Toronto Hydro-Electric System Limited ( THESL ) 2011-2020 Electrical Distribution Capital Plan

Toronto Hydro-Electric System Limited EB-2010-0142 Exhibit D1 Tab 8 Schedule 10 ORIGINAL (33 pages) Toronto Hydro-Electric System Limited ( THESL ) 2011-2020 Electrical Distribution Capital Plan June 2010 Revision 1.0

1 INTRODUCTION... 4 1.1 DESCRIPTION OF TORONTO HYDRO-ELECTRIC SYSTEM LIMITED... 4 1.2 BACKGROUND... 4 1.3 OBJECTIVE... 4 1.4 SCOPE... 4 1.5 SUMMARY OF INVESTMENTS... 5 1.6 COMPARISON TO 2010-2019 PLAN... 6 2 ASSET MANAGEMENT... 7 2.1 THESL ASSET MANAGEMENT... 7 2.2 ASSET MANAGEMENT OBJECTIVES... 7 2.3 DISTRIBUTION PLANT CAPITAL INVESTMENT PLANS... 7 2.4 DISTRIBUTION PLANT MAINTENANCE INVESTMENT PLANS... 8 2.5 ASSET MANAGEMENT CAPITAL INVESTMENT STRATEGY... 9 3 OPERATIONAL INVESTMENTS... 10 3.1 SUSTAINING CAPITAL FORECASTS... 10 3.2 REACTIVE CAPITAL... 17 3.3 CUSTOMER CONNECTIONS... 18 3.4 ENGINEERING CAPITAL... 19 4 EMERGING PORTFOLIOS... 21 4.1 STANDARDIZATION... 21 4.2 DOWNTOWN CONTINGENCY... 22 4.3 WORST PERFORMING FEEDER PROGRAM... 23 4.4 SMART GRID OPERATIONS... 24 4.5 INFRASTRUCTURE PLANT RELOCATION... 25 4.6 STATIONS SYSTEM ENHANCEMENT... 27 4.7 SECONDARY UPGRADES... 30 5 CONCLUSION... 31 APPENDIX A... 32 Page 1

Table 1 - THESL s Ten Year Plan (For the complete table, refer to Appendix A)... 5 Table 2 - Reliability Performance without MEDs and Loss of Supply... 8 Table 3 - Ten-year plan for summary for sustaining capital... 16 Table 4 - Reactive Capital Investments Summary ($ millions)... 17 Table 5 - Ten-Year Reactive Capital Estimated Capital Costs... 17 Table 6 Ten year Customer Connections Estimated Capital Costs... 19 Table 7 - Ten Year Engineering Capital Estimated Capital Costs... 20 Table 8 Ten-Year Standardization Estimation Capital Costs... 22 Table 9 - Ten-Year Downtown Contingency Estimated Capital Costs... 23 Table 10 - Ten-Year WPF/FESI7 Estimated Capital Costs... 24 Table 11 - Ten-Year Smart Grid Estimated Capital Costs... 26 Table 12 - Ten-Year Externally Initiated Plant Relocation Estimated Capital Costs (Excluding Recoveries)... 26 Table 13 - Ten-Year Externally Initiated Plant Relocation Estimated Capital Costs (Excluding Recoveries)... 27 Table 14 - Ten-Year Stations System Enhancement Estimated Capital Costs... 29 Table 15 - Ten-Year Secondary Upgrades Estimated Capital Costs... 30 Page 2

Figure 1 Comparison of the new and old 10-year plan... 6 Figure 2 - Asset Life Cycle Optimization... 11 Figure 3 - U/G Direct Buried Cable EOL Stream Results (Cable Only)... 12 Figure 4 - U/G Transformer EOL Stream Results... 13 Figure 5 - U/G Padmount Switches (PMHs) EOL Stream Results... 14 Figure 6 - Network Units EOL Stream Results... 15 Figure 7 - Toronto Transit City Light Rail Plan (supplied by TTC)... 26 Page 3

1 Introduction 1.1 Description of Toronto Hydro-Electric System Limited Toronto Hydro-Electric System Limited ( THESL ) owns and operates $1.9 billion of capital assets comprised primarily of the City of Toronto s electrical distribution system. As the largest municipal electrical distribution company in Canada, THESL supplies approximately 690,000 customers within the City of Toronto which accounts for approximately 20% of Ontario s electricity consumers and 18% of the provinces electricity demand. THESL s business is regulated by the Ontario Energy Board ( OEB ), which has broad powers relating to licensing and standards of conduct and service. The OEB is also responsible for the regulation of rates charged by all local distribution companies in Ontario, including THESL. 1.2 Background This version of the Electrical Distribution Capital Plan (2011-2020, Version 1.0) supersedes version 3.2 of the 2010-2019 plan which was filed in August 2009. This report is the result of the ongoing distribution capital investment planning process. The purpose of this process is to ensure that standards for safety and system reliability, as outlined in Toronto Hydro s Conditions of Service, are met. The capital investment process also gives consideration to the requirements of external stakeholders that include City of Toronto, Toronto Transit Commission, Hydro One Networks Inc., other utilities, customers and other developers. 1.3 Objective The objective of this plan is to outline THESL s proposed annual capital expenditures over the next ten year horizon. These planned expenditures are necessary to sustain, enhance or upgrade the distribution system while addressing various operational and emerging issues. Variances and deviations from previously filed plans are also captured. 1.4 Scope This document describes THESL s planned capital spending for each of the next ten year, broken down by portfolio, with the intention of setting an achievable and prudent scope of the work and annual budget for the foreseeable future. This plan does not detail or justify individual projects, nor does it include capital investments in meter systems, capital investments related to individual customer connections or specific distributed generation systems or proposals. Page 4

