on recent historic costs and it is estimated that $12.0 million will be required to address emergency work during 2009 and 2010. Results: • Maintain system and customer reliability by responding to transmission line emergency repair work in an

expedient manner. • Maintain public and worker safety by responding to unsafe conditions in a timely manner. Project Classification per OEB Filing Guidelines: Project Class: Sustaining Project Need: Non-Discretionary


Investment Category: Sustaining Capital - Lines - Transmission Lines Re-Investment

Reference # Investment Name Gross Cost In-Service DateS34 Conductor & Structure Replacement.

L1S – Coniston TS to Martindale TS $13.1 M Late 2009

Please see Exhibit D1, Tab 3, Schedule 2 for cash flows. Need: The L1S circuit between Coniston TS and Martindale TS is 11 km long with 55 double circuit steel transmission towers strung with a 266.8 kcmil ACSR 6/7 conductor and 3#5 copperweld shieldwire. All these components have deteriorated to the point where the strength and ductility characteristics are considered unacceptable. As the result, the existing double circuit steel transmission towers, shieldwire, and conductor need to be replaced.

Not making this investment will increase the probability of future line failures that will adversely impact the supply reliability to the customers and potential conductor failures will also create a risk to public safety.

Summary: Circuit L1S is located in what had been a very corrosive environment between Sudbury and Crystal Falls, and consists of 7 line sections totalling 93 km. The pre-1970 conductors on these line sections have been replaced with the exception of the line section between Martindale TS and Coniston TS. Upon an investigation, it has been confirmed that the conductors between Martindale TS and Coniston TS are severely corroded and require replacement. The conductors on this section of L1S are supported on double circuit towers with the potential to add another circuit.

This investment will consist of replacing the existing non-standard 266.8 kcmil ACSR conductor that has reached end of life with new 477 kcmil ACSR conductor between Coniston TS and Martindale TS. The 266.8 kcmil conductor was last installed in 1949 on the Hydro One transmission system. The 477 kcmil ACSR conductor is a standard type and delivers additional current carrying capacity by 50% and reduces line losses by about 45%. Furthermore, the insulators, shieldwire, and hardware on this line are also in poor condition and require replacement. Additionally, the steel structures have deteriorated to unacceptable levels, which also will need to be replaced. The proposed replacement work will return this section of line to an as-new condition. Results:

• Reduce safety hazards to the public from potential component failures of the transmission line. • Maintain and improve customer delivery reliability and voltage performance. • Improve energy efficiency by reducing line losses.



Investment Category: Sustaining Capital - Lines - Transmission Lines Re-Investment

Reference # Investment Name Gross Cost In-Service DateS35 Conductor & Structure Replacement

P3S – Port Hope Jct. to Sidney TS $25.5 M Late 2010

Please see Exhibit D1, Tab 3, Schedule 2 for cash flows. Need: This investment is required to address the condition of the conductors and shieldwire on the 115 kV circuit P3S from Port Hope Jct to Sidney TS (60.1 km). The conductor and shieldwire have deteriorated to the point where the strength and ductility characteristics are below established criteria determining end of life. Furthermore, this investment addresses anticipated load growth on P3S over the next 10 years. Not making this investment will increase the probability of future line failures that will adversely impact the supply reliability to a number of industrial and residential customers in the Belleville, Port Hope, and Trenton Regions. Conductor failures will also create a risk to public safety. Summary: Conductors are a critical element of a transmission line. Conductors with loss of ductility in the steel strands are susceptible to failure from movements caused by wind, ice and changes in conductor tension. The conductor on P3S from Port Hope Jct to Sidney TS is 78 years old. Conductor tests reveal that the tensile strength and ductility has deteriorated to an extent that the conductor is at end of life. Furthermore, the insulators, hardware and shieldwire on this line are also in poor condition and require replacement. Additionally, some wood poles have deteriorated to unacceptable levels and will need to be replaced.

This investment will consist of replacing the existing 477 kcmil ACSR conductor with new 732 kcmil conductor on the 60.1 km section of line between Port Hope Jct and Sidney TS. The 732 kcmil compact conductor is a readily available modern standard conductor that is adequate for replacement of the existing conductor while delivering additional current carrying capacity and reducing line losses by about 35%. In addition to conductor and shieldwire replacement between Port Hope Jct and Sidney TS (60.1km), end of life shieldwire will be replaced on the companion circuit P4S between Port Hope Jct to Hilton Jct. Proposed refurbishment work will return this section of line to a near-new condition and will also meet future load growth demands

Results:

• Reduce safety hazards to the public from potential component failures of the transmission line. • Maintain and improve customer delivery reliability and voltage performance. • Improve energy efficiency by reducing line losses.



Investment Category: Sustaining Capital - Lines - UG Cables Component Refurbishment and Replacement


S36 H3L Underground Cable Replace Project $4.3 M Early 2009

Please see Exhibit D1, Tab 3, Schedule 2 for cash flows. Need: The 115 kV gas pressurized underground transmission cable that runs from Gerrard TS to Bloor Street Junction (1.8 km) in downtown Toronto, needs to be replaced due to an aging, obsolete and problematic design. Failure to proceed with this investment could lead to future reliability and supply issues to the downtown Toronto area. Summary: The H3L underground cable circuit between Gerrard TS and Bloor Street Junction was installed in 1952 as a high-pressure gas-filled pipe type cable. The installation consists of three oil impregnated paper insulated phase conductors with a lead covering that are contained within a 6.25" (159 mm) diameter steel pipe. This cable is paralleled and directly tied with H3L Cable 2 to achieve the required load rating capability. Cable 2 was originally installed as the same high pressure-gas design but later replaced in the 1970’s with a low-pressure oil filled cable after multiple failures. These cables are 1.8 km in length and run parallel to the Don River, crossing it twice. The design methodology of the gas filled design is to pressurize the outside of the cable insulation at about 200 PSI using dry nitrogen to eliminate the formation of voids between the paper tape layers during load cycling. Formation of air voids in the paper tapes would lead to electrical discharges and ionization, which would result in insulation breakdown and cable failure. The gas pressurized design was common during the 1950’s and 1960’s but unfortunately proved to be somewhat troublesome with major problems experienced throughout the 1970’s and 1980’s. As a result, all other identical designs have been converted or replaced by Hydro One over the years. This particular cable is the oldest cable in the transmission underground network and the only gas-pressurized design that remains in the system. The plan to replace this cable is based on the load supply requirements to the downtown core and the lack of spare parts to conduct repairs should the cable fail. Asset condition assessment validates the need to replace this cable. Results:

• Maintain system and customer reliability. • Prevent public safety incidents by maintaining a reliable supply to the downtown core



Hydro One Networks – Investment Summary Document Investment Type: Inter-Area Network Transfer Capability

Reference # Investment Name Gross Cost In-Service DateD1 Hydro One-Hydro Québec 1,250MW Interconnection $122.8M Mid 2009

Please see Exhibit D1, Tab 3, Schedule 3, Table 2 for cash flow and other details about each project. Need: To increase the inter-tie capability by 1,250MW and allow power transfer between Ontario and Québec.

Not proceeding with this investment would limit Ontario customers' access to a renewable source of electricity, and it would curtail the opportunity to bank off-peak power in Hydro Québec's reservoirs for delivery to Ontario during on-peak periods. Summary: The Ontario – Québec 1,250MW interconnection project was initiated in 1999 and approvals under the Environmental Assessment and Ontario Energy Board Acts were obtained in 2001. Until 2006 the project had been on hold awaiting a commitment to proceed by both provinces. In 2006, Hydro One and Hydro Québec TransEnergie (the transmission division of Hydro Québec) restarted talks about the project. The government of Ontario and the Ontario Power Authority indicated their support for the new tie to be built and for the necessary investment in Ontario transmission facilities by Hydro One. As such, Hydro One and TransEnergie (“TE”) concluded an agreement to build the tie in October 2006.

Under the proposed interconnection project, Hydro One will build a new 230kV double circuit transmission line between Hydro One’s Ottawa Hawthorne TS and the Ontario-Québec inter-provincial boundary. Hydro Québec Trans Energie Division will construct a back-to-back DC Converter Station at TE’s Outaouais TS and a line to the inter-provincial boundary. These facilities will provide a transfer capability of 1,250MW. The Québec portion of the interconnection facilities will be paid for by Hydro Québec. The project is currently under construction. The Independent Electricity System Operator has completed the System Impact Assessment Report (CAA ID 2000-001) for this project. This project received Ontario Energy Board ‘Leave to Construct’ Approval by Proceeding RP-2000-0068 on January 31, 2001. The new interconnection is expected to go into operation in spring 2009. Results: Increase Ontario-Québec inter-tie capability by 1,250MW.

Project Classification per OEB Filing Guidelines / IPSP Status: Project Class: Development Project Need: Discretionary: Improve transfer capability between Ontario and Québec. IPSP Reference: Non-IPSP

Hydro One Networks – Investment Summary Document Investment Type: Inter-Area Network Transfer Capability Reference # Investment Name Gross Cost In-Service Date

D2 New 500kV Bruce to Milton Double Circuit Transmission Line $619.8M Mid 2010/Late 2011Please see Exhibit D1, Tab 3, Schedule 3, Table 2 for cash flow and other details about each project.

Need:

To construct a new double-circuit 500kV line between Bruce and Milton in accordance with the Ontario Power Authority (“OPA”) recommendation; to address the inadequate transmission capacity to transmit committed renewable and baseload generation in Bruce Area to the load in southern Ontario (as per deliberations during Proceeding EB-2007-0050 for the Bruce to Milton 500kV project). Not proceeding with this investment would result in the constraint of nuclear and renewable generation in the Bruce Area.

Summary:

The existing transmission in southern Ontario cannot accommodate the generation expected to come into service in the Bruce area over the next few years. This includes:

• 1500MW from upgrades of existing facilities and rehabilitation and restart of Bruce A units G1 and G2, for which OPA has assumed a contract between the Ministry of Energy and Bruce Power Inc.

• 1700MW from new wind generation in the Bruce area, including an aggregate of 723MW for which the OPA has entered into contracts with wind developers, through the Ministry of Energy’s Request For Proposals.

To incorporate the above generation into the transmission system, additional transmission capability is required. The OPA has determined that the preferred solution to increase the transfer capability of Hydro One’s 500kV system is to build a new 500kV double circuit transmission line between Bruce Complex and Milton SS to securely incorporate all eight units from Bruce and the committed and potential wind generation. The OPA has urged Hydro One to initiate the activities required to construct the new 500kV line for in-service by December 2011. The activities noted include "acquiring the required permits, regulatory approvals, engineering work and the prudent purchasing of materials needed to meet the required in-service date". The OEB approved Hydro One’s ‘Leave to Construct’ Application in September 2008 (Proceeding EB-2007-0050) and an application for Environmental Assessment Approval has been submitted. The project will be undertaken in two phases to facilitate construction by taking advantage of the availability of transmission outages in 2009 and 2010 as a result of planned outages at Bruce GS. Thus, Phase 1 is scheduled to be in-service in mid-2010 and Phase 2 by December 2011. The need for this project was identified in the IESO’s December 2007 Ontario Reliability Outlook, and an IESO System Impact Assessment Report (CAA ID 2006-250) has been completed for this project. The Ontario Government has also, in its announcement of “A Balanced Plan for Ontario’s Electricity Future”, reiterated the need for “expanding the transmission capacity from Bruce County and surrounding area to facilitate the transmission of electricity from several new wind farms and the Bruce facility”. Results:

Provide sufficient transmission capacity to reliably transmit the output of the Bruce GS and 1700MW of wind generation in Bruce and surrounding counties in accordance with Northeast Power Coordinating Council criteria. Project Classification per OEB Filing Guidelines / IPSP Status:

Project Class: Development Project Need: Non-Discretionary: The project is required to satisfy the recommendations outlined by the OPA

to accommodate new generation. IPSP Reference: Pre-IPSP: This project was referenced in the IPSP Discussion Document (November 13, 2006)

and/or in the IPSP (August 29, 2007) on the basis that, in order to meet the required need date, the project would be initiated by Hydro One prior to IPSP approval.


