IPSP and Procurement Process Outline of Evidence for the Ontario - PDF document

Implementation Priority – Post-2015: Scenarios 6000 6000 5000 5000 - Case 1A/B: Reference cases 4000 4000 3000 3000 - Case 2A/B: High load growth 2000 2000 Effective MW 1000 1000 - Case 3A/B: High conservation 0 0 -1000 -1000 -Case 4A/B: No development of Northern renewables -2000 -2000 A: Pickering refurbishment -3000 -3000 B: Pickering not refurbished -4000 -4000 -5000 -5000 -6000 -6000 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 Existing Nuclear Committed Nuclear Planned Nuclear Existing Gas/Oil Committed Gas Planned Gas Existing Renewables Committed Renewables Planned Renewables Committed Conservation Planned Conservation Existing Coal Unspecified Required Resources 19

What are the benefits of an integrated plan? • Engages Ontarians; promotes shared understanding • Identifies electricity policy/regulatory issues at an early stage that should be considered in order to facilitate the Supply Mix Directive • Provides context for individual projects/programs/initiatives, and evaluations of options • Signals Ontario’s priorities/opportunities to developers/proponents • Provides OPA with implementation authority if the OEB approves the plan and the procurement processes 20

What are the limitations of an integrated plan? • Project-related issues not addressed - details around specific projects are not available at this planning stage • Scope/depth of analysis is limited for practical and timeline reasons • Complexity and continuous change in the real world are difficult to fully capture by analysis, forecasting, modelling, and discrete case studies • Current information and updates to cost outlook and cost assumptions (including nuclear, natural gas, construction) will be informed through experience 21

Models assist planning, but have limitations • Cost assumptions present typical and indicative costs. More certain cost estimates typically materialize as specific developments emerge. • Outlook for the economy, population, consumer choices, and technology development are all uncertain, and change from forecasts. • Simulations of how the integrated system is operated are complex, but necessary to test different solutions. This involves hourly load and generation patterns to simulate dispatch and operation of various resources. Real time operations take more considerations into account. • Assumptions about technical and environmental performance of various options are made to estimate the resulting reliability, emissions, land use, water use, etc. These are generic estimates, good as an indicator, but specific projects will invariably have some variation. 22

The IPSP Components – The Next Panels • The next panels will address the basic building blocks of the IPSP and Procurement Process • IPSP development steps – Setting resource requirements through demand forecast and reserve requirements – Applying feasible and cost effective conservation; – Applying feasible and cost effective renewable resources – Meeting remaining baseload requirements through nuclear power – Replacing coal by cleaner committed and planned new resources – Applying gas to specific projects when additional conservation and renewable resources are not feasible or cost effective – Plan transmission for reliability, incorporation of generation and system efficiency 23

Next Panels • Procurement process and procurement related issues • First Nations, Métis People Consultation • Stakeholder Consultation 24

Resource Needs: Demand Forecast and Reserve Requirements: Lily Buja-Bijunas, Planner Bob Gibbons, Director Resource Integration Evidence: Exhibit D-1-1 to D-3-1 Issues List: A 33 to A 34 25

Purpose of Presentation • Presentation will address resource requirements of plan • This consists of demand forecast plus reserve requirements • It also addresses how the resource requirements are unbundled into base, intermediate and peak load requirements • The evidence addresses the issues: – Do the forecasts relied upon by the OPA in the developing the IPSP, and the uncertainties attributed to them, present a reasonable range of future outcomes for planning purposes? D-1-1, D-1-1 Attachments 1-4 D-4-1 Attachment 6 – Does the IPSP meet its obligation to provide adequate electricity system reliability in all regions of Ontario? D-2-1, Ex. D-2-1 Attachments 1-3 D-3-1, Ex. D-3-1 Attachments 1-4 26

Demand Forecast • Forecasting electricity demand is inherently uncertain. • IPSP’s approach is not to plan to one forecast; rather uses reference case, high case and low case to illustrate potential demand requirements and how resources may be used to meet those requirements • Actual demand for 2006 and 2007 is significantly less than reference forecast. This is because of reduction in demand due to economic factors and the contribution of Conservation savings. • It is not possible to measure the contribution of each contributing factor with any level of certainty. • It is also not possible to conclude whether the current downturn is temporary, or long term, or what will be the effects of future energy use, including technological change and environmental policy. 27