1.5 Summary of Investments The current ten year plan is based on the 2010-2019 Electrical Distribution Capital plan submitted in August 2009. The revised version submitted here has been updated to reflect the work completed (or on target to be completed) in 2010, an additional year of planning, as well as recent developments such as the Green Energy Act and ever evolving customer demand. The capital spending portfolios and their yearly allocations are presented in Table 1 below. Portfolio Year Total Capital Category Number 2011 2012 2013 $ Millions 1 Underground Direct Buried Cable $62.6 $60.0 $50.0 $342.6 2 Underground Rehabilitation $49.8 $88.2 $89.1 $951.2 3 Overhead Systems $46.7 $73.1 $65.8 $505.5 4 Network Vaults $15.1 $26.0 $26.0 $204.1 5 Transformer Stations $14.3 $15.4 $15.5 $194.3 6 Municipal Stations $8.2 $8.4 $8.4 $85.2 SUSTAINING CAPITAL TOTAL $196.7 $271.0 $254.8 $2,282.9 7 Reactive $22.2 $21.0 $20.0 $193.2 8 Customer Connections $41.8 $50.0 $50.0 $407.8 9 Engineering Capital $43.3 $45.0 $44.0 $422.3 TOTAL TRADITIONAL OPERATIONS $304.0 $387.0 $368.8 $3,306.3 EMERGING REQUIREMENTS 10 Standardization - PMH / SCADAmates and CSPs $4.7 $2.8 $4.4 $29.5 11 Downtown contingency (feeder-tie) $5.4 $12.0 $12.0 $225.0 12 Worst Performing Feeder (WPF) $10.9 $10.0 $10.0 $82.9 13 Smart Grid Operations $1.3 $1.3 $1.3 $20.5 14a Externally Initiated Plant Relocation $9.7 $15.0 $15.0 $109.7 14b Transit City $2.5 $2.5 $2.5 $25.0 15 Stations System Enhancement $48.1 $74.0 $29.0 $152.4 16 Secondary Upgrades $10.0 $10.0 $10.0 $70.0 TOTAL EMERGING REQUIREMENTS $92.6 $127.6 $84.2 $715.0 TOTAL CAPITAL PLAN $396.6 $514.6 $453.0 $4,021.3 Contributions from Customers $21.2 $25.5 $25.5 $210.1 TOTAL (NET) $375.5 $489.1 $427.5 $3,811.2 Table 1 - THESL s Ten Year Plan (For the complete table, refer to Appendix A) Page 5

1.6 Comparison to 2010-2019 Plan This report can be considered a living document. THESL s capital plans depend on a number of factors, including (among other things) the economy, Ontario Energy Board direction, provincial legislation, current industry practice, analytical tools and availability of condition data. THESL is constantly gathering and analyzing new data, and as a result, detailed year-to-year plans will deviate to a certain degree based upon current conditions and special and/or unforeseen circumstances. Despite this, the long-term direction is expected to remain in alignment with this document. For the reasons outlined above, the ten year plan presented here represents current THESL s assessment of the distribution systems projected needs for the next decade. A comparison of the current ten year plan and the version filed in August 2009 is provided in Figure 1 below. Figure 1 Comparison of the new and old 10-year plan As shown above, the overall spending trend is similar to the previous plan. The relatively large spread between the 2012 investments illustrates the amount of spending required to catch up to the intended plan line. Deviations in individual portfolios will be explained throughout this document. Page 6

2 Asset Management 2.1 THESL Asset Management The Asset Management (AM) division of Toronto Hydro consists of four departments - Standards and Policy Planning, Capacity Planning, System Reliability Planning and Procurement. AM s primary responsibility is to ensure that based upon an assessment of system needs, the right actions are being performed on the right assets at the right time. From this assessment, AM scopes and plans work for construction service providers in order to maintain alignment with THESL s customer service, reliability, environmental, safety and service related corporate objectives. 2.2 Asset Management Objectives The objectives of Asset Management are to invest into the distribution plant in a financially sound manner, in order to: Mitigate risks Maintain system performance (reliability) Maintain acceptable customer service 2.3 Distribution Plant Capital Investment Plans The majority of THESL distribution system capital investments are focused on rebuilding and sustaining existing distribution plant. Regardless of any maintenance programs, distribution equipment will ultimately fail or become obsolete, reaching a point where it is no longer cost effective to maintain a given piece of equipment. Distribution system projects are derived through analysis of performance data (failure frequency and impact), condition assessment results, feedback from field staff and engineering experience. It may also be economically and operationally beneficial to enhance certain parts of the system, through such measures as voltage conversion and/or feeder automation for a given project location. In order to accomplish the analysis as described above, THESL utilizes several tools. Asset Condition Assessment (ACA) is a condition assessment methodology, fundamental to asset management for electric utilities. Feeder Investment Model (FIM) is a risk model for identifying which assets have reached the end of their economic life. Asset Investment Strategy (AIS) is a highlevel value model that uses THESL s Business Pillars to facilitate comparison of spending proposals across portfolios. Together, these three tools form the backbone of THESL s asset management program. The goals of THESL s distribution system capital investments are to improve performance statistics such as failure frequency, outage duration, and total customer interruptions. Table 2 illustrates benchmark statistics such as the System Average Page 7

Interruption Frequency Index (SAIFI) and System Average Duration Index (SAIDI) trend (major event days (MEDs) and loss of supply have been removed from the data) over the last five years. Service Reliability Indicators Performance Measures (without MEDs & Loss of Supply) SAIDI (number of hours of interruption per customer) SAIFI (number of interruptions per customer) CAIDI (number of hours per interruption) 2005 2006 2007 2008 2009 Actual Actual Actual Actual Actual 1.17 1.17 1.25 1.22 1.24 1.62 1.84 1.77 1.66 1.51 0.72 0.64 0.71 0.73 0.82 Table 2 - Reliability Performance without MEDs and Loss of Supply In general, THESL s reliability performance has been trending downwards over the last five years. The Electrical Distribution Capital Plans aim to address this downward trend by replacing and modernizing deteriorating assets and plant. THESL has also benchmarked its reliability performance against other major utilities. Toronto was found to rank 7 out of 9 for SAIDI and 7 out of 8 for SAIFI (SAIFI data was not available for Miami). The report points out that while Toronto is the third largest financial centre in North America, further growth is hindered by the relatively poor reliability numbers as companies looking to locate in Toronto may find the comparison discouraging. The benchmark study also reinforced many of the existing upgrades outlined in previous Capital Plans that THESL have been performing. In addition, the study recommended accelerating the replacing and modernizing deteriorating assets and plant in order to improve reliability performance. 2.4 Distribution Plant Maintenance Investment Plans Investment plans for distribution plant maintenance are developed by applying reliabilitybased methods. Reliability Centred Maintenance ( RCM ) using the Aladon RCM II Methodology is designed to establish the optimal maintenance required to achieve a desired level of operational performance from an asset within its current operating context. All of THESL s distribution system assets have been analyzed by multidisciplinary teams. RCM establishes the asset functions, identifies how the asset can fail to perform each function (termed functional failures ), identifies potential causes of these failures (the failure modes ) and identifies the impacts that these failures would have on the system ( failure effects ). Following this analysis, the failure is classified as hidden or evident and any safety, environmental or operational impacts are analyzed. At each step it is Page 8