Reference # Investment Name Gross Cost In-Service Date D3 Install Seven 230kV Capacitor Banks in Southwestern Ontario $56.5M Late 2009

Please see Exhibit D1, Tab 3, Schedule 3, Table 2 for cash flow and other details about each project. Need:

To comply with the recommendation of the Ontario Power Authority (“OPA”) to install seven 230kV shunt capacitor banks at three stations in southwestern Ontario in 2009 as a near-term measure to increase transfer capability in the Bruce Area and southwestern Ontario (as per deliberations during Proceeding EB-2007-0050 for the Bruce to Milton 500kV project). Not proceeding with this investment would result in increased amounts of constrained nuclear and wind generation starting in 2009. Summary:

The OPA has recommended that Hydro One Networks proceed with the installation of seven capacitor banks: one 230kV 200MVar at Buchanan TS, four 230kV 250MVar at Middleport TS and two 230kV 250MVar at Nanticoke TS for in-service in 2009. The installation of these facilities is one of the measures required to increase the transfer capability of the Bruce and southwestern Ontario transmission systems to accommodate the delivery of 1500MW of additional generation at Bruce A nuclear plant and the 1700MW of committed and potential wind generation developments in the Bruce area. The capacitor bank installations will include additional measures that were identified in the investigation of an explosion of the 230kV Richview TS capacitor bank on January 30, 2007 in order to address the cause of the failure. These additional measures include installation of the following: • Surge capacitors to mitigate the rapid rise of recovery voltage (RRRV) seen by the capacitor bank breakers • Breakers with a better transient recovery (TRV) characteristic • Capacitor unit insulators with a larger creep to reduce the possibility of insulator flashover This project was identified in the IESO’s December 2007 Ontario Reliability Outlook and an IESO System Impact Assessment Report (CAA ID 2007-295) that was completed for this project. The increased transmission capacity, provided by the capacitor banks, will also have an enduring benefit after the completion of the proposed Bruce to Milton 500kV transmission line. The new capacitor banks will support the government’s off-coal strategy by replacing some of the voltage control functionality currently provided by Nanticoke GS. Results:

Increase the transmission transfer capability of the Bruce and southwestern Ontario transmission systems through the installation of seven 230kV shunt capacitor banks as recommended by the OPA. Project Classification per OEB Filing Guidelines / IPSP Status:

Project Class: Development Project Need: Non-Discretionary: The projects are required to incorporate new generation in Ontario, to

satisfy government directive(s), and to satisfy the recommendations outlined by the OPA. IPSP Reference: Pre-IPSP: This project was referenced in the IPSP Discussion Document (November 13, 2006)



Reference # Investment Name Gross Cost In-Service DateD4 Bruce Special Protection System Modifications for Bruce Area $5.8M Mid 2010


To increase generation and load rejection coverage within the Bruce Area as an interim measure in accordance with the Ontario Power Authority (“OPA”) recommendation (as per deliberations during Proceeding EB-2007-0050 for the Bruce to Milton 500kV project). Implication of not proceeding with this investment includes: outage restrictions impacting Hydro One work program and curtailment of nuclear and wind powered generation in the Bruce Area resulting in increased costs. Summary:

The Bruce Special Protection System (BSPS) is a collection of special protection systems installed at Bruce NGS and associated stations that perform pre-defined control actions (such as: generation rejection, reactor tripping and load rejection) in response to recognized contingencies in the Bruce area. By providing these capabilities, restrictions on the maximum output of Bruce NGS and other system parameters can be reduced or eliminated, while still respecting the established system criteria for voltage stability and transmission equipment thermal loading. The transmission capability of the Bruce Area will be at its limit starting in mid-2009. There is an increase of nuclear and wind generation expected in the area post mid-2009, which will cause the transmission capability to be exceeded until the new 500kV line is completely installed in December 2011. In order to help bridge the gap between the return to service of Bruce units and in-service of a new double circuit 500kV line from Bruce to Milton, the OPA is recommending as an interim measure that Hydro One proceed with the work to increase generation and load rejection coverage. To maximize the transmission capability, the BSPS requires modification to increase the number of contingencies that require the use of generation rejection in the Bruce Area and to add IESO-identified wind generators to the BSPS scheme. The load rejection capability will also be re-activated at thirteen stations to assist with re-preparation of the system following a critical contingency. This project was identified in the IESO’s December 2007 Ontario Reliability Outlook and an IESO System Impact Assessment Report (CAA ID 2005-222) was completed for this project. Results:

• Maximize the transmission capability in the Bruce area by modifying the BSPS to increase generation and load rejection coverage as an interim measure until the new 500kV line is in-service.

• The BSPS will provide enduring benefits in the longer term, as it will be armed during contingency conditions thereby minimizing the outage restrictions that would curtail nuclear and wind powered generation in the Bruce Area and impact the Hydro One work program.

Project Classification per OEB Filing Guidelines / IPSP Status:

Project Class: Development Project Need: Non-Discretionary: The project is required to satisfy the recommendations outlined by the

OPA to accommodate new generation. IPSP Reference: Pre-IPSP: This project was referenced in the IPSP Discussion Document (November 13, 2006)



Reference # Investment Name Gross Cost In-Service DateD5 Claireville TS x Cherrywood TS: Unbundle 500kV Circuits $107.3M Late 2010


Reduce need to limit generation east of Toronto and imports from Hydro Québec for 500kV system contingencies and improve the reliability of the Ontario Bulk Electricity System. The implications of not proceeding with this investment include: limiting power transfers from eastern Ontario, exposing Darlington GS to the risk of unscheduled power reductions, and increasing operational risks during outages of 500kV circuits or when elements are out-of-service at Cherrywood TS. Summary:

The existing 500kV transmission lines between Cherrywood TS and Claireville TS consist of two 500kV double circuit tower lines. The circuits on the north tower line are joined together and operated as a single “super circuit” C551V. Similarly the circuits on the south tower line are joined together and operated as a single circuit C550V. Under outage conditions when one of the two circuits is out-of-service (due to either forced or planned outage), generation connected to the 500kV system in eastern Ontario is curtailed to prevent excessive flows on the 230kV network should a contingency occur. This generation curtailment increases the risk to the reliability of the Bulk Electricity System. The new 1,250MW interconnection with Hydro Québec, 550 MW Portlands GS, and 198 MW Wolfe Island Wind Generation will further increase flow across the Cherrywood TS x Claireville TS 500kV interface. The proposed replacement of Lennox GS with gas-fired units, as per the IPSP, and the proposed development of Darlington “B” GS will also further increase flow across this interface. As a result, potential loss of the interface, or element(s) of the interface, will have a corresponding greater impact since greater amount of generation would be affected. (Additional details about the cost and benefits of this project are provided in Section 3.1.2 of Exhibit D1, Tab 3, Schedule 3). In order to improve the reliability of the Bulk Electricity System, to provide greater operating flexibility, and to reduce the adverse impact on supply to customers, it is proposed to unbundle the two ‘super’ circuits. This will effectively result in two additional 500kV circuits between Cherrywood TS and Claireville TS. New 500kV terminations will be required at both Cherrywood TS and Claireville TS to accommodate the new circuits. The project also includes work to correct existing deficiencies at Cherrywood TS and Claireville TS. At Cherrywood TS, four 500kV air blast circuit breakers will be replaced with SF6 type breakers. At Claireville TS, a new 500kV GIS breaker will be installed to allow autotransformer T13 to be isolated without having to take one of the two main 500kV buses out-of-service. This project was identified in the IESO’s December 2007 Ontario Reliability Outlook and the IESO has completed the System Impact Assessment Report (CAA ID 2006-297) for this project. Results:

Improve transfer capability across the Cherrywood TS x Claireville TS interface and improve reliability of the Bulk Electricity System. Project Classification per OEB Filing Guidelines / IPSP Status:

Project Class: Development Project Need: Partially Discretionary: Improve transfer capability from generation east of Toronto (Refer to

Exhibit D1-3-3, Section 3.1.2). IPSP Reference: Non-IPSP


D6 Installation of Static Var Compensator at Lakehead TS $22.5M Late 2010 Please see Exhibit D1, Tab 3, Schedule 3, Table 2 for cash flow and other details about each project.

Need:

To replace the Lakehead TS synchronous condenser that failed in 2005 with a static var compensator (“SVC”). This replacement is required in order to mitigate concerns about power quality and risk of voltage instability. Not proceeding with this investment would result in sub-standard voltage support in the West System (northwestern Ontario). Summary:

The 230kV transmission system between the Manitoba border and Wawa area is the backbone of the bulk power system in the West System. It allows incorporation of the local generation, import from and export to Manitoba and Minnesota, the transfer of surplus West System generation to the rest of Ontario during the peak load periods, and the transfer of generation from the East System during the off-peak periods when the output of the local generation is not sufficient to meet West System load requirements. There have always been significant challenges in dispatching of reactive power devices in the area to maintain acceptable voltages, security, and reliability of the system in West System due long transmission circuits and the daily variation in power transfers across this system. Until 2005, there were two synchronous condensers at Lakehead TS to facilitate the voltage control in the area. The older of the two, Unit C7 (+48/-24MVar) that was placed in-service in 1955, suffered a major failure in December 2005. Following a detailed analysis, it has been determined that this unit is not repairable, primarily because of lack of spare parts. The companion Unit C8, in-service since 1969, is now the only continuous voltage control device for maintaining the bulk system voltage in the area. Although it is feasible to control the voltage with only Unit C8, it would be difficult to maintain the system voltage if that unit was forced out-of-service. Furthermore, experience has shown that the West System can experience huge voltage excursions (i.e. voltage has risen to as high as 280kV). In such cases it has been difficult to bring down the voltage in a timely manner even with two synchronous condensers in-service. As a result, there is a significant and increasing risk of substandard operating voltage, poor power quality, and voltage instability in the West System if the failed condenser Unit C7 were not replaced. The IESO System Impact Assessment Report (CAA ID 2006-247) indicates the installation of a +60/-40MVar SVC at Lakehead is required to meet the need of providing dynamic voltage control to enable power transfer capability in the West System. This project was identified in the IESO’s December 2007 Ontario Reliability Outlook. Results:

Provide necessary reactive reserve margin, effectively maintain acceptable voltage, and eliminate operational concerns. Project Classification per OEB Filing Guidelines / IPSP Status:

Project Class: Development Project Need: Non-Discretionary: The project is required to replace the failed synchronous condenser to

address voltage stability and operational concerns. IPSP Reference: Non-IPSP


Reference # Investment Name Gross Cost In-Service DateD7 Northeast Transmission Reinforcement: Installation of Static

Var Compensators at Porcupine TS and Kirkland Lake TS $108.6M Late 2010

D8 Installation of Series Capacitors at Nobel SS $47.2M Late 2010 Please see Exhibit D1, Tab 3, Schedule 3, Table 2 for cash flow and other details about each project.

Need:

To relieve congestion on the North-South (“N-S”) Interface in order to access available northern generation, and to enable incorporation of additional committed and planned renewable generation in northern Ontario in accordance with Ontario Power Authority (“OPA”) recommendation and the Government directives. These projects will also ensure that the transfer of power from committed and planned generation will not have adverse impact on the supply reliability to electricity consumers in northeastern Ontario. Not proceeding with these investments would result in bottling of economic generation in northern Ontario and utilization of uneconomic generation in the south during peak loading conditions. Summary:

The existing north and south electricity systems in Ontario are interconnected by two 278km long 500kV single-circuit lines between Hanmer TS and Essa TS and one 91km long 230kV single-circuit line between Otto Holden TS and Des Joachims TS. These circuits comprise the N-S Interface, which allows transfer of generation that is surplus to northern Ontario into southern Ontario during critical peak load conditions. Currently, the N-S Interface has a transfer capability of 1,300MW without Generation Rejection (“GR”) or 1,400 MW with GR based on voltage and transient stability considerations. With the recent addition of new generation and the reduction of load in northern Ontario, the transfer capability limitations on the N-S Interfaces have resulted in constraining up to 400MW of economic generation, mostly during the critical peak load conditions. The congestion across the N-S interface is expected to increase further over the next few years as over 500MW committed and planned generation will be placed in-service in the north. In order to mitigate concerns about increasing congestion on the N-S Interface and to enable renewable generation in the north as per the Government’s direction, the OPA has recommended near term measures to enhance the N-S transfer capability and the transmission system north of Sudbury. These measures include: installation of series capacitors (“SC”) at Nobel SS to provide 50 % compensation on the two 500kV lines, and installation of -100/+300MVar static var compensator (“SVC”) at Porcupine TS and +200MVar SVC at Kirkland Lake TS. This project was identified in the IESO’s December 2006 Ontario Reliability Outlook, and the IESO System Impact Assessment Reports (CAA ID 2004-160 and 2006-223) for the SC and SVC projects have been completed. Results:

• Reduce or eliminate generation congestion in the north by increasing the N-S transfer capability by 500MW to 1,800MW without Generation Rejection (“GR”) and by 750MW to 2,150MW with GR.

• Enable OPA to successfully procure approximately 550MW of renewable generation north of Sudbury. • Address concerns about the risk of supply reliability for electricity customers in northeastern Ontario. Project Classification per OEB Filing Guidelines / IPSP Status:

Project Class: Development Project Need: Non-Discretionary: The projects are required to incorporate new renewable generation in

northern Ontario to satisfy government directive(s), and to support the OPA’s recommendation IPSP Reference: Pre-IPSP: This project was referenced in the IPSP Discussion Document (November 13, 2006)



Reference # Investment Name Gross Cost In-Service DateD9 Installation of Shunt Capacitor Bank at Algoma TS $9.7M Late 2010

D10 Installation of 2 Shunt Capacitor Banks at Mississagi TS $10.3M Late 2010 D11 Installation of Static Var Compensator at Mississagi TS $31.9M Late 2011


To increase the transfer capability of the Mississagi Flow-East Interface to relieve congestion to access available generation in the area from Sudbury to eastern Lake Superior including Manitoulin Island (“Sault/Algoma area”). These projects will be committed only if the OPA recommends them, in order to accommodate new renewable generation in northern Ontario to satisfy government directive(s). Not proceeding with these investments would result in the output of generators west of Sudbury having to be constrained in order to meet the reliability criteria under peak load conditions, necessitating the use of less-favorable sources of power to meet the demand. Summary:

This transmission system between Wawa and Sudbury serves about 500MW of load and about 1,100MW of generation in the Sault/Algoma area; and provides the capability to transfer generation surplus in the area to the Sudbury area. It also provides a connection for power transfers, up to 325MW, from northwestern Ontario through the East-West Tie at Wawa TS. The Mississagi Flow-East Interface comprises of three 230kV circuits connecting Mississagi TS to Hanmer TS and Martindale TS in Sudbury area, a distance of approximately 200km. The present eastbound transfer from Mississagi TS to Sudbury can potentially reach 1,000MW which would exceed the 670MW existing capacity. Consequently, up to 400MW of generating capacity could be constrained by the transfer capability of the existing transmission facilities. There are also new and committed generation developments west of Sudbury, in particular wind potential on Manitoulin Island, which will increase the transfer level in the near future. The work currently underway to upgrade the Mississagi Area Generation Rejection scheme and the proposed installation of a shunt capacitor bank at Algoma TS and a shunt capacitor and static var compensator at Mississagi TS will increase the transfer capability of this interface by approximately 260MW to about 930MW. These projects were identified in the IESO’s December 2007 Ontario Reliability Outlook. Results:

• Increase the transfer capability of Mississagi Flow-East Interface to about 930MW to reduce congestion and maintain the reliability of supply.

• Provide an added benefit of increasing the transfer capability of the North-South Tie by about 60MW. • Enable OPA to procure renewable generation west of Sudbury to meet the government directives. Project Classification per OEB Filing Guidelines / IPSP Status:


northern Ontario to satisfy government directive(s), and to support the OPA’s recommendation IPSP Reference: Pre-IPSP: The need for reactive support in Northern Ontario was referenced in the IPSP

Discussion Document (November 13, 2006) and/or in the IPSP (August 29, 2007). Additional details about the need were recently finalised by OPA.


Reference # Investment Name Gross Cost In-Service DateD12 Installation of 2 Shunt Capacitor Banks at Porcupine TS $14.6M Late 2011


To relieve congestion on the North-South (“N-S”) Interface in order to access available northern generation, as well as enable incorporation of additional committed and planned renewable generation in northern Ontario in accordance with Ontario Power Authority (“OPA”) recommendation and Government directives. These projects will also ensure that the transfer of power from committed and planned generation will not have adverse impact on the supply reliability to electricity consumers in northeastern Ontario. Not proceeding with these investments would result in bottling of economic generation in northern Ontario and utilization of uneconomic generation from the south during peak loading conditions. Summary:

The existing north and south electricity systems in Ontario are interconnected by two 278km long 500kV single-circuit lines between Hanmer TS and Essa TS and one 91km long 230kV single-circuit line between Otto Holden TS and Des Joachims TS. These circuits comprise the N-S Interface, which allows transfer of generation that is surplus to northern Ontario into southern Ontario during critical peak load conditions. Currently, the N-S Interface has a transfer capability of 1,400MW (with generation rejection) based on voltage and transient stability considerations. With the recent addition of new generation and the reduction of load in northern Ontario, the transfer capability limitations on the N-S Interfaces have resulted in constraining up to 400 MW of economic generation, mostly during the critical peak load conditions. The congestion across the N-S interface is expected to increase further over the next few years as more committed and planned generations are placed in-service in the north. In order to mitigate concerns about increasing congestion on the N-S Interface and to enable renewable generation in the north as per the Governments’ directive, the OPA has recommended several near term measures to enhance the N-S transfer capability which include the installation of static var compensators (“SVCs”) at Porcupine TS and at Kirkland Lake TS (Reference ISD D7), the installation series capacitors (“SC”) at Nobel SS (Reference ISD D8), and the installation of a set of 230kV shunt capacitor banks at Porcupine TS. The SC and SVC upgrades, which are being implemented independently, will increase the N-S transfer capability by 500MW. The installation of 2x125MVar shunt capacitor banks at Porcupine TS will further increase the N-S transfer capability by 250MW to 2,050MW without generation rejection. This project was identified in the IESO’s December 2007 Ontario Reliability Outlook. Results:

• Reduce or eliminate generation congestion in the north by further increasing the N-S transfer capability by 750MW to 2,050MW without Generation Rejection (“GR”) and by 900MW to 2,300MW with GR.

• Facilitate the incorporation of up to 900MW of committed and planned generation north and west of Sudbury. Project Classification per OEB Filing Guidelines / IPSP Status:


northern Ontario to satisfy government directive(s), and to support the OPA’s recommendation IPSP Reference: Pre-IPSP: The need for reactive support in Northern Ontario was referenced in the IPSP

Discussion Document (November 13, 2006) and/or in the IPSP (August 29, 2007). Additional details about the need were recently finalised by OPA.


D13 Installation of Static Var Compensator&Reactors at Nanticoke TS $80.0M Mid 2011 D14 Installation of Static Var Compensator at Detweiler TS $69.2M Mid 2011


To provide increased transmission capacity to support 1500MW of increased generation at the Bruce complex plus 1700MW of committed and potential wind generation in the Georgian Bay area both as a near-term measure and long term solution to increased transfer capability out of the Georgian Bay area following the decommissioning of the Nanticoke coal-fired plant in 2014 (as per deliberations during Proceeding EB-2007-0050 for the Bruce to Milton 500kV project). Not proceeding with this investment would result in constraining nuclear and renewable generation in the Bruce Area. These projects will be committed only if OPA recommends them, based on its assessment of technical characteristics currently being finalized. Summary:

The existing transmission out of the Bruce complex comprising 4 x 500kV circuits and 6 x 230kV circuits transmit power from the Bruce nuclear plants and the wind generation in the Georgian Bay area. The two Bruce 230kV nuclear generating units are currently being refurbished and are planned to return to service in 2010. Two new Bruce x Milton 500kV circuits, planned to be incorporated in 2011, are intended to support the resulting 1500MW of increased generation plus 1700MW of committed and potential wind generation in the Georgian Bay area. In the interim period, additional reactive support will be required to support the large transfers out of the Georgian Bay area. Over the longer term, reduction in generation at Nanticoke and the eventual decommissioning of the coal-fired plant, by 2014, will require the availability of reactive support to permit large transfers out of the Bruce complex in the long term. This reactive support requirement will be met by the installation of two 350MVar Static Var Compensators (“SVC”); one at Nanticoke TS (at 500kV) and the other at Detweiler TS (at 230kV), and the installation of 300MVar reactors at Nanticoke TS. These projects were identified in the IESO’s December 2007 Ontario Reliability Outlook. Result:

Increase transfer capability out of the Georgian Bay area by 250MW to support increased generation in the area and reduce the risk of generation congestion. Project Classification per OEB Filing Guidelines / IPSP Status:

Project Class: Development Project Need: Non-Discretionary: The project is also needed to satisfy the recommendations outlined by the

OPA to accommodate phasing out of cola-fired generation and to incorporate new generation in southwestern Ontario.

IPSP Reference: Pre-IPSP: This project was referenced in the IPSP Discussion Document (November 13, 2006) and/or in the IPSP (August 29, 2007) on the basis that, in order to meet the required need date, the project would be initiated by Hydro One prior to IPSP approval.

Hydro One Networks – Investment Summary Document Investment Type: Local Area Supply Adequacy Reference # Investment Name Gross Cost In-Service Date

D15 Southern Georgian Bay Transmission Reinforcement $88.0M Mid 2009 Please see Exhibit D1, Tab 3, Schedule 3, Table 3 for cash flow and other details about each project.

Need:

To provide adequate supply capacity and transformation capacity for load growth in the Southern Georgian Bay area. Not proceeding with this investment would result in the customers in the Southern Georgian Bay area continuing to receive substandard transmission supply. Summary:

Currently one 115kV single circuit line from Essa TS to Owen Sound TS, via Stayner TS and Meaford TS, provides the majority of electricity supply for load in Southern Georgian Bay. In this area, significant amount of load is exposed to rejection for a first contingency outage. As load in this area grows, it is increasingly exposed to load rejection. Currently, the local area supply adequacy in this part of the system does not meet Hydro One’s guidelines for area supply. The Meaford TS and Waubaushene TS, which are carrying load transferred from Stayner TS on an interim basis, are overloaded. The 230/115kV autotransformers at Essa TS are overloaded and Midhurst TS, which also carries load transferred from Stayner TS, is expected to be at station capacity in 2014. In addition, the low voltage distribution lines emanating from Meaford TS to supply load local to Stayner TS are currently experiencing voltage deficiencies. In order to mitigate concerns about supply adequacy, the existing 115kV single circuit between Essa TS and Stayner TS is being replaced with a double 230kV circuit along the existing right of way. The new two 230kV circuits will terminate into Essa TS’s 230kV switchyard where a new breaker position will be developed and several line re-terminations will be made. The other end of the double circuit line will terminate into Stayner TS. Stayner TS will be converted from an 115kV station to a 230kV station with full 230kV switching. A 230/115kV autotransformer will also be installed to maintain network connection to the 115kV circuit to Owen Sound TS. This work will prevent voltage collapse and load rejection upon a first contingency. Transformation capacity at Stayner TS will also be increased allowing load that is local to Stayner TS to be supplied from Stayner TS thereby alleviating transformation overloads at Meaford TS, Waubaushene TS and Midhurst TS. By supplying Stayner TS load via Essa TS 230kV system, instead of the 115kV system, this will also alleviate loading on 230/115kV autotransformers at Essa TS. This project is highlighted in the IESO’s December 2007 Ontario Reliability Outlook. The IESO has completed the System Impact Assessment Report (CAA ID 2005-190) for this project. This project received Ontario Energy Board ‘Leave to Construct’ Approval on January 26, 2007 (Proceeding EB-2006-0242). Results:

Improve transmission supply capacity, transformation capacity and customer reliability in Southern Georgian Bay while relieving other Simcoe County transformation stations to supply their own load growth. Project Classification per OEB Filing Guidelines / IPSP Status:

Project Class: Development Project Need: Non-Discretionary: The project is non-discretionary because the project is required to

accommodate new and existing load. IPSP Reference: Pre-IPSP: This project was referenced in the IPSP Discussion Document (November 13, 2006)



D16 Hurontario Station & 230kV Transmission Line Reinforcement $43.5M Mid 2010 D17 Transmission Reinforcement for the Supply to Jim Yarrow TS $49.1M Mid 2011

Please see Exhibit D1, Tab 3, Schedule 3, Table 3 for cash flow and other details about the project. Need:

Transmission line capacity in Western GTA is inadequate to meet requirements of the area over the next ten years. • Load on the Richview to Trafalgar 230kV circuits R19T/R21T (including the “Pleasant tap” from these

circuits) already exceeds the load meeting capability of these circuits. The load growth in Western GTA is expected to cause thermal overloading on these circuits in summer 2009 or earlier.

• The transmission circuits supplying Jim Yarrow TS are expected to be at their capacity by mid 2009. Not proceeding with these projects will impair Hydro One’s ability to reliably accommodate load expansions in Western GTA and will result in congestion on the circuits that transfer power into the Toronto area from the west. Summary:

Hydro One and five local distribution companies in the GTA West Area completed a joint planning study in 2006 that forecast a 2.6% annual load growth rate for 27.6kV loads and 1.5% for 44kV loads in the area over the next ten years. The study identified inadequate transformation capacity to supply future loads and recommended four transformer stations to be built within this area. The study also reported that the load growth in Western GTA is expected to cause thermal congestion on R19T/R21T in summer 2009 on the sections of the circuits out of Trafalgar TS, and on its “Pleasant tap” section of circuits that supply Jim Yarrow TS and Pleasant TS. In addition, loads on R19T/R21T peaked to approximately 750MW in summer 2005, exceeding the 600MW maximum recommended load interruption, as per Market Rules for a contingency involving loss of a double-circuit line. To resolve these issues, the aforementioned study recommended the Hurontario SS and 230kV Transmission Reinforcement from Cardiff TS to Hurontario SS project. The study also recommended reinforcement of transmission supply to Jim Yarrow TS. This project is highlighted in the IESO’s December 2007 Ontario Reliability Outlook and the IESO System Impact Assessment Report (CAA ID 2006-248) has been completed. These projects received Ontario Energy Board ‘Leave to Construct’ Approval on January 31, 2007 and October 9, 2007 (Proceedings EB-2006-0215 and EB-2007-0013 respectively). Results:

Increase reliable, transmission capacity in the northern Mississauga and Western Brampton area. Project Classification per OEB Filing Guidelines / IPSP Status:

Project Class: Development Project Need: Non-Discretionary: The project is required to increase reliable transmission capacity to supply

new and existing load customers. IPSP Reference: Pre-IPSP: This project was referenced in the IPSP Discussion Document (November 13, 2006)



D18 Woodstock Area Transmission Reinforcement $69.8M Mid 2011 Please see Exhibit D1, Tab 3, Schedule 3, Table 3 for cash flow and other details about the project.