decided if an immediate maintenance task can be carried out based on a repairable failure-predicting condition, if a proactive cyclical task is warranted, or if a scheduled replacement should take place. All decisions are based on technical feasibility and how worthwhile the option is judged to be. A task is deemed worthwhile if the average annual cost of the maintenance activities is less than the average annual cost of the failure over the entire population of the asset class. The proposed task is mandatory if there are safety or environmental considerations. Once maintenance programs have been established, THESL s enterprise resource management system (Ellipse) manages the programs in a number of ways. The maintenance procedures themselves are recorded in a Standard Job, which in effect serves as a template for the Work Order to carry out a given maintenance task. Cyclical maintenance is managed via Maintenance Scheduled Tasks ( MSTs ), which track the required dates and frequencies for the various tasks. Planned maintenance inspection forms exist for all assets that have RCM analyses, although not all forms can be electronically completed in the field. The inspection results are tied to the asset in question and stored in the Condition Monitoring module within Ellipse where it is electronically searchable. On-condition maintenance tasks are triggered using the Condition Monitoring functionality, which compares inspection results or performance measures against trigger values, and creates Work Orders should the triggers be exceeded. 2.5 Asset Management Capital Investment Strategy In the past, sustaining capital investments have predominated over other types of capital investments. However, in recent years it has become clear that significant investments are required to address operational, redundancy, safety, non-discretionary and obsolescence issues. THESL s capital investment strategy is to identify the areas of the distribution system (in terms of both geography and design) that are under-performing. For example, for proposed sustaining capital investments the condition of key asset classes such as direct buried underground cable is one of the strongest drivers for the forecasted size of the sustaining capital investments. Further improvements to the system will be implemented through the introduction of system feeder automation, SCADA control and online data collection in certain systems such as the Network and URD (Underground Residential Distribution). These improvements will enable THESL to fulfill new obligations under the Green Energy Act ( GEA ), such as the accommodation of bidirectional power flow. Page 9

3 Operational Investments 3.1 Sustaining Capital Forecasts 3.1.1 Asset Condition The condition of THESL assets was originally established based on an Asset Condition Assessment (ACA) performed by THESL in 2006. In 2009, an assessment was performed using the Health Index (HI) methodology applied within THESL s HI Calculator. This tool is used to derive and develop HI scores for distribution system assets. By comparing results from 2006, 2009 and equipment performance data, it was concluded that the current ACA process is significantly improved when compared to the process from 2006. This can be attributed to the use of refined formulas for determining an HI rating, improved data granularity and a larger pool of condition data from the field. HI calculations are consolidated within the application and concentrated efforts have been made to modify network asset inspection practices to include end-of-life condition information. 3.1.2 Distribution Capital Investment Planning Process In recent years, THESL has shifted from a reactive capital investment planning process to a proactive approach. The intent of this approach is to achieve and maintain a desired level of asset operating risk based upon the historical performance and risk thresholds of different asset classes, feeders and individual equipment. Detailed annual capital plans are developed as part of the business planning and budgeting cycle. These plans consist of: The ten-year plan which is developed to review and address the long-term distribution system needs. The ten-year plan identifies THESL s long term capital requirements. The short-term capital program which identifies specific projects for implementation during the current year. All THESL distribution projects are created and prioritized with consideration to the following five criteria: 1) Risk mitigation 2) Financial impacts 3) System Performance 4) Personnel Safety 5) Customer needs These criteria assist the management team to consistently maximize the value of the capital program. Page 10

Capital investment planning begins with an evaluation of the needs and planned requirements of external stakeholders, including, but not limited to, the City of Toronto, Toronto Transit Commission, Hydro One Networks Inc., other utilities, customers, developers and users of the street allowance. To determine capital needs for existing distribution assets, in 2008, THESL introduced a risk-based approach to assist engineers in identifying the optimal intervention time for each asset based on asset condition, risk, criticality, and life-cycle costs of asset ownership. This methodology is referred to as the Feeder Investment Model (FIM) and has been used to identify some of the Underground Sustaining Capital projects that need to be executed mitigate risk to our plant, staff and the public. Figure 2 below illustrates the economic concept behind the FIM approach. The minimum point of the U-shaped total cost curve is the optimal replacement timing where life-cycle costs are minimized. This point is demonstrated below and coincides on the x-axis at the Equivalent Annual Cost level or the EAC. Figure 2 - Asset Life Cycle Optimization The main advantages of the new approach include: The calculation of economic risks for each distribution system asset, by examining both the assets probability and consequences of failure. Derivation of an optimal intervention time for each asset, based upon a balance between economic risks and capital costs. Providing the big picture to AM engineers, allowing them to examine an entire feeder holistically and formulate projects on the basis of the highest risk assets. Currently, the risk-based analysis has been applied to four of THESL s major asset classes - namely: Page 11

1) Underground Direct Buried Cable 2) Underground Transformers (Submersibles, Vault and Pad-mounts) 3) Underground Pad-mounted Switches (PMHs) 4) Network Units (Network Transformer and Protector) $250.0 million Underground Direct Buried Cable Replacement and Reactive Program (2011-2020) $200.0 million Required Spending $150.0 million $100.0 million $50.0 million $0.0 million 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Figure 3 - U/G Direct Buried Cable EOL Stream Results (Cable Only) The FIM indicates that there is a backlog of underground direct buried cable work to be performed in 2011 (Figure 3), since based on the model, these assets should have been intervened upon already. The results above are in alignment with the actual field performance of this cable type, which has been worsening over time. It should be noted that these graphs only account for the capital costs of the cable replacement activities, and do not account for any additional enhancement costs established during the project planning, design and execution phases. For practical reasons (planned outages, resource requirements, permits, and spending shock) it is not feasible to undertake this large investment within a single year. Therefore, THESL proposes to spread this spending over several years. Year Page 12