Need:

Customer load supplied in the Woodstock Area at 115kV has exceeded the reliable transmission capacity. Not proceeding with this investment would result in the inability to reliably supply customers in the Woodstock Area. Summary:

Driving the increased electricity demand in the Woodstock Area is the fact that Toyota Canada Inc. is building a new manufacturing plant that is scheduled to be complete in 2008. The new Toyota plant has resulted in economic growth in the Woodstock Area in the form of industrial load ancillary to the Toyota plant such as parts fabrication as well as increased residential and commercial load. As a result the total load supplied at 115kV in the Woodstock area is expected to grow over the next 18 years at an average of 3.5% per year including the impact of Conservation and Demand Management. On February 13, 2007, Hydro One issued a report entitled “Woodstock Area Study” in response to inquires from Woodstock Hydro and Hydro One Distribution who were concerned about the capability of the existing 115kV transmission network to supply the growing load in the Woodstock area. The Woodstock Area Study found that the existing Woodstock area loads exceed the current reliable transmission capacity of 96MW for a loss of one of the existing 115kV circuits that supplies Woodstock TS. The exposure existed for 20 hours in 2006, 160 hours in 2007, and was forecasted to exceed 96MW for over 1000 hours in 2008. The Woodstock Area Study recommended that major transmission reinforcement be provided by 2010 to increase the transmission capacity so that this load can be supplied reliably. The proposed facilities of this investment include 11km of new 230kV double-circuit line on the existing 115kV right-of-way (“ROW”) between Ingersoll TS and a new station called Karn TS and 3km of new 230kV double-circuit line, initially operated at 115kV4, on the existing 115kV ROW between Karn TS and Woodstock TS. The project also includes construction of the new Karn TS which consists of two 250MVA 230/115kV autotransformers with three 115kV circuit breakers at a location 3km west of Woodstock TS. These projects will increase the transmission capacity in the Woodstock Area to 290MW in preparation for future growth. This project is highlighted in the IESO’s December 2007 Ontario Reliability Outlook and the IESO System Impact Assessment Report (CAA ID 2006-253) has been completed for this project. This project received OEB ‘Leave to Construct’ Approval on October 11, 2007 (Proceeding EB-2007-0027). Results:

Increase reliable transmission capacity in the Woodstock Area. Project Classification per OEB Filing Guidelines / IPSP Status:

Project Class: Development Project Need: Non-Discretionary: The project is required to increase reliable transmission capacity in the

Woodstock Area to supply new load customers, and it is endorsed by OPA. IPSP Reference: Pre-IPSP: This project was referenced in the IPSP Discussion Document (November 13, 2006)


4 The new line between Karn TS to Woodstock TS will be built to 230kV in order to cater for possible future 230kV conversion


D19 Replacement of Switchgear & Main Bus in 115kV Switchyard at Burlington TS

$11.8M Mid 2011

D20 Replacement of 12 - 115kV Circuit Breakers at Burlington TS $14.1M Late 2011 Please see Exhibit D1, Tab 3, Schedule 3, Table 3 for cash flow and other details about the project.

Need:

Various components at Burlington TS have exceeded their capability. These include circuit breakers, switches and busses. As a result of the operating measures that are required to manage the situation, the four 230/115kV transformers cannot be fully utilized and this exposes customers to post-contingency load shedding. Failure to proceed with this investment would result in the continued exposure of customers to post-contingency load shedding for customers in the Burlington area. Summary:

During planned maintenance outages of certain breakers at Burlington TS, or when the bus is split to control fault levels, the emergency ratings of the existing 230/115kV autotransformers cannot be utilized due to substandard busses. An automatic load rejection scheme is used at Burlington TS to reduce the transformer loadings to within their limits following critical contingencies. With the planned addition of the new Halton Hills CGS and Thorold CGS in 2010, the 115kV fault levels at Burlington TS will exceed the 10,000MVA asymmetrical or 45.5kA ratings of twenty 115kV circuit breakers. This will require the bus to be operated split much of the time which unduly exposes customers to load rejection for single contingencies in violation of load supply reliability criteria. The summer peak load supplied by the 115kV system at Burlington TS is currently about 800MVA and will be approaching 900MVA by 2010. When the bus is split, only 540MVA can be reliably supplied. In 2005 the load at Burlington TS was above 540MVA for 2,777 hours or 32% of the year which exposed up to 260MVA of load to load rejection. These two investments will replace twenty 115kV circuit breakers, four 230kV autotransformer disconnect switches, 115kV buses, twenty 115kV transformer and breaker disconnect switches, as well as associated instrument transformers. The replacement of these components will increase the fault rating of the station so that it will no longer be required to be operated split, allow the emergency ratings of the transformers to be utilized, and eliminate the use of the load rejection scheme for single contingency scenarios. The Independent Electricity System Operator has completed the System Impact Assessment Report (CAA ID 2007-299) for this project, which concludes that the proposed changes will not result in a material adverse effect on the reliability of the IESO-controlled grid. Results:

Improve load supply reliability of the 115kV customer load supplied from Burlington TS. Project Classification per OEB Filing Guidelines / IPSP Status:

Project Class: Development Project Need: Non-Discretionary: The project is required to meet compliance and reliability requirements;

and increase the reliability of supplying the 115kV customer load at Burlington TS. IPSP Reference: Non-IPSP


D21 Leaside TS x Birch Junction Transmission Reinforcement $56.6M Mid 2012 Please see Exhibit D1, Tab 3, Schedule 3, Table 3 for cash flow and other details about each project.

Need:

To provide adequate supply capacity to meet future load growth, and to adhere to applicable reliability criteria that specify load customers are not to be rejected upon a first contingency. Not proceeding with this investment would result in increased risk of customer interruptions affecting supply reliability for customers. Summary:

The existing facilities between Leaside TS and Wiltshire TS consist of three 115kV circuits L13W, L14W and L15W and their capability is sufficient to supply 272MW of load. These circuits supply Bridgman TS and Dufferin TS as well as provide load transfer capability between the Leaside TS and Manby TS 230/115kV autotransformer stations. The 2007 coincident summer peak load for Bridgman TS and Dufferin TS was 278 MW. Therefore, loss of either the L13W or the L15W circuit would have resulted in the flow exceeding the ratings of the remaining in-service circuits. A joint planning study in 2006 by Hydro One and Toronto Hydro on the adequacy of the supply to the City of Toronto has identified the need to reinforce the 115kV transmission network between Leaside TS and Wiltshire TS. The joint study has recommended building a new circuit from Leaside TS to Birch Junction to reduce the risk of customer interruption and provide improved reliability for customers in the area served by Bridgman TS and Dufferin TS. There is also a need to refurbish or replace the existing 50 year old underground cable section of 115kV circuit L14W between Birch Junction and Bayview Junction. It is recommended that the cable replacement be carried out at the same time as the installation of the new circuit to minimize costs and avoid unnecessary disruption to the community. The IESO has completed the System Impact Assessment Report (CAA ID 2006-238) for this project; which concludes that the proposed plan will alleviate thermal overloading of the Leaside to Wiltshire circuits under contingency conditions. This project will also provide operational flexibility to Hydro One and the customer with respect to load transfers, maintenance and outage scheduling. The project cost that is allocated to the development component of the project (i.e. after subtracting cost allocated to replacement of the cable) will be recoverable through incremental revenue for the appropriate rate pool and capital contributions from the customers, as indicated in Table 3 of Exhibit D1, Tab 3, Schedule 3. The capital contribution amounts indicated herein are considered preliminary as they are only finalized when the Capital Cost Recovery Agreement is signed and when the project is placed in-service. The capital contributions are determined as per Hydro One’s Transmission Customer Contribution Policy in accordance with the Transmission System Code. The planned in-service date is for summer 2012, a delay of about two years compared to the date identified earlier, in order to allow for required development work, consultations, approvals, design, and construction. However, if expeditious approvals are obtained, Hydro One will attempt to have the facilities completed earlier. Results:

Improve load meeting capability and transmission reliability for customers in the City of Toronto mid-town area. Project Classification per OEB Filing Guidelines / IPSP Status:

Project Class: Development Project Need: Non-Discretionary: The project is required to reliably serve City of Toronto customers. IPSP Reference: Pre-IPSP: This project was referenced in the IPSP Discussion Document (November 13, 2006)



D22 Supply to Essex County (formerly Windsor Area Reinforcement) $43.9M Late 2012 Please see Exhibit D1, Tab 3, Schedule 3, Table 3 for cash flow and other details about each project.

Need:

To increase load supply capability in the Essex County, enhance supply reliability, and reduce generation congestion. Not proceeding with this investment would result in the inability to continue to provide a reliable supply to customers in the Windsor-Essex area. Summary:

The Windsor–Essex area comprises the City of Windsor, Essex County, and western portions of the Municipality of Chatham-Kent. Electricity distribution in the area is carried out by ENWIN Powerlines Ltd., Essex Powerlines Corporation, Essex-Lakeshore-Kingsville (E.L.K.) Inc., Chatham-Kent Hydro Inc., and Hydro One Distribution. Three customer-owned generating plants (Brighton Beach CGS, West Windsor Power CGS and Windsor TransAlta CGS) with a combined generating capacity of about 825MW are also connected to the transmission system in the area. The Windsor-Essex area is summer peaking, with a peak demand of over 1000MW. About 60% of the area load is supplied by transformer stations connected to the 115kV transmission system. The 115kV transmission system in the area is loaded to beyond its reliable capacity and as result it is managed with a Special Protection System to mitigate thermal and voltage concerns. A joint planning study in 2007 by Hydro One and the Ontario Power Authority on the Windsor area transmission system identified several transmission reinforcement projects required to mitigate concerns about supply capability. One component of the work to increase the load supply capability and reliability in Essex County involves the building of a new 12km 2-circuit 230kV line on an existing right-of-way starting at Sandwich Junction in the Town of Lakeshore and passing through the Town of Tecumseh to the existing Lauzon station in the City of Windsor, and building appropriate terminations for circuits and transformers at the station. The need for the above investment is highlighted in the IESO’s December 2007 Ontario Reliability Outlook, and the IESO System Impact Assessment Report (CAA ID 2007-263) has been completed for this project. The planned in-service date for the project is late 2012 to allow for required project development work, consultations, and approvals, design, and construction. However, if expeditious approvals are obtained, Hydro One will attempt to have the facilities completed earlier. Result:

Increase load supply capability in the Windsor–Essex area, enhance load supply reliability and reduce generation congestion. Project Classification per OEB Filing Guidelines / IPSP Status:

Project Class: Development Project Need: Non-Discretionary: The projects are required to mitigate existing load supply issues in the

Windsor-Essex area. IPSP Reference: Pre-IPSP: This project was referenced in the IPSP Discussion Document (November 13, 2006)


Hydro One Networks – Investment Summary Document Investment Type: Load Customer Connection Reference # Investment Name Gross Cost In-Service Date

D23 Kingston Gardiner TS: Increase Transformation Capacity $14.3M Late 2008 / Mid 2009


Hydro One Distribution and Utilities Kingston are local utility customers supplied at 44kV from Kingston Frontenac TS (115 /44kV) and Kingston Gardiner TS (230/44kV). In 2005, the total load in the area exceeded the combined 10-day summer limited time rating of the two stations by about 39MW. Further, the customer’s load forecast indicates that the load in the area is expected to increase by about 50MW over the next 13 years. Not proceeding with this investment would impair the local utility customers’ ability to supply its load. Hydro One is obliged under the Transmission System Code to meet customer supply needs, when requested by the area customers. Summary:

Hydro One (Transmission and Distribution) and Utilities Kingston jointly assessed the future supply needs in Kingston area. The assessment identified a need for additional transformation capacity on the site of the existing Kingston Gardiner TS, in the Kingston area. To meet this need Hydro One initiated building a new 230/44kV, 50/83MVA station adjacent to the existing station at Kingston Gardiner TS in late 2006. During the procurement of the new 230/44kV 50/83MVA transformers, quality assurance problems were identified and change in manufacturer was initiated. In order not to delay the project, system reserve transformers were utilized for this project. In order to replenish the system reserve pool the new transformers procured will be transferred into the pool upon delivery in mid 2009. The new transformation capacity will serve both customers, Utilities Kingston and Hydro One Distribution. The project cost will be recoverable through incremental revenue for the appropriate rate pool and capital contributions from the customers, as indicated in Table 4 of Exhibit D1, Tab 3, Schedule 3. The capital contribution amounts are considered preliminary as they are only finalized when the Capital Cost Recovery Agreement is signed and when the project is placed in-service. The capital contributions are determined as per Hydro One’s Transmission Customer Contribution Policy in accordance with the Transmission System Code. Results:

Increase transformation capacity to meet the future load growth of Hydro One Distribution and Utilities Kingston. Project Classification per OEB Filing Guidelines / IPSP Status:

Project Class: Connection Project Need: Customer Driven: The project is required to increase transformation capacity to supply the

customers’ future load growth. IPSP Reference: Non-IPSP


D24 Holland TS: Build New 230/44kV TS & Line Connection $26.2M Mid 2009 Please see Exhibit D1, Tab 3, Schedule 3, Table 4 for cash flow and other details about each project.