U/G Distribution Transformers Extrapolated Replacement and Reactive Program (2011-2020) Required Spending $4.0 million $3.5 million $3.0 million $2.5 million $2.0 million $1.5 million $1.0 million $0.5 million Total Spending Total Quantity 250 200 150 100 50 Quantity Replaced per Year $0.0 million 0 Year Figure 4 - U/G Transformer EOL Stream Results For Underground Transformers (Figure 4), the FIM indicates a backlog that should be addressed in 2011, in addition to another spike in 2014. These results are in alignment with the high failure probabilities associated with submersible transformers, which account for approximately 50% of the total U/G transformer population. Page 13

Underground Padmount Switches Replacement and Reactive Program (2011-2020) $18.0 million 600 Required Spending $16.0 million $14.0 million $12.0 million $10.0 million $8.0 million $6.0 million $4.0 million $2.0 million Total Spending Total Quantity 500 400 300 200 100 Quantity Replaced per Year $0.0 million 0 Year Figure 5 - U/G Padmount Switches (PMHs) EOL Stream Results For Underground Pad-mounted Switches (Figure 5), the FIM indicates a significant backlog that should be addressed in 2011. These results are in alignment with both the high failure probabilities and high impacts associated with Pad-mounted switches. In this case, the open-air design of the Pad-mount Switch assets allow for a high probability of a flashover to occur within the asset. These assets are typically configured in such a way that the entire feeder will experience the resulting outage. As was the case with direct buried cable, THESL proposes that these assets be replaced over several years to account for resource requirements, planned outages and spending shock. Page 14

Network Units Extrapolated Replacement Program Required Spending $50.0 million $45.0 million $40.0 million $35.0 million $30.0 million $25.0 million $20.0 million $15.0 million $10.0 million $5.0 million $0.0 million Total Spending Total Quantity 450 400 350 300 250 200 150 100 50 0 Quantity Replaced per Year Year Figure 6 - Network Units EOL Stream Results For Network Units (Figure 6), the FIM indicates a backlog that should be addressed in 2011. These results are in alignment with the high impact of failure associated with most Network Units. The FIM takes into account the risk associated with a full failure to the connected network grid, which would result in many large customers experiencing an outage. THESL proposes that these assets be replaced over several years to account for resource requirements, planned outages and spending shock. The analysis results in an economically optimized replacement program for each asset class. In the future, THESL plans to extend this approach to all key asset classes to make the planning methodology more consistent and tie together Asset Management activities in a systematic process. This will help THESL achieve performance and safety goals at the lowest operating costs. In conclusion, THESL has been advancing its Asset Management approach by introducing risk as a key driver for asset-related interventions and decisions. THESL is working to continually improve and further develop the risk-based intervention decisionmaking model, tools and methodologies. THESL will also continue to improve the quality of data related to condition, failure rate, and consequences of failure. Additional data will allow engineers and managers to estimate optimal intervention periods as well as the costs and consequences of delaying intervention with more precision, and, consequently, produce more effective capital programs. Page 15

3.1.3 Sustaining Capital Requirements THESL forecasts that it will need to make sustaining capital investments of approximately $2.283 billion over the next ten years to maintain asset condition. Over $342 million will need to be invested to replace underground direct buried cable. In addition, THESL also forecasts that the rest of its underground plant and overhead plant will need $951.2 million and $505.5 million respectively over the next ten years. Investments in transformer stations, municipal stations and network systems will require investments of $194.3 million, $85.2 million, and $204.1 million respectively over the next ten years. The ten-year forecast for sustaining capital, broken down by distribution group is presented in Table 3 below. Portfolio Year Total Capital Category Number 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 $ Millions 1 Underground Direct Buried Cable $62.6 $60.0 $50.0 $50.0 $50.0 $50.0 $5.0 $5.0 $5.0 $5.0 $342.6 2 Underground Rehabilitation $49.8 $88.2 $89.1 $90.9 $94.6 $107.9 $110.3 $102.0 $109.3 $109.3 $951.2 3 Overhead Systems $46.7 $73.1 $65.8 $59.7 $55.2 $54.0 $49.0 $34.0 $34.0 $34.0 $505.5 4 Network Vaults $15.1 $26.0 $26.0 $26.0 $21.0 $21.0 $21.0 $16.0 $16.0 $16.0 $204.1 5 Transformer Stations $14.3 $15.4 $15.5 $19.5 $19.8 $20.6 $21.2 $22.0 $23.0 $23.0 $194.3 6 Municipal Stations $8.2 $8.4 $8.4 $8.5 $8.5 $8.5 $8.6 $8.7 $8.7 $8.7 $85.2 SUSTAINING CAPITAL TOTAL $196.7 $271.0 $254.8 $254.6 $249.1 $262.0 $215.1 $187.7 $196.0 $196.0 $2,282.9 Table 3 - Ten-year plan for summary for sustaining capital The sustaining capital program is divided into six portfolios: - Underground Direct Buried Cable: This portfolio addresses the removal of all underground direct buried cable in the THESL distribution system. In general, direct buried cable has been identified to fail more frequently than other types of installation. This is due to direct buried cable s susceptibility to water ingress and the lack of cable jacketing. - Underground Rehabilitation: This portfolio addresses the replacement and rehabilitation of all deteriorating and obsolete underground assets in the THESL distribution system. This includes the replacement of XLPE cable in duct and associated aging and nonstandard distribution assets, proactive PILC cable replacement and conversions of rear lot plant to front lot underground services. - Overhead Systems: This portfolio addresses the replacement and rehabilitation of all deteriorating and obsolete overhead assets in the THESL distribution system. This includes poles, pole-top transformers, switches and elimination of box design construction. - Network Vaults: This portfolio addresses all network asset upgrades in the Old Toronto district. This includes the replacement of any transformers and civil infrastructures that have been identified as being in poor condition. In addition, it also includes the replacement of non-standard assets such as Automatic Transfer Switches and Reverse Power Breakers. - Transformer Stations: This portfolio addresses any upgrade of Transformation assets such as switchgear and circuit breakers. - Municipal Stations: This portfolio addresses any upgrade of Municipal Station assets such as transformers, switchgear and circuit breakers. Page 16

3.2 Reactive Capital Reactive capital investment includes funds for the replacement of failed distribution components, and also includes funding allocated for the proactive enhancement of system reliability. Funds in this portfolio are allocated based on past practice and trending. The purpose of this portfolio is to maintain system reliability at an acceptable standard. Overhead work includes spot replacement of poles, wires, transformers and overhead line hardware. Underground work includes replacement of cables, splices, joints, transformers, switches and civil infrastructure. Forecasting for both these investments is based upon historical performance and trending data. Stations work refers to all reactive work on system components located between the demarcation point with HONI supply and the line disconnect device on the distribution feeder circuit. Table 4 summarizes the total capital requirements for reactive capital investments for the 2011 test year, as well as the historical and bridge years. 2008 Actual 2009 Actual 2010 Bridge 2011 Test Underground Assets 11.2 9.4 12.9 14.6 Overhead Assets 7.6 10.7 6.3 7.3 Stations Assets 0.5 0.6 0.2 0.2 Total Reactive Capital 19.3 20.7 19.4 22.2 Table 4 - Reactive Capital Investments Summary ($ millions) *Capital costs for FESI and WPF Improvement of $10.9 million are included in the Worst Performing Feeder (WPF) portfolio rather than the Reactive Capital portfolio. 3.2.1 Cost Table 5 below contains the estimated costs associated with the Reactive Capital program across a ten year time horizon. YEAR 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 TOTAL $ millions $22.2 $21.0 $20.0 $20.0 $20.0 $18.0 $18.0 $18.0 $18.0 $18.0 $193.2 Table 5 - Ten-Year Reactive Capital Estimated Capital Costs Page 17

3.3 Customer Connections 3.3.1 Connection Charges When THESL receives a request to connect a new customer load or upgrade connection capacity for an existing customer, an Offer to Connect is issued to the customer. The Offer to Connect consists of Basic and Variable Connection Costs, a Capital Contribution and a Security Deposit. An economic evaluation is carried out to determine if the future revenues from the connected customer(s) will adequately cover the costs pertaining to the new connection or the capacity upgrade. Should the Net Present Value ( NPV ) of the costs and revenues associated with the Expansion be less than zero, a capital contribution in the amount of the shortfall is required. The amount of the capital contribution is set out in THESL s Offer to Connect to the customer. The parameters used in the Business Economic Model for the economic evaluation of the expansion project include: New Expansion Costs Basic Connection Costs Operating, maintenance and administration costs ( OM&A Costs ) Estimated Incremental Revenues 3.3.2 New Expansion Costs New Expansion Costs are the capital expenditures associated with the installation of new distribution facilities and circuits when these are essential to accommodate new customer loading and which are not used to serve other customers. If within five years from the connection date, non-forecasted customers are connected to this new plant without any further capital costs, THESL will rebate the initial customer for that customer s portion of the New Expansion that is shared with non-forecasted customers. Basic Connection Costs The Basic Connection Cost is the cost for connecting the standard 30 metre overhead service including the connection and transformation equipment. The Basic Connection Cost for 2010 is $1,315.00. The Basic Connection Cost is recovered through distribution rates. This figure is updated annually. Operating, Maintenance and Administration Costs For the purpose of determining OM&A Costs, THESL uses system average operating, maintenance, and administrative expenditures as a proxy for incremental OM&A expenditures, and apportions them as fixed costs (for Rate Class 1 and 2 customers) or as a function of $/kw of demand (for Rate Class 3, 4, and 5 customers). These values are updated annually. Page 18

Estimated Incremental Revenues Estimated Incremental Revenues are calculated using the Estimated Incremental Demand, the fixed charge and the variable charge that have been approved by the OEB for the Rate Class applicable to each individual new meter installed in connection with the expansion project. For existing customers, THESL apportions the fixed charge based on the ratio between the incremental load and the combined load. Variable Connection Costs Variable Connection Costs are the firm costs associated with the installation of connection assets above and beyond the Basic Connection Cost. The Variable Connection Costs are paid 100 percent by the customer. The Variable Connection Costs are not required for the economic evaluation of the Capital Contribution. Average Costs for Customer Connection The average costs for customer connections, including new services and upgrades to existing services, are calculated from the Capital Expenditures for the different types of services and the number of customer connections of each type per year. These costs are THESL s gross capital costs to connect customers to existing infrastructure. For some large services, the costs to connect the customer may be incurred over many months, or between fiscal years. The reporting of the physical connection is made when the customer is energized. Therefore, the average cost per customer may be skewed in a given year and is affected by the site specific conditions. 3.3.3 Cost Table 6 below contains the estimated costs associated with the Customer Connections program across a ten year time horizon. YEAR 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 TOTAL $ millions $41.8 $50.0 $50.0 $35.0 $35.0 $38.0 $38.0 $40.0 $40.0 $40.0 $407.8 Table 6 Ten year Customer Connections Estimated Capital Costs 3.4 Engineering Capital The design, construction and operation of the distribution system are based on sound engineering principles and industry experience. THESL employs Engineers and Technologists to ensure the distribution plant is designed accordingly and continues to provide efficient and reliable service. Although a portion of the costs associated with engineering, design, and operations is expensed, the majority of the effort, and associated costs, provide benefits beyond the current period and are capitalized. Page 19

THESL will be employing additional engineers, technicians and technologists to support the increased capital program and it is estimated that the requirement for 2011 is $31.5 million. 3.4.1 Cost Table 7 below contains the estimated costs associated with the Engineering Capital program across a ten year time horizon. YEAR TOTAL 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 $ millions $43.3 $45.0 $44.0 $43.0 $43.0 $43.0 $41.0 $40.0 $40.0 $40.0 $422.3 Table 7 - Ten Year Engineering Capital Estimated Capital Costs Page 20