Need:

On June 29, 2005 Hydro One and York Region Local Distribution Companies (“LDCs”) identified, to the Ontario Energy Board (“OEB”), transmission and distribution options to address the needs of LDCs in York Region. The Ontario Power Authority (“OPA”) recommended on September 30, 2005, and the OEB directed Hydro One Transmission on November 22, 2005 to construct Holland TS to address ongoing load growth in northern York Region. Not proceeding with the investment would impair the customers’ ability to supply its load. Hydro One is obliged under the Transmission System Code to meet customer supply needs, when requested by the area customers. Summary:

A new transformer station in the northern York Region area is urgently needed to serve new load in Aurora, Newmarket, and the surrounding areas. Northern York Region’s only source from the electrical power grid is Armitage TS which has four 230/44kV transformers supplying Powerstream, Newmarket Hydro and Hydro One Distribution load. The combined summer 10-day limited time rating (“LTR”) for the station is 352MVA. The summer peak loading on Armitage TS has exceeded this LTR for sustained periods for several years. Hydro One has initiated work on the new station in compliance with the OEB directive to proceed as soon as possible. The new station will have two 230/44kV transformers and would be built at a site close to Holland Marsh Jct. The property has been purchased, the Environmental Assessment has been completed, and major equipment ordered. Site construction is under way. The expected in-service date for the station is summer 2009. The project cost will be recoverable through incremental revenue for the appropriate rate pool. Based on calculations for capital contributions, as per Transmission System Code, no capital contribution is required from the customers as the forecast transformation connection pool revenues are sufficient to pay for the incremental capital and operating costs of the station. Results:

Increase transformation capacity to Newmarket Hydro, Hydro One Retail and PowerStream (Aurora), thereby relieving overload at Armitage TS and providing for future load growth. Project Classification per OEB Filing Guidelines / IPSP Status:

Project Class: Connection Project Need: Customer Driven: This project is required supply customers’ future load growth and to relieve

the overloading at Armitage TS. IPSP Reference: Non-IPSP

Hydro One Networks – Investment Summary Document Investment Type: Load Customer Connection

Reference # Investment Name Gross Cost In-Service DateD25 Goreway TS: Build and Connect Second 230/27.6kV DESN $24.6M Mid 2010


The 27.6kV supply facilities in eastern Brampton have reached capacity. Hydro One Brampton has requested that Hydro One Networks build a second 230/27.6kV DESN at existing Goreway TS to be ready for service no later than summer of 2010. Not proceeding with this investment would impair the customers’ ability to supply its load. Hydro One Networks is obliged under the Transmission System Code to meet customer supply needs, when requested by the area customers. Summary:

Hydro One Networks undertook a West GTA planning study jointly with Hydro One Brampton, Enersource Hydro Mississauga, Halton Hills Hydro and Milton Hydro. The study identified the need for a number of upgrades to the Hydro One system in the area, including the need for a new 230/27.6kV, 75/125MVA transformer station to supply Hydro One Brampton in the eastern side of the City of Brampton. The customer has requested that Hydro One Networks build a new DESN at Goreway TS in order to meet future load growth in this area of Brampton. The existing 230/27.6kV DESN at Goreway TS has reached its 10 day limited time rating or design capacity of 191.8MVA. New transformation capacity is required to meet future expected load growth of the LDCs in the area. The project cost will be recoverable through incremental revenue for the appropriate rate pool and capital contributions from the customers, as indicated in Table 4 of Exhibit D1, Tab 3, Schedule 3. The capital contribution amounts are considered preliminary as they are only finalized when the Capital Cost Recovery Agreement is signed and when the project is placed in-service. The capital contributions are determined as per Hydro One’s Transmission Customer Contribution Policy in accordance with the Transmission System Code. Results:

Increase transformation capacity to Hydro One Brampton, thereby providing for future load growth. Project Classification per OEB Filing Guidelines / IPSP Status:

Project Class: Connection Project Need: Customer Driven: This project is required to supply customers’ future load growth. IPSP Reference: Non-IPSP


D26 Vansickle TS: Increase capacity to supply new load $16.3M Mid 2010 Please see Exhibit D1, Tab 3, Schedule 3, Table 4 for cash flow and other details about each project

Need: The Vansickle TS load has reached its supply capacity. The customer, Horizon Utilities, has requested that Hydro One increase capacity at Vansickle TS by mid 2010 to supply new loads that include critical loads of the Niagara Health System’s new medical complex. Not proceeding with this investment would impair the customers’ ability to supply its load. Hydro One is obliged under the Transmission System Code to meet customer supply needs, when requested by the area customers. Summary: Vansickle TS comprises of two 115/13.8kV, 20/27/33MVA transformers and one 13.8kV indoor metalclad switchgear. The plan is to replace the existing transformers with higher rated transformers (115/13.8kV 45/60/75 MVA) and install a second, metalclad switchgear to meet Horizon Utilities’ future load growth in the supply area. The project cost will be recoverable through incremental revenue for the appropriate rate pool and capital contributions from the customers as indicated in Table 4 of Exhibit D1, Tab 3, Schedule 3. A credit to Horizon Utilities for advancement costs associated with the like-for-like replacement of the transformers was included in the capital contribution calculation as per Section 6.3.6 of the Transmission System Code. The capital contribution amounts are considered preliminary as they are only finalized when the Capital Cost Recovery Agreement is signed and when the project is placed in-service. The capital contributions are determined as per Hydro One’s Transmission Customer Contribution Policy in accordance with the Transmission System Code. Results: Increase transformation capacity to Horizon Utilities, thereby providing for future load growth. Project Classification per OEB Filing Guidelines / IPSP Status:

Project Class: Connection Project Need: Customer Driven: The project is required to supply customers’ future load growth. IPSP Reference: Non-IPSP

Hydro One Networks – Investment Summary Document Investment Type: Load Customer Connection

Reference # Investment Name Gross Cost In-Service DateD27 Churchill Meadows TS: Build New 230/44kV TS & Line

Connection (formerly NW Mississauga TS) $24.0M Late 2010

Please see Exhibit D1, Tab 3, Schedule 3, Table 4 for cash flow and other details about each project. Need: The 44kV supply facilities in Mississauga are reaching capacity. Enersource Hydro Mississauga has requested that Hydro One build a 230/44kV transformer station (“TS”). Not proceeding with this investment would impair the customers’ ability to supply its load. Hydro One is obliged under the Transmission System Code to meet customer supply needs, when requested by the area customers. Summary: Hydro One Networks undertook a West GTA planning study jointly with Hydro One Brampton, Enersource Hydro Mississauga, Halton Hills Hydro and Milton Hydro. The study identified the need for a number of upgrades to the Hydro One system in the area, including the need for a new 230/44kV, 75/125MVA transformer station to supply Enersource Hydro Mississauga. This station is required because the transformation capacity for 44kV supply to the entire City of Mississauga is expected to reach its limits of about 1140MVA by summer of 2008. The customer has requested that Hydro One build a new TS to meet future load growth in Mississauga. The preferred location is in North West Mississauga, close to the greatest concentration of load growth. The recommended TS location is west of Erindale TS and ideally adjacent to the 230kV transmission circuits R19T and R21T. A preferred site has been identified at the northeast corner of 9th Line and Highway 403 adjacent to the transmission corridor. Funds have been released to secure this property, to complete Environmental Assessment requirements, and to order long-lead equipment. The project cost will be recoverable through incremental revenue for the appropriate rate pool and capital contributions from the customers, as indicated in Table 4 of Exhibit D1, Tab 3, Schedule 3. The capital contribution amounts are considered preliminary as they are only finalized when the Capital Cost Recovery Agreement is signed and when the project is placed in-service. The capital contributions are determined as per Hydro One’s Transmission Customer Contribution Policy in accordance with the Transmission System Code. Results: Increase transformation capacity to Enersource Hydro Mississauga, thereby relieving existing overloaded facilities and providing for future load growth. Project Classification per OEB Filing Guidelines / IPSP Status: Project Class: Connection Project Need: Customer Driven: This project is required to supply customers’ future load growth. IPSP Reference: Non-IPSP


D28 Glendale TS: Upgrade capacity to supply new load $13.2M Late 2010 Please see Exhibit D1, Tab 3, Schedule 3, Table 4 for cash flow and other details about each project

Need: The Glendale TS T3/T4 DESN load has reached its supply capacity. The customer, Horizon Utilities, has requested that Hydro One increase capacity at Glendale TS by 2010 to supply new loads that include increased loads at the General Motors plant in St. Catharines. Not proceeding with this investment would impair the customers’ ability to supply its load. Hydro One is obliged under the Transmission System Code to meet customer supply needs, when requested by the area customers. Summary: Glendale TS comprises two DESNs T1/T2 and T3/T4. The plan is to replace the two existing T3/T4 DESN transformers (115/13.8kV, 11/15MVA) with higher rated transformers (115/13.8kV, 25/33.3/41.7MVA), and to replace the associated 13.8kV outdoor switchyard with an indoor metalclad switchgear to meet Horizon Utilities’ future load growth in the Glendale TS supply area. The project cost will be recoverable through incremental revenue for the appropriate rate pool and capital contributions from the customers, as indicated in Table 4 of Exhibit D1, Tab 3, Schedule 3. The capital contribution amounts are considered preliminary as they are only finalized when the Capital Cost Recovery Agreement is signed and when the project is placed in-service. The capital contributions are determined as per Hydro One’s Transmission Customer Contribution Policy in accordance with the Transmission System Code. Results:

Increase transformation capacity to Horizon Utilities, thereby providing for future load growth. Project Classification per OEB Filing Guidelines / IPSP Status: Project Class: Connection Project Need: Customer Driven: This project is required to supply customers’ future load growth. IPSP Reference:

Non-IPSP


D29 Dunnville TS: Increase Capacity to supply new load $8.6M Late 2010 Please see Exhibit D1, Tab 3, Schedule 3, Table 4 for cash flow and other details about each project.

Need: The Dunnville TS load has reached its supply capacity. The station supplies Haldimand County Hydro (“HCH”) and Hydro One Distribution. Discussions with the local distribution companies indicate that there is need for additional capacity by December 2010. Not proceeding with this investment would impair the customers’ ability to supply its load. Hydro One is obliged under the Transmission System Code to meet customer supply needs, when requested by the area customers. Summary: The plan is to replace the two existing 115/27.6kV, 18.7MVA transformers with two 115/27.6kV, 25/41MVA transformers, and add two feeder positions at Dunnville TS to meet the supply needs of HCH’s future load growth in the supply area as well as avoid loading the transformers above their capacity. The project cost will be recoverable through incremental revenue for the appropriate rate pool and capital contributions from the customers, as indicated in Table 4 of Exhibit D1, Tab 3, Schedule 3. The capital contribution amounts are considered preliminary as they are only finalized when the Capital Cost Recovery Agreement is signed and when the project is placed in-service. The capital contributions are determined as per Hydro One’s Transmission Customer Contribution Policy in accordance with the Transmission System Code. Results: Increase transformation capacity to HCH, thereby providing for future load growth. Project Classification per OEB Filing Guidelines / IPSP Status: Project Class: Connection Project Need: Customer Driven: The project is required to supply customers’ future load growth to

avoid overloading of the transformer above their capacity. IPSP Reference:

Non-IPSP


D30 Hanlon TS: Build new TS & Line Connection $28.3M Mid 2009 / Mid 2011


To provide relief for existing Guelph-Hanlon TS that has exceeded its capacity. Guelph Hydro has received several requests for new load connections in the Hanlon Business Park area. In the short term Guelph Hydro is transferring loads from Hanlon TS to Guelph Cedar TS to make capacity available for an additional load in the Business Park area. In the longer term a new station will be required to accommodate the additional load. Not proceeding with this investment would impair the customers’ ability to supply its load. Hydro One is obliged under the Transmission System Code to meet customer supply needs, when requested by the area customers. Summary:

Guelph Hydro has received several requests for new load connections in the Hanlon Business Park area. The existing Hanlon TS is being expanded to its maximum capacity with the addition of three new feeder breakers to accommodate additional load and is expected in-service in mid 2009. In addition, Guelph Hydro has asked Hydro One to proceed with a pool funded transformer station (Hanlon #2 TS) to meet future demand in the area (phase 2). The proposed Hanlon #2 TS will consists of two 115/27.6kV, 25/41MVA transformers and is expected in-service in mid 2011. In the longer term, the supply to Hanlon TS and the surrounding area will need to be reinforced. For this purpose, the Guelph Area Transmission Reinforcement Plan, recommended by the OPA in the IPSP, is scheduled to be in-service in mid 2012. This plan will likely require a Section 92 approval and the project development work for it will be underway shortly. The project cost will be recoverable through incremental revenue for the appropriate rate pool and capital contributions from the customers, as indicated in Table 4 of Exhibit D1, Tab 3, Schedule 3. The capital contribution amounts are considered preliminary as they are only finalized when the Capital Cost Recovery Agreement is signed and when the project is placed in-service. The capital contributions are determined as per Hydro One’s Transmission Customer Contribution Policy in accordance with the Transmission System Code. Results:

Ensure availability of electricity supply and maintain required quality of supply to customers in the Guelph-Hanlon area. Project Classification per OEB Filing Guidelines / IPSP Status:



D31 Crowland TS: Build and Connect second 115/27.6kV DESN $21.9M Mid 2011 Please see Exhibit D1, Tab 3, Schedule 3, Table 4 for cash flow and other details about each project.