4 Emerging Portfolios 4.1 Standardization THESL plans, designs and constructs distribution system infrastructure in accordance with approved standards. These standards are developed and maintained by THESL s Standards and Policy Planning Department and are intended to ensure that the distribution system is safe and reliable. As per the requirements of Ontario Regulation 22/04, all THESL assets must be constructed to the approved standard at the time of construction. Standard designs also facilitate harmonization of inventory items, operating procedures and maintenance procedures. As construction standards evolve, legacy inservice assets that were installed prior to the development and adoption of the current standards can become an unnecessary burden. The most problematic legacy installations are those installed prior to the amalgamation of the former utilities of Toronto Hydro, Etobicoke Hydro, North York Hydro, Scarborough PUC, East York Hydro and York Hydro into the present day Toronto Hydro. THESL upgrades these legacy assets to bring them into compliance with current standards and modernize the distribution system. Assets requiring upgrade to the current standards are selected by taking into consideration the levels of risk they pose to public and employee safety, system reliability and potential harmonization opportunities. The major standardization initiatives are described in the sections that follow. 4.1.1 SCADA MATE Switches The SCADA MATE standardization portfolio involves replacing manual switches at feeder tie points with SCADA switches to reduce the duration of customer interruptions in the event of a power interruption. The SCADA switches can be operated remotely, improving operational flexibility and reliability. Currently, not all Toronto Hydro s switches at feeder tie points are remote controlled. In the event of a fault, the remote operation of the tie switch in conjunction with the field crew s report will expedite the following operations: 1) Isolation of the faulted section 2) Transfer of customers to an adjacent feeder This results in much quicker restoration times for customers 4.1.2 Transformer Standardization Transformer standardization is intended to initiate a program to proactively identify and replace numerous non-standard transformers which currently exist in the distribution system. Many of these legacy installations were installed by former utilities prior to amalgamation as evaluation trials or pilot projects. Others were standard installations at the time. By purging non-standard equipment from the system, THESL can reduce costs through work process and material harmonization. THESL is currently focussed on elimination of the Completely Self-Protected (CSP) transformer. Page 21

4.1.3 Cost Table 8 below contains the estimated capital costs associated with the standardization portfolio across a ten year time horizon. YEAR 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 TOTAL $ millions $4.7 $2.8 $4.4 $2.4 $3.0 $2.4 $2.4 $2.6 $2.4 $2.4 $29.5 Table 8 Ten-Year Standardization Estimation Capital Costs 4.2 Downtown Contingency 4.2.1 Background Outside of the former City of Toronto area, the distribution system is of an open loop design. This design incorporates many ties between feeders, including feeders originating at different stations. As a result, this design is capable of providing support to one substation area from an adjoining substation area. The distribution system designs employed in the former City of Toronto predate the open loop design. These lack, almost entirely, ties between feeders coming from different stations. The downtown area s distribution system was designed to maximize its installed distribution capacity and it depends upon a very reliable substation to the supply the distribution system emanating from it. Consequently, a significant impact to the station customers will result if a station is adversely affected. For example, on January 15, 2009, Dufferin TS was completely shutdown due to flooding from the deluge system in the stations. As it was not possible to transfer the load of the station to any other stations, a total of 34,308 customers experienced an outage, with some customers without power for more than 24 hours. This program will provide an alternative supply to the station s feeders. In the future, projects will be planned to ensure that all stations achieve the same level of risk management using a standard planning concept. In the event of a partial or complete station outage, customers can be switched to an alternative supply from an adjacent substation. For Dufferin station feeders, 19 feeder-to-feeder ties projects were developed for implementation in 2010. In the future, remaining Dufferin station feeder ties and all remaining station feeder ties will be examined. The project will involve: 1) Installing remotely operable load break switches to permit the isolation of the Dufferin feeders from Dufferin station and, Page 22

2) Installing remotely operable load break switches to tie individual Dufferin feeders to the nearest feeder from a neighbouring station (Strachan, Bridgman, Wiltshire, or Cecil). Ties between 4.16 kv stations supplied from Dufferin will be tied to other 4.16 kv stations in a similar fashion. 4.2.2 Cost Table 9 below contains the estimated capital costs associated with the Downtown Contingency program across a ten year time horizon. It was estimated that a total cost of $287 million will be required to tie all the existing feeders in a similar manner. This sum was spread out throughout ten years and that these costs are projected on a per feeder basis. YEAR 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 TOTAL $ millions $5.4 $12.0 $12.0 $14.3 $31.3 $30.0 $30.0 $30.0 $30.0 $30.0 $225.0 Table 9 - Ten-Year Downtown Contingency Estimated Capital Costs 4.3 Worst Performing Feeder Program The purpose of the Worst Performing Feeder (WPF) program is to improve system reliability and asset performance by applying immediate adjustments to our planned program, with the intent of eventually eliminating these problem feeders from the WPF list. FESI-X refers to those feeders that have had X sustained interruptions (more than one minute) or more within one year. Worst Performing Feeder refers to those feeders which have high numbers of Customer Interruptions (CI) and corresponding Customer Minutes Out (CMO). The top 40 worst performing feeders as well as FESI-7 and FESI-12 are targeted for improvements. These feeders were chosen for manageability and resource capability. FESI-12 feeders contribute 40% of the total system interruptions. Going forward as these feeders get improved THESL s plans are to continue work on adjacent groups of WPF (e.g. FESI-5, etc.) Program Actions are implemented in order to improve the reliability of FESI feeders. Short Term Actions include: Field surveys & Inspections Asset cleaning/washing & CO2 cleaning Removal of Foreign Objects Installation of Animal Guards, New Conductor, Insulators, Poles (Structure & Accessories) Inspection of Switches & Transformers Page 23