Need: The Crowland TS has reached its supply capacity. The station supplies Welland Hydro and Hydro One Distribution. Discussions with the local distribution companies indicate that there is need for additional capacity by December 2011 to meet future load growth in the Crowland TS area and to avoid loading the transformers above their capacity. Not proceeding with this investment would impair the customers’ ability to supply its load. Hydro One is obliged under the Transmission System Code to meet customer supply needs, when requested by the area customers. Summary: The plan is to install a second DESN, with two 115/27.6kV 50/83MVA transformers and eight feeder positions at Crowland TS. The second DESN will be built adjacent to the existing T5/T6 DESN within the existing Crowland TS property. This second DESN is required to meet Welland Hydro’s and Hydro One Distribution’s future load growth in the supply area, and to avoid loading the transformers above its capacity. The project cost will be recoverable through incremental revenue for the appropriate rate pool and capital contributions from the customers, as indicated in Table 4 of Exhibit D1, Tab 3, Schedule 3. The capital contribution amounts are considered preliminary as they are only finalized when the Capital Cost Recovery Agreement is signed and when the project is placed in-service. The capital contributions are determined as per Hydro One’s Transmission Customer Contribution Policy in accordance with the Transmission System Code. Results: Increase transformation capacity to Welland Hydro and Hydro One Distribution, thereby providing for future load growth and avoid overloading the existing DESN. Project Classification per OEB Filing Guidelines / IPSP Status: Project Class: Connection Project Need: Customer Driven: This project is required to supply customers’ future load growth and to

avoid overloading of the existing DESN. IPSP Reference:

Non-IPSP


D32 Build New 230/27.6kV TS & Line Connection in Northern Mississauga

$36.1M Mid 2011

Please see Exhibit D1, Tab 3, Schedule 3, Table 4 for cash flow and other details about each project. Need: The 27.6kV supply facilities in northern Mississauga are reaching capacity. Enersource Hydro Mississauga has requested that Hydro One build a 230/27.6kV transformer station (“TS”). Not proceeding with this investment would impair the customers’ ability to supply its load. Hydro One is obliged under the Transmission System Code to meet customer supply needs, when requested by the area customers. Summary: Hydro One Networks undertook a West GTA planning study jointly with Hydro One Brampton, Enersource Hydro Mississauga, Halton Hills Hydro and Milton Hydro. The study identified the need for a number of upgrades to the Hydro One system in the area, including the need for a new 230/27.6kV, 75/125MVA transformer station to supply Enersource Hydro Mississauga in northern Mississauga. This station is required because the transformation capacity for 27.6kV supply within the City of Mississauga area bounded by Highways 401 and 407 is reaching capacity. The customer has requested that Hydro One build a new TS to meet future load growth in this area of Mississauga. The preferred location is in northern Mississauga, close to the greatest concentration of new load growth, near Highway 407 and Kennedy Road. Connection of this new TS will likely require construction of a new line connection, likely to be shorter than 2 kilometers. The project is in the preliminary planning stage and the new TS site has not yet been selected. The project cost will be recoverable through incremental revenue for the appropriate rate pool and capital contributions from the customers, as indicated in Table 4 of Exhibit D1, Tab 3, Schedule 3. The capital contribution amounts are considered preliminary as they are only finalized when the Capital Cost Recovery Agreement is signed and when the project is placed in-service. The capital contributions are determined as per Hydro One’s Transmission Customer Contribution Policy in accordance with the Transmission System Code. Results: Increase transformation capacity to Enersource Hydro Mississauga, thereby providing for future load growth. Project Classification per OEB Filing Guidelines / IPSP Status: Project Class: Connection Project Need: Customer Driven: This project is required to supply customers’ future load growth. IPSP Reference:

Non-IPSP


D33 Enfield TS (Oshawa): Build new 230/44kV TS & Line Connection

$25.6M Mid 2011

Please see Exhibit D1, Tab 3, Schedule 3, Table 4 for cash flow and other details about each project. Need: Oshawa Power & Utilities (OPUC) and Hydro One Distribution requested Hydro One to add transformation capacity on the site of the Oshawa Area Junction to address load growth in the Durham Region. Not proceeding with this investment would impair the customers’ ability to supply its load. Hydro One is obliged under the Transmission System Code to meet customer supply needs, when requested by the area customers. Summary: Hydro One (Transmission and Distribution) and OPUC jointly assessed the future supply needs for the Durham Region. A joint study with the LDCs recommended that a new 230/44kV, 75/125MVA TS near the border of the two municipalities of Oshawa and Clarington be built to address present and future load growth. The new TS will relieve the current overloading versus the 10-day summer limited time rating at Oshawa Wilson TS and Oshawa Thornton TS. The new transformation capacity will serve both customers, OPUC and Hydro One Distribution. The project cost will be recoverable through incremental revenue for the appropriate rate pool and capital contributions from the customers, as indicated in Table 4 of Exhibit D1, Tab 3, Schedule 3. The capital contribution amounts are considered preliminary as they are only finalized when the Capital Cost Recovery Agreement is signed and when the project is placed in-service. The capital contributions are determined as per Hydro One’s Transmission Customer Contribution Policy in accordance with the Transmission System Code. Results: Increase transformation capacity to meet the future load growth at OPUC and Hydro One Distribution. Project Classification per OEB Filing Guidelines / IPSP Status: Project Class: Connection Project Need: Customer Driven: The project is required to incorporate new loads and supply customers’

future load growth. IPSP Reference:

Non-IPSP


D34 Bracebridge TS: Station Expansion $19.5M Mid 2011 Please see Exhibit D1, Tab 3, Schedule 3, Table 4 for cash flow and other details about each project.

Need: Hydro One Distribution requested Hydro One to add transformation capacity on the site of the existing Bracebridge TS to address load growth in the Gravenhurst/Bracebridge area. Not proceeding with this investment would result in continued deficiency in transformation capacity in the Gravenhurst/Bracebridge area. This will impair the customers’ ability to supply their yearly load growth and increases the risk of prolonged rotating interruptions to the region if any equipment fails. Summary: A planning study identified the need for additional transformation capacity at Bracebridge TS to supply customers in the Gravenhurst/Bracebridge area where the load growth is averaging about 3-3½ % per year and the current transformation facilities in the area are overloaded. Bracebridge TS has one 230/44kV, 50/83MVA transformer with one 44kV feeder position. Bracebridge TS is located in the load centre and it is currently supplying TransCanada Pipe Lines (“TCPL”) only. The plan is to add a second transformer and three feeder positions to supply the additional load. The project cost will be recoverable through incremental revenue for the appropriate rate pool and capital contributions from the customers, as indicated in Table 4 of Exhibit D1, Tab 3, Schedule 3. The capital contribution amounts are considered preliminary as they are only finalized when the Capital Cost Recovery Agreement is signed and when the project is placed in-service. The capital contributions are determined as per Hydro One’s Transmission Customer Contribution Policy in accordance with the Transmission System Code. Results: Satisfy Hydro One Distribution’s request for additional transformation capacity to meet the forecasted electricity load growth and reliability needs of the area. Note: The need for this project is being reassessed in consultation with the transmission customer. Project Classification per OEB Filing Guidelines / IPSP Status: Project Class: Connection Project Need: Customer Driven: The project is required to increase transformation capacity to supply

customer’s future load growth. IPSP Reference: Non-IPSP


D35 Long Lac TS: Replace End-of-Life 115/44kV Transformers $14.6M Mid 2011 Please see Exhibit D1, Tab 3, Schedule 3, Table 4 for cash flow and other details about each project.

Need: • To replace the station’s power transformers which are approaching or at end-of-life. • To address the transformation capacity of the station supply • To address the safety and maintenance issues associated with the low voltage structure. Implications of not proactively managing the end-of-life issues of transmission facilities include: an increase in customer complaints and a decline in reliability; as well as an increased risk to employees’ safety relating to known deficiencies associated with the low voltage structure. Summary: Long Lac TS is a 115/44kV transformer station located in the northwest district supplied from the 115kV line AL4. The station has three single-phase transformers and one spare single-phase transformer each rated 115/44kV, 5/6.67/8.33MVA. The transformers are more than 60 years old and tests on similar retired units have shown major insulation deterioration. The spare parts for these transformers are not available and transformer accessories e.g. bushings and controls have a high failure rate. The transformer insulation has no tensile strength and with any major disturbance the transformer can fail at any time. Recently one of the transformers failed that resulted in a 12 hour outage for the area. Hydro One received a number of service interruption complaints from the area customers. The installation of two larger, 25/42MVA transformers will address the existing loading situation and will provide for the future load growth as identified by Hydro One Distribution. The proposed replacement is consistent with the current transformer Asset Management Strategy that looks to manage an aging population and also to manage spares effectively. No capital contribution is required from the customers since the primary driver for the plan is end-of-life replacement. Results: • Optimize the life cycle of the facility by reducing the Operating and Maintenance expenditures and

outage requirements through an integrated replacement and refurbishment program. • Eliminate the reliability, maintenance and safety concerns associated with the end-of-life components. • Increase the transformation capacity of the station. Project Classification per OEB Filing Guidelines / IPSP Status: Project Class: Connection Project Need: Non-Discretionary: The project is required to replace end-of-life equipment and

increase transformation capacity to supply future load growth. IPSP Reference: Non-IPSP


D36 Rodney TS: Build new TS & Line Connection $18.9M Late 2011 Please see Exhibit D1, Tab 3, Schedule 3, Table 4 for cash flow and other details about each project.

Need: To replace end-of-life St. Thomas TS and to resolve Hydro One Distribution’s supply issues related to supplying load from St. Thomas TS and Kent TS. Implications of not proactively managing the end-of-life issues of transmission facilities include an increase in customer complaints and a decline in reliability. Summary: The 100 year old St. Thomas TS is forecasted to be end-of-life by 2010. This station currently supplies about 25 MW of Hydro One Distribution’s load. Hydro One Distribution has also identified several issues related to supply from St. Thomas TS and Kent TS. The feeders out of St. Thomas TS and Kent TS are approximately 45km long and supply loads in the vicinity of Rodney TS. The long feeders are subject to voltage problems and outages caused by lightning. To compound matters Kent TS load cannot be backed-up from St. Thomas TS because St. Thomas TS is a 3-wire station and Kent TS is a 4-wire station. To resolve the transmission and distribution issues it was decided to build Rodney TS for an in-service of Late 2011. Rodney TS will be located approximately mid-way between St. Thomas TS and Kent TS. The proposed replacement is consistent with the current transformer Asset Management Strategy that looks to manage an aging population and also to manage spares effectively. No capital contribution is required from the customers since the primary driver for the plan is end-of-life replacement. Results: Resolve current distribution supply issues and replace end-of-life St. Thomas TS. Project Classification per OEB Filing Guidelines / IPSP Status: Project Class: Connection Project Need: Non-Discretionary: This project is required to resolve supply issues and replace end-of-

life St. Thomas TS. IPSP Reference: Non-IPSP


D37 Woodstock East TS: Build new 115/27.6kV TS & Line connection

$30.6M Mid 2011


To provide relief for the existing Woodstock TS that has exceeded its capacity. Woodstock Hydro and Hydro One Distribution are forecasting an additional 30MW growth in the area by 2010. This growth is fuelled by spin-off industries around the new Toyota Woodstock plant. In the short term, increases in load have been met by transferring loads to Ingersoll TS. Beyond this load transfer, there will be a need to reject load upon contingency scenarios when peak load levels exceed the Woodstock TS capacity limit. Implications of not proceeding with this investment include: insufficient supply capacity and a decrease in supply reliability. Summary:

In April 7, 2007, Woodstock Hydro Services Inc (“WH”) and Hydro One Distribution gave Hydro One the go-ahead to build a pool funded transformer station (Woodstock East TS) to meet future demand in the area. The in-service date for the station is targeted for mid 2011. However, the recently OEB-approved Woodstock Area Transmission Facilities must be in-service before Woodstock East TS can be reliably connected to the network. The proposed Woodstock East TS will consist of two 115/27.6kV, 50/83MVA transformers. In order to accommodate the new TS, the existing 115kV single circuit (B8W) has to be rebuilt to a double circuit line from Woodstock TS to the tapping point of the new Woodstock East TS. The line would be operated at 115kV, but would be built to 230kV standards for possible future use at 230kV. Construction of the new double circuit line will occur on existing right-of-ways. Property acquisition is required for the construction of the new TS. The line portion of the project requires “Leave to Construct” approval from the Ontario Energy Board. The entire project is subject to the provincial Environmental Assessment (“EA”) Act approval in accordance with the Class EA for minor Transmission Facilities. The project cost will be recoverable through incremental revenue for the appropriate rate pool and capital contributions from the customers, as indicated in Table 4 of Exhibit D1, Tab 3, Schedule 3. The capital contribution amounts are considered preliminary as they are only finalized when the Capital Cost Recovery Agreement is signed and when the project is placed in-service. The capital contributions are determined as per Hydro One’s Transmission Customer Contribution Policy in accordance with the Transmission System Code. Results:

Ensure availability of electricity supply and maintain required quality of supply to customers in the Woodstock area. Project Classification per OEB Filing Guidelines / IPSP Status:


Hydro One Networks – Investment Summary Document Investment Type: Generation Customer Connection

Reference # Investment Name Gross Cost In-Service DateD38 Lower Mattagami Extensions $32.8M Early 2012


Ontario Power Generation Inc. (“OPGI”) is proposing to upgrade their generating stations in the Lower Mattagami River, namely Little Long GS, Smoky Falls GS, Harmon GS and Kipling GS. The upgrades will result in a generation increase of approximately 450MW. The Minster of Energy directed OPA to assume the responsibility of the Crown and negotiate a financial energy supply agreement with OPGI. The proposed investment is consistent with government direction and expectations. Not proceeding with this investment would result in violation of Hydro One’s Transmission License for failure to connect a generator proponent. As well, the Ontario government’s directive for renewable energy would not be satisfied. Summary:

The OPGI proposed redevelopment of the existing generating plants on the Lower Mattagami River involves installing a third generating unit at Little Long GS, Harmon GS and Kipling GS and replacing the existing four-unit Smoky Falls generating station with a new three-unit facility. The following investments are required to accommodate the additional output from the generating facilities on the Mattagami River: • Modification of switching facilities at Little Long SS and an addition of a 230kV, 100MVAr capacitor bank. • Addition of a second 230kV circuit on the L20D corridor from Harmon GS to Kipling GS. • Connection of a second tap point for each of the existing generating stations to the 230kV network. • Uprating of the section of the 115kV circuits H6T and H7T between La Forest Junction and Timmins TS. • Modification of the northeast Load and Generation Rejection Scheme. • Modification of the Under-Frequency Load Shedding in the northeast.

The cost of the work, for the construction of approximately 4km of 230kV double circuit from Smoky Falls GS to the existing H22D and L20D lines, is included in the total cost of this project but may be contracted to a third party by OPGI. The project cost directly attributable to the generator will be recoverable through capital contributions from the generator, as indicated in Table 5 of Exhibit D1, Tab 3, Schedule 3. Some of the capital costs (for example, part of the Little Long SS facilities, 115 kV capacitor bank, modifications to the generation and load rejection schemes, and refurbishment of existing 115 kV circuits) will be pool funded as these facilities cannot be attributed to the generator. The capital contribution amounts are considered preliminary as they are only finalized when the Capital Cost Recovery Agreement is signed and when the project is placed in-service. The capital contributions are determined as per Hydro One’s Transmission Customer Contribution Policy in accordance with the Transmission System Code. Results:

• Provide adequate transmission facilities to allow the connection of OPGI Lower Mattagami plants expansion. • Enable OPA to successfully procure approximately 450MW of renewable generation north of Sudbury. Project Classification per OEB Filing Guidelines / IPSP Status:

Project Class: Connection Project Need: Customer Driven: The projects are required to incorporate new renewable generation in

northern Ontario to satisfy government directive(s). IPSP Reference: Non-IPSP. (The Mattagami Development is referenced in the IPSP in the context of supply

related matters).

Hydro One Networks – Investment Summary Document Investment Category: Operating Capital: Grid Operations Control Facility

Reference # Investment Name Gross Cost In-Service DateO1 Network Management System Upgrade $27M Mid 2009

Please see Exhibit D1, Tab 3, Schedule 4, Table 2 for cash flow and other details about each project.

Need:

The Network Management System (NMS) must be upgraded due to the impending end of life of software and hardware components. As of April 2008, the current application software, Areva Energy Management System (EMS) 2.2, is two releases out of date and does not support future business requirements. The server hardware has been in continuous operation since 2003, and is therefore reaching end of life between 2008 and 2011. In addition, the server hardware is not compatible with the required software upgrade, i.e. Areva EMS 2.5. The upgrade must be completed in 2009 to facilitate Hydro One being NERC Cyber Security compliant and to mitigate the business risks associated with operating the Transmission system using a control system that is at end-of-life. Summary:

The NMS is the mission critical operating tool used for monitoring and control of the Hydro One Transmission System. The reliable operation of the Ontario Power System is dependent on the continued availability and high performance of the NMS. This investment upgrades the NMS software and associated server hardware currently in service at the Ontario Grid Control Centre and the Richview Backup Centre. In addition, this investment provides computer room HVAC and power supply upgrades for the secure computing facilities at the OGCC and the Richview Backup Centre. Results:

Completion of this investment will result in the following accomplishments: (i) All NMS application installations upgraded to Areva EMS version 2.5; (ii) Hydro One’s NMS will be compliant with NERC Cyber Security regulations; (iii) hardware upgrades for continued sustainability; (iv) better performance and reliability (v) additional capacity for transmission growth and incorporation of distributed generation connections. Project Classification per OEB Filing Guidelines:

Project Class: Operations Project Need: Non-Discretionary


Investment Category: Operating Capital: Integrating Operating Infrastructure

Reference # Investment Name Gross Cost In-Service DateO2 Hub Site End of Life Replacement Program $11.4 M mid 2010

Please see Exhibit D1, Tab 3, Schedule 4 for cash flows. Need: Telecommunication Hub sites are locations around the Province where the OGCC monitoring & control of multiple transmission stations is facilitated by data-concentrating gateways. There are 39 Hub sites that service the OGCC and Back-up center via two independent telecom paths. As new assets have been added to the grid and more telemetry is added for better monitoring of the existing assets, many of these gateways have come close to being fully loaded. This investment is required to:

• provide capacity expansion for the monitoring and control of new or expanded transmission stations and new Generators (39 sites),

• meet NERC Cyber Security requirements5 (39 sites), • relocate equipment for NERC physical security requirements (15 sites) • decommission legacy equipment (5 sites) and • meet the performance and reliability of critical operating facilities (39 sites)

A compressed schedule (5 year to 2 year program) is needed to meet the NERC compliance deadline. NERC compliance, reliability and performance would be at risk if this investment does not proceed. Summary: The detailed scope of work was identified through a comprehensive assessment. Gateways will be replaced at 39 Hub Sites to provide capacity expansion and to replace systems that cannot implement NERC access control requirements5. Station hardened hardware and fiber optic interfaces will replace commercial grade equipment to address reliability issues identified in the Black-Out report6. Cyber Security system management tests will also be included in the commissioning of each Hub site upgrade. All of this work will be planned and implemented on a site by site basis to permit the best use of resources and equipment outages and promote an efficient approach to change management and commissioning of new equipment.

Results: Hub sites will have capacity to handle projected Grid System expansion for about 5 years with compliance to new NERC Cyber Security standards. Reliability and support upgrades will ensure transmission system control facility availability requirements are met. Project Classification per OEB Filing Guidelines:

Project Class: Operations Project Need: Non-Discretionary

5 NERC Cyber Standards: CIP005 Electronic Security Perimeter, CIP006 Physical Security and CIP007 Systems Management 6 PR-55-003 - “STATION - LOCAL BACKUP CONTROL The Need for DC Powered Centralized Local Control Facilities”


Investment Category: Operating Capital: Integrating Operating Infrastructure

Reference # Investment Name Gross Cost In-Service DateO3 Telecom Wide Area Network $40.3 M mid 2013

Please see Exhibit D1, Tab 3, Schedule 4 for cash flows. Need: Hydro One has the need for expanded telecommunication capacity into many of its transmission stations to support expanded assets (not related to real time operation), video surveillance for security, backhaul of communication from mobile devices and expanded enterprise systems (Resource Planning, Geographic Information Systems, video conferencing) serving offices located in those stations. Most of Hydro One’s transmission stations are in remote locations that are not served by high bandwidth telecommunication providers. However, Hydro One already has existing fibre optic communications facilities between many of its transmission stations for the protection and control of the transmission lines and station equipment. The fibre optic cables are built into the skywire of the transmission lines or in some cases, fastened along the side of the towers. This project will use separate wavelengths of light to add an additional network onto those existing physical paths. Not proceeding with this investment will restrict the opportunities for efficiency improvements through the deployment of new technologies. Summary: A high capacity wide area network will be provisioned among Hydro One’s transmission stations to meet Hydro One’s enterprise telecommunication needs in a manner that is physically separated from the telecommunications used for protection and control of the grid.

Results: The telecommunications required to enable new enterprise systems, video surveillance, improved asset information collection and other advanced applications will be in place. Project Classification per OEB Filing Guidelines: Project Class: Operations Project Need: Discretionary


Investment Category: Information Technology Reference # Investment Name Gross Cost In-Service Date

IT1 Cornerstone Phase 2 (Finance/HR/Payroll) $183.2M Q3, 2009 Need: The current Hydro One version of PeopleSoft, installed in 1998 for Finance, Human Resources, and Payroll processing was last partially upgraded in 2002, and is at end-of-life and is no longer under vendor support. Significant investment is required or else process and technology solutions will not exist to support the achievement of business objectives. Moreover, significant business continuity risks would remain unaddressed if Cornerstone Phase Two did not proceed.

Investment Summary: In 2006, Hydro One developed an IT strategy that called for replacement of core business systems (and associated bolt-ons) which had reached or were approaching end-of-life, with one or two off the shelf Enterprise Resource Planning (ERP) systems. In 2007, to commence implementation of this IT strategy, Hydro One initiated Cornerstone Phase I, an SAP Enterprise Asset Management solution; this project was successfully completed on June 30, 2008.

Cornerstone Phase 2 proposes to continue to expand Hydro One’s SAP solution to replace PeopleSoft, eliminating the need for the temporary SAP-to-PeopleSoft interfaces and bringing a greater proportion of Hydro One’s core business systems under vendor support. In addition, Cornerstone Phase 2 will replace the in-house application, Business, Regulatory Planning & Reporting (BRPR), which tracks the release of work from Asset Management to the field; this will be a first step in the deployment of SAP business planning and investment management functionality. Lastly, Cornerstone Phase 2 proposes to replace legacy Data Warehouse applications and databases with a single SAP business warehouse and a reporting tool, to provide one source of reliable business data. The proposed go-live date for Cornerstone Phase 2 is Q3 2009.

In addition to the defined project scope outlined above, Phase 2 also addresses currently anticipated International Financial Reporting Standards (IFRS) requirements to accommodate IFRS compliance by January 1, 2011. A parallel IFRS Project will be carried out to review Hydro One accounting policies/practices and recommend changes to meet IFRS compliance requirements. It is expected that many of these recommendations will be incorporated into the Phase 2 SAP solution while others will be addressed in subsequent releases of SAP, to address any late changes in IFRS requirements so as to provide full IFRS compliance before the January 1, 2011 deadline.

Similar to Cornerstone Phase I, the scope consists of and is restricted to doing what is required to turn on the SAP product and make it work as designed in the business, with no SAP software customizations or unnecessary enhancements. Results: Cornerstone Phase 2 will bring the following business benefits to Hydro One:

• Critical Finance & Payroll functions will be moved to a fully vendor-supported environment • Hydro one will avoid prolonged reliance on temporary financial interfaces between SAP and PeopleSoft • One integrated system of record for all asset and financial data

Costs1:

2007 ($M) 2008 ($M) 2009 ($M) 2010 ($M) Total ($M) Capital * and MFA 54.6 82.1 42.7 179.4 OM&A and Removals 0.1 0.8 2.9 3.8

Gross Investment Cost 0.1 55.4 42.7 98.2

Capital Contribution

Net Investment Cost 0.1 55.4 85.0 42.7 183.2 *Includes overhead and AFUDC at current rates.

Hydro One Networks – Investment Justification

Investment Category: Information Technology Reference # Investment Name Gross Cost In-Service Date

IT2 Cornerstone Phase 3 - Enhance Integrated Planning $72M 2010 Need: Phase 3 will enhance integrated planning by expanding Hydro One’s SAP solution and integrating key systems/technologies and specialized packaged point solutions to drive additional business value, improve end-to-end process efficiency and improve asset lifecycle management analytics/decisions. This investment is required to support the achievement of business objectives and to release significant business value. Not proceeding with this investment would eliminate the integrated tools and systems that are needed to further optimize asset lifecycle decisions and improve operational efficiency and productivity. It would also necessitate a continued reliance on existing end-user disparate systems/databases for this decision support.