Addition of new Nomenclature Implementation of Tree Trimming programs Long Term actions include: Asset Replacement (e.g. Fuses, Cable, Transformer, Switches) Installation of Fault Indicators System Enhancements (Automation) System Coordination Studies & Implementation Grounding Improvements System Reconfiguration External Requests for Hydro One to Review & Improve Transformer Station Performance It is projected that THESL will spend roughly $10 million/year for the next six years and roughly $5.5 million/year after that on WPF activities. The decrease in spending in the later years is due to the expectation that investments made in the first five years of the Capital Plan will result in fewer WPF activities. 4.3.1 Cost Table 10 below contains the estimated costs associated with the WPF program across a ten year time horizon. YEAR 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 TOTAL $ millions $10.9 $10.0 $10.0 $10.0 $10.0 $10.0 $5.5 $5.5 $5.5 $5.5 $82.9 Table 10 - Ten-Year WPF/FESI7 Estimated Capital Costs 4.4 Smart Grid Operations THESL plans to implement a smart grid in accordance with the Ontario government s legislation in the Green Energy and Green Economy Act, 2009 ( GEA ), passed May 14, 2009. THESL commits to deliver on the government s policy objectives in Ontario s vision for the smart grid. In 2009, THESL initiated a 25-year smart grid roadmap that is intended to bridge toward an eventual plan encompassing the full scope of THESL s actions to enable the GEA. Page 24

4.4.1 Cost Table 11 below contains the estimated costs associated with the smart grid program across a ten year time horizon. YEAR 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 TOTAL $ millions $1.3 $1.3 $1.3 $1.6 $2.5 $2.5 $2.5 $2.5 $2.5 $2.5 $20.5 Table 11 - Ten-Year Smart Grid Estimated Capital Costs 4.5 Infrastructure Plant Relocation 4.5.1.1 Externally Initiated Plant Relocation THESL infrastructure is located primarily on City of Toronto ( City ) owned roadway/property. Every year the City identifies projects to maintain their infrastructure that is located on the right of way by reconstructing roadways, widening roads, repairing/expanding sewer lines, replacing water mains, repairing bridges and other streetscape improvements to expand or maintain City owned infrastructures on right-ofways. THESL has the obligation to coordinate its existing rehabilitation work and new infrastructure build with the City s capital work programs. Additionally, the Toronto Transit Commission ( TTC ) executes construction programs to rehabilitate and expand streetcar tracks, extend subway lines, and replace steel poles on the road allowance. THESL s Asset Management team works with the City and TTC to co-ordinate work programs to minimize scheduling conflicts and identify opportunities for joint benefits. AM reviews the City's long term plans, negotiates priorities, coordinates schedules, and identifies new infrastructure requirements and additional power requirements if needed. Detailed infrastructure relocations are often impractical to identify at a very early stage because road curb realignments and/or road elevations are not known. Close coordination is required between the construction location activities amongst various parties to ensure effective infrastructure placement and minimize safety hazards. THESL can receive a capital construction recovery for a portion of its infrastructure relocation work. Road construction cost-sharing arrangements based on the Government of Ontario s Public Service Works on Highways Act, stipulate that THESL is required to pay for 100% of their materials. However, the associated labour & vehicle cost are shared 50:50. Over the past two years, THESL has improved its relationships with the City and the TTC, recognizing the importance of closely coordinating our work programs to mutual benefit. Because our relocation projects are generally non-discretionary, and cannot be postponed, we must work very closely with the City s construction and project management teams. Page 25

Recent announcements to expand public transit, rebuild roadways, bridges and highways, and improve the water delivery system have resulted in more City and TTC infrastructure programs. THESL anticipates a requirement to relocate significantly more infrastructure over the next ten years. 4.5.1.2 Cost Table 12 below outlines the estimated costs associated with externally initiated plant relocations across a ten year time horizon. YEAR 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 TOTAL $ millions $9.7 $15.0 $15.0 $15.0 $15.0 $8.0 $8.0 $8.0 $8.0 $8.0 $109.7 Table 12 - Ten-Year Externally Initiated Plant Relocation Estimated Capital Costs (Excluding Recoveries) 4.5.2.1 Transit City The Toronto Transit Commission ( TTC ) has received money from the Government of Ontario for the creation of Light Rail Transit ( LRT ) lines across the City. These projects are collectively known as the TTC Transit City Light Rail Plan ( Transit City ). See Figure 7 for an overview map of the Transit City Plan. Figure 7 - Toronto Transit City Light Rail Plan (supplied by TTC) The Transit City Plan will result in a large amount of overhead and underground relocation work over the next ten years. THESL can recover 100 percent of all relocation Page 26

costs related to Transit City work, since the TTC is not a road authority as defined in the Public Service Works on Highways Act, R.S.O 1990, CHAPTER P.49. On March 25, 2010 the Ontario government released the annual budget which included deferrals and cuts to the public transportation (Transit City) plan. The plan was announced in the spring of 2009 when various levels of government, including municipalities in the surrounding GTA area, committed a $10 billion dollar infrastructure renewal program to create jobs and improve the existing transportation system. This announcement had an impact on existing THESL plant, which is located in City rights-ofway. Due to the revised transit plan, the plant relocation work is now estimated to be $100 million over the next ten years, from the $250 million predicted last year. 4.5.2.2 Cost Table 13 below contains the estimated costs associated with Transit City relocation work across a ten year time horizon. YEAR 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 TOTAL $ millions $2.5 $2.5 $2.5 $2.5 $2.5 $2.5 $2.5 $2.5 $2.5 $2.5 $25.0 Table 13 - Ten-Year Externally Initiated Plant Relocation Estimated Capital Costs (Excluding Recoveries) 4.6 Stations System Enhancement 4.6.1 Bremner TS Project Description The purpose of this project is to develop a new substation, Bremner TS, to be located at Bremner Boulevard and Rees Street in downtown Toronto. This site is currently owned by Hydro One Networks Inc. ( HONI ). THESL will be the station developer. The project will include site preparation, construction of the substation building, installation of electrical equipment and site landscaping work. Electrically, the substation will consist of interface equipment with HONI incoming circuits, two 60/80/100 MVA 115 kv/13.8 kv-13.8 kv transformers, 13.8 kv switchgear, protection and control and other ancillary equipment. The project will provide about 72 MVA new firm capacity. The substation will also include space provisions for future transformers and 13.8 kv switchgear, to provide an additional 216 MVA firm capacity in three more future stages (3x72 MVA) as the need arises. 4.6.2 Justification The existing area is supplied by Windsor TS (referred to as John TS by HONI). Windsor TS was built in 1950, and expanded in 1968. Windsor TS has become the largest 13.8 kv substation in Toronto. The 13.8 kv air-blast switchgear, first installed in 1956, needs to be replaced in three stages. The substation is fully occupied with no room for further switchgear. In order to replace the end-of-life switchgear at Windsor TS, the existing customers from the affected equipment need to be supplied from a new source first. In Page 27