Investment Summary: In 2006, Hydro One developed an information technology (IT) strategy that called for replacement of core business systems (and associated bolt-ons) which had reached or were approaching end-of-life, with one or two off the shelf Enterprise Resource Planning (ERP) systems. In 2007, Hydro One embarked on this strategy by initiating Cornerstone Phase 1, an SAP Enterprise Asset Management (EAM) solution. This project was successfully completed in June 2008. Cornerstone Phase 2 is now underway to replace PeopleSoft Finance/Human Resources/Payroll Functionality that is integrated with the EAM solution installed in Phase 1 for service Q3 2009. Hydro One business information consists of many different components that reside in many different sources even after completion of Phases 1 and 2. The key is to integrate these sources to allow asset and other business data to be captured once and used consistently throughout Hydro One to provide asset and asset work information from a variety of perspectives e.g. system performance, asset condition, labour, cost (historical and forecasted), work accomplishment, performance and work metrics, customer reliability, outage management, etc. This facilitates breaking down the information silos and driving enterprise integration and improvements via process, people and technology. An essential element of this vision is to provide seamless integration of data between the asset registry, work orders, scheduling/dispatch and GIS system using mobile technology. Cornerstone Phase 3 will build on the success of Phases 1 and 2 and further enhance integrated planning by expanding Hydro One’s SAP solution and integrating key systems/technologies and specialized packaged point solutions to drive additional business value, improve end-to-end process efficiency and improve asset lifecycle management analytics/decisions. This includes adding SAP functionality by turning on new SAP modules (including workflow for process control); integrating specialized software applications for reliability centred maintenance optimization (RCM) and scheduling/dispatch; interfacing key enterprise systems (i.e. graphical information system, operating, fleet, telecom, protection & control, etc); incorporating new assets into the asset registry (e.g. information technology assets, real estate assets, metering assets, etc); deploying enterprise mobile strategy across the province; and consolidating end-user databases. The proposed go-live date for Cornerstone Phase 3 is 2010. Results: Cornerstone Phase 3 will deliver the following business benefits • Provide SAP integration to operating, scheduling/dispatch and GIS system using mobile technology • Provide specialized RCM software application to monitor/analyze preventative maintenance results, validate asset

models, and facilitate strategic/scenario planning that is focused on improving asset lifecycle management decisions • Consolidate and eliminate duplicative end-user databases/applications • Streamline processes and improve information transparency

Costs1: 2007 ($M) 2008 ($M) 2009 ($M) 2010 ($M) Total ($M)

Capital * and MFA 27.2 18.2 20.8 66.2 OM&A and Removals 2.4 1.6 1.8 5.8

Gross Investment Cost 29.6 19.8 22.6 72.0

Capital Contribution

Net Investment Cost 29.6 19.8 22.6 72.0 *Includes overhead and AFUDC at current rates.

Hydro One Networks – Investment Summary Document Investment Category: Information Technology

Reference # Investment Name Gross Cost In-Service DateIT3 Mobile IT - 2009 $3.0M 2009 IT3 Mobile IT - 2010 $4.0M 2010

Need:

This investment is required to permit managers and staff access to critical systems and information regarding work crews who perform data collection (asset condition assessments, inspections), work management, and time and accomplishment reporting activities. Additionally, other business functions and services can be enabled through a common mobile information technology infrastructure including enhanced customer service. Greater than 50% of the Hydro One organization performs or supports work in the field. By 2010, the field work is expected to increase substantially over that experienced in 2005. If this investment is not undertaken, there is an ongoing risk of delayed information, inefficiencies and/or errors and omissions being encountered with data entry from field staff using current processes and tools. Hydro One’s overall strategy of an adequately equipped mobile work force will be delayed and the quality of data within the recently deployed SAP – Asset and Work Management solution will be at risk. Summary:

Based on the business and technology mobility strategy recently completed, each line of business has mobility needs for applications and data for data collection, work management, and time and accomplishment reporting processes. Significant resources are used to manage and report on field-based activities (planned maintenance), and respond to unplanned/emergency maintenance activities. Project reporting and activity planning based on timely and accurate scheduling of information for both goods and services as well as manpower and equipment require access to critical information using mobile computing tools. After consideration of alternatives, the preferred plan is to provide mobile application tools to field staff. This investment will provide tools in the areas of data collection, work management, time and accomplishment reporting that deliver data to support business processes from Grid Operations to Asset Management, among others. This investment provides additional commercial software products, enhancements to existing software products and the installation, configuration and integration of those products. Results:

• Improved Asset Decision Quality: Provide immediate access to more comprehensive and integrated asset data in corporate systems, contributing to consistency and timeliness in asset decisions.

• Increased Productivity leading to Throughput and Visibility: With the ability to capture data at source as well as enable remote connectivity, we will enable one-time and near-time data entry and workflow approval.

• Prevention of rework and re-visits: Asset condition assessment surveys on occasion require some rework or a revisit to the site. There is an anticipated general reduction in such rework as this initiative is implemented.

• Timely Investments: Ability to make efficient decisions regarding field assets and their replacement scheduling will be assisted by additional and available information. With increased volumes of asset condition information, investment planners can utilize and analyze this information to strengthen decisions that replace assets at the right time, not sooner than required nor too late, avoiding undue risks to service levels.

• Increased Customer Service Levels: With the ability of real-time work status updates and we will be able to more accurately update our customers on appointment times and expected delays.

Hydro One Networks – Investment Summary Document Investment Category: Fleet Shared Services

Reference # Investment Name Gross Cost In-Service DateC1 Fleet Services 2009 Capital Requirements $39.7M Late 2009 C1 Fleet Services 2010 Capital Requirements $37.9M Late 2010

Fleet costs are included in Shared Services capital and allocated to the transmission business as outlined in the Fleet Capital Exhibit D1, Tab 3, Schedule 9 and the Costing of Work Exhibit C1-4-1. Need:

This investment is required to meet vehicle and fleet capital requirements arising from increased work programs and staff growth. Not proceeding or delaying this investment would lead to lower-than-required fleet levels, would change the vehicle mix and may cause a shift to use of more expensive rental units. Extending the life of the vehicles past their optimum level of economic and reliable operations will result in increased equipment and user operating costs, reduced reliability and unsafe operating conditions. Summary:

Hydro One controls and manages 5,421 fleet units which support the various lines of business (LOBs) including Provincial Lines, Stations, Forestry and Engineering and Construction Services (E&CS). Fleet vehicles must be maintained at an optimum level to comply with various regulations (Highway Traffic Act, CVOR regulations, etc.) and to maintain LOB productivity by minimizing downtime and travel time and taking advantage of technology improvement opportunities. Present replacement criteria are based on manufacturers' recommendations and repair history. Light vehicles are replaced after 6 years or 180,000 km, service trucks are replaced after 6 years or 200,000 km, and work equipment is replaced after 8 – 10 years or 330,000 km. This is used as a guideline and ultimately it is used in combination with break-even analysis, including replacement cost, depreciation, operating cost and potential life expectancy. Of the capital required in 2009 and 2010, $35M is required to replace units which have reached their end of life cycle. Other key elements of the 2009 capital program include: • additional equipment requirements for the 2nd year Forestry Apprenticeship Program and additional staff. • additional equipment requirements for the Provincial Lines Apprenticeship Program and additional staff. Key elements of the 2010 capital program include:

• Replacement of an aging helicopter. Results:

• Reduced operating costs and increased reliability.

Hydro One Networks – Investment Summary Real Estate Facilities 2009 & 2010

Investment Driver: Real Estate Facilities Capital for 2009 & 2010 Reference # Investment Name Gross Costs In-Service Date

C2 Real Estate Facilities 2009 Capital Requirements $30.7M 2009 C2 Real Estate Facilities 2010 Capital Requirements $14.3M 2010

Need:

Facilities Capital Work Program addresses facilities portfolio accommodation needs in terms of facility improvements, building additions and new facilities in line with Company operational requirements. This program also focuses on ensuring critical facility structural and other building integrity improvements are made to Administrative and Service Centres to ensure appropriate maintenance and operation of the asset in the longer term. The aging facilities asset base in conjunction with operational needs of the business units requires capital investment in order to continue to provide adequate accommodation space. Approximately 40% of Administrative and Service Centres facilities infrastructure are estimated to be more than 40 years old. The program focuses on undertaking the critical component replacement work on a priority basis. Not proceeding with this capital investment would result in a lack of adequate office space and facilities for new and current staff, thereby risking business plan accomplishment. Hydro One Networks head office is a leased facility comprising approximately 250,000 square feet. The lease will be ending on January 31, 2010. Currently, long term accommodation alternatives are being investigated with the need to have a new lease completed by January 2009 and subsequent execution of required improvements. It is expected that all alternatives, including the renewal of the current premises will entail extensive tenant improvements. The existing premises are approximately 25 years old and the interiors are in need of upgrade and/or replacement. Similarly, alternative accommodations are being offered in base building condition, which will require complete tenant improvements. In all instances, the overall cost of completing improvements, which entails design, engineering and construction, are estimated approximately in the range of $10.M to $12.M. Similar to tenant interiors, existing furniture systems within the head office facilities are in need of replacement because of age related use. The cost of replacing these furniture systems are estimated at approximately $6.0M to $7.0M. Investment Summary:

Key program work activities include: • Addressing Company accommodation requirements in terms of new buildings, buildings additions and major facility

renovations including head office accommodation needs. • Replacement of major building components including roof structures, windows, heating, ventilating and air

conditioning (HVAC) systems and other structural elements and building systems; • Purchase of MFA (office furniture) • Water treatment upgrades to improve quality and reliability of water supply, including conversions to municipal

supply; Capital investment of $30.7M is required for 2009 to provide for head office accommodation improvements, address need for new buildings, buildings additions and provide for facilities improvements in order to continue to provide adequate accommodation space to support work programs. Capital investment of $14.3M is required for 2010 to address need for new buildings and building additions and provide for field facilities improvements in order to continue to provide adequate accommodation space to support work programs. Results:

• Secured necessary accommodation space for head office and field in line with work programs requirements. • Improved Administrative and Service Centre facilities through replacement of roof structures, windows, HVAC

systems and other structural elements.

Hydro One Networks – Investment Summary Document Investment Category: Service Equipment Shared Services Capital


C3 Service Equipments 2009 Capital Requirements $11.6M Late 2009 C3 Service Equipments 2010 Capital Requirements $11.3M Late 2010

Service Equipment costs are included in Shared Services capital and allocated to the transmission business Need:

Minor fixed asset expenditures for service equipment are required to replace end of life and obsolete equipment, and to provide sufficient levels of new equipment consistent with work program and staffing expansions. Service equipment is used by field staff to carry out day-to-day work activities including specialized transportation equipment to and from the work site. This equipment must be maintained at appropriate levels such that work can be executed in a safe and cost effective manner. Inadequate investment will result in equipment breakdowns or increased labour time. Overall this would adversely impact job costs, outage duration, and work program accomplishments. Summary:

Minor fixed asset (MFA) spending for service equipment represents items > $2000 each exclusive of general computer MFA requirements, real estate MFA requirements and fleet MFA requirements, addressed elsewhere, which are necessary to replace end of life equipment used by field staff to execute the work program in a cost effective manner. Purchases in this category include: - Minor specialized transportation equipment such as snowmobiles, all terrain vehicles, boats, barges, and related

accessories to transport crews to off-road work sites, - Measuring and testing equipment to carry out a variety of work activities including trouble shooting, performance

testing of equipment, wood pole density testing, battery testing, relay test systems, moisture analyzers, circuit breaker testers, resistance testers, metering technical testing equipments, etc.,

- Tools and a wide range of other miscellaneous equipment such as PCB waste bins, portable generators, cabling trailers and equipment, satellite equipment for mobile emergency preparedness, insulator power washing equipment, Automated External Defibrillators devices, conventional line tensioning puller ropes, Maintenance shop equipments to describe a few.

- Relatively large tanker units utilized in the service of transformers including SF6 gas carts, degassifiers used to remove impurities from insulating oil, heated oil tankers, oil filters, oil farm upgrades, vacuum dry out machines and dry air machines.

MFA service equipment requirements will vary year to year depending on a number of factors including the overall asset condition, the number of large cost “one-time” items that occur from year to year, the size of the work program and associated staffing levels projected in the business plan, random equipment failures, unanticipated system impacts, weather severity and trends which affect the intensity and use of certain types of equipment particularly related to storm and trouble call programs. Spending in 2009 is focused on additional service equipment required to accommodate the growth in the work program and the result of end of life replacement of specific large equipment such as oil tankers, degassifiers, vacuum dry out and air supply equipment used to overhaul and maintain large power transformers and manage the related oil requirements. Such purchases are a part of long term replacement plans to replace end of life equipment that are expected to extend to 2010 and beyond.

Results:

• Maintain equipment and tool fleets at required levels to execute the 2009 & 2010 transmission OM&A and capital program

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