addition, a new source is also needed to reduce the overall loading level at Windsor TS as no spare feeder positions are available. The supply to the existing downtown customers also needs to be diversified to mitigate the effects of high-impact low-probability station events such as fire or flooding. The chosen site of Bremner TS is in relatively close electrical proximity to Windsor TS. The site also is in close proximity to existing THESL duct banks that will permit the linking of the two stations. The site is well-located with respect to the high voltage connection and provisions exist for the interconnection at 115 kv. Its location and the planned design satisfy the objectives of: providing a new source of supply to the area s customers permitting the removal from service and the replacement of end-of-life switchgear at Windsor TS providing capacity relief to Windsor TS and to neighbouring stations mitigating the effects of high-impact low probability stations events 4.6.3 Alternatives Considered 4.6.3.1 Do Nothing THESL will need to continue to have custom made parts replaced and expensive airsupply systems rebuilt. However, the reliability will decline eventually leading to failure. Switchgear failure at Windsor TS will have a high impact on customers in the area, which would include many of the downtown business towers and financial district. There is no alternate supply to customers should a switchgear fail, and restoration time would be measured in days, possibly weeks. This alternative has been ruled out. 4.6.3.2 Bus-to-bus Load Transfer within Windsor TS There is not enough firm capacity available on the bus structure within Windsor TS, to support load transfer to alternate positions because of the high load factor. This alternative is not feasible. 4.6.3.3 Load Transfer to Existing Adjacent Substations There are four existing substations adjacent to Windsor TS. None of these adjacent substations has enough firm capacity available, because of high loading. Of the four, two substations (Strachan TS and Esplanade TS) have the space for expansion to provide new capacity. Compared to Bremner TS, these two substations are further away from Windsor TS, and outside of the existing Windsor TS supply area. Installation work of underground cables to pickup Windsor feeders will be across existing supply areas, and disruption due to construction will be more extensive on city streets. This is not a preferred alternative. Page 28

4.6.4 Bremner TS HONI has acquired the site for Bremner TS, and it is designated for electric substation use. The site is within the existing supply area of Windsor TS. The new Bremner TS has been planned to relieve Windsor TS, and facilitate load transfers in the area to relieve the adjacent substations. There are existing cable ducts installed by THESL along Bremner Blvd. to facilitate feeder installation from Bremner TS. As part of coordinated long term planning, THESL has been developing this plan for several years. According to current forecasts, Windsor TS and its adjacent substations as a group will require new capacity by 2018. As Bremner TS is already within the supply area of Windsor TS, advancing Bremner TS can provide the capacity required to offload Windsor TS for switchgear replacement. This is the preferred alternative. 4.6.5 Benefits The project will provide capacity required to facilitate the staged replacement of old airblast switchgear at Windsor TS, reducing the risk of customer outage due to equipment failure at Windsor TS. It also reduces the overall loading level at Windsor TS, thereby diversifying customer supply, and mitigating the impact of high-impact low-probability station events. The project will also provide capacity relief to neighboring stations by enabling distribution load transfers to occur. 4.6.6 Impact of Deferral/Cancellation If other alternatives are selected and an adjacent substation is expanded to facilitate crosssupply area load transfers, then there will be more extensive installation work of underground cables on city streets, and abortive cross-supply area load transfers. If the project does not move ahead, and no other alternatives are selected, then the commissioning date of the proposed Bremner TS will be delayed, increasing the risk of customer outages because of equipment failure at Windsor TS. 4.6.7 Cost Table 14 below contains the estimated costs associated with the Stations System Enhancement portfolio. YEAR 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 TOTAL $ millions $48.1 $74.0 $29.0 $0.2 $0.2 $0.2 $0.2 $0.2 $0.2 $0.2 $152.4 Table 14 - Ten-Year Stations System Enhancement Estimated Capital Costs Page 29

4.7 Secondary Upgrades Distribution system plant installed in the field is constantly subjected to the elements of nature and the environment. Secondary distribution system assets endure wide temperature variations as well as water, salt and contamination ingress. These elements can lead to the corrosion and eventual degradation of these assets. Over time, this degradation can impact the integrity of electrical connections and allow for these connections to become loose or exposed. Therefore, secondary asset installations, repairs and/or upgrades must be implemented to ensure that their functional and operational performance is maintained at desired levels. Examples of such activities include secondary wiring connections in handwells and street lighting poles installed on city sidewalks. During the Level III contact voltage inspection work carried out in February 2009, handwell and street lighting pole locations across the city were inspected. Secondary wires were reconnected with standard waterproof connectors where needed in order to standardize the installation. However, there are a number of locations identified during the Level III inspection that require additional follow up work to bring them up to acceptable operating condition. Those locations include work that is required to re-install secondary wires between handwells, fuse installations in street lighting poles and the replacement of poles. It is essential that the required work be completed to maintain the physical and electrical integrity of the street lighting system within the THESL distribution plant. 4.7.1 Cost Table 15 below contains the estimated capital costs associated with the Secondary Upgrade program across a ten year time horizon. YEAR 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 TOTAL $ millions $10.0 $10.0 $10.0 $10.0 $5.0 $5.0 $5.0 $5.0 $5.0 $5.0 $70.0 Table 15 - Ten-Year Secondary Upgrades Estimated Capital Costs Page 30

5 Conclusion The ten-year plan will be reviewed and updated annually by the THESL Asset Management planning team. The underlying assumptions on which much of this plan is based are described in the relevant section of this document. It is understood and expected that some of these future expenditures required to address the needs of the system will be adjusted as more detailed plans are developed and as unforeseen requirements arise. As new information becomes available and as the analytical tools mature, capital plans will be adjusted to reflect the investments needed for THESL to continue to provide safe and reliable energy to Canada s largest city. Page 31

Appendix A Page 32