Demand Forecast • Both inherent uncertainty of forecasting and changing economic, technological and policy context put premium on flexibility in both developing demand forecasts and in pursuing resource requirements. 28

Reference Forecast – Energy Demand (Weather Normal (D-1-1, Figure 1) IPSP Reference Forecast - Energy (weather normal) 250 200 Reference Forecast Energy Demand (TWh) Historical 1.1%/year (1995-2005) : 1.3%/year 150 100 50 0 1995 2000 2005 2010 2015 2020 2025 29

Reference Forecast – Peak Demand (Weather Normal) (MW) D-1-1, Figure 2 IPSP Reference Forecast - Peak (weather Normal) 40000 Coincident Peak Demand (MW) 35000 Reference Forecast 1.2%/year 30000 Historical Peak (1995-2005): 1.4%/year 25000 20000 Historical Summer Peak (1995-2005): 2.3%/year 15000 10000 5000 0 1995 2000 2005 2010 2015 2020 2025 30

Development of Forecast • Built on Study prepared for Council of Energy Ministers ( Demand Side Management Potential in Canada: Energy Efficiency Study May, 2006) (D-1-1, Attachment 3) • Compared to – historical performance (D-1-1 pp. 1-3) – per capita and per GDP indices (D-1-1 pp. 14-16) – forecasts by Hydro One, IESO and NRCan (D-1-1, pp. 16-19) 31

Development of Forecast • Produced using end use methodology – Canadian Integrated Modeling System (“CIMS”), developed and maintained by Energy and Materials Research group at Simon Fraser University (D-1-1; D-4-1, Attachment 6) • CIMS produces estimates of energy consumption at the consumer level. It simulates the equipment and building decisions of firms and households (D-1-1; D-4-1, Attachment 6; D-1-1, Attachment 2) • Having obtained the energy values, the OPA then used load shapes to convert annual energy values into hourly demand and peak demand. This conversion process can be found in Attachments 1 and 2 of Exhibit D-1-1 • The provincial forecast was used as a starting point for regional analysis. Energy and hourly load forecasts were produced for 10 electrical zones (D1-1, Attachment 1; D1-1, Attachment 2) 32

Plan Resource Requirements • In addition to the resources needed to meet peak and energy demands, the IPSP provides Planning Reserve to deal with risks • Planning Reserve has two components: NPCC Reserve and Insurance Reserve • NPCC Reserve is a mandatory requirement established by the Northeast Power Coordinating Council in order to meet required levels of generation adequacy (D-2-1, Attachment 1) • Insurance Reserve covers a number of specific risks that are not covered by NPCC Reserve • Insurance Reserve also covers a number of risks that are specific to the coal shutdown period out to 2014 (D-2-1, Attachment 2) 33

Reserve Requirements: NPCC and Insurance Requirements (D-2-1, Figure 1) SOURCES OF RELIABILITY RISK AND MITIGATION CONCEPTS Sources of Risk Sources of Risk POTENTIAL ADDITIONAL RESERVE • Nuclear Refurbishment / New Build Delays INSURANCE • Gas Additions Gas Additions Reliability Risk Nuclear Refurbishments • Transmission In service Date Delays • Nuclear Refurbishments RESERVE Bruce – Milton Line Mitigated by Gas and • Bruce Milton Line • Load Forecast Uncertainty Due to Economic Factors In - service Reliability • In - service Interconnections Risk Mitigated by Coal and INSURANCE • Conservation Additions • Conservation Additions Interconnections Conservation Additions RESERVE Conservation Additions • Renewables Additions • Renewables Additions Renewables Additions Renewables Additions Hydro Capability Reliability Risk • Hydro Capability • Hydro Capability Hydro Capability Nuclear Extended Outage Nuclear Extended Outage • Nuclear Extended Outage • Nuclear Extended Outage Mitigated by Gas and Nuclear Performance Nuclear Performance • Nuclear Performance • Nuclear Performance Interconnections • Load Forecast Uncertainty due to Weather Load Forecast Uncertainty due to Weather NPCC NPCC • Thermal Unit Forced Outages Thermal Unit Forced Outages Wind Availability RESERVE RESERVE • Wind Availability 2008 2014 2015 2027 . . Note: Risks in shaded areas are included in the Planning Reserve 34

Contributions of Existing Resources to Meet Resource Requirements (Effective MW) (D-3-1, Figure 1) 45,000 45,000 40,000 40,000 35,000 35,000 30,000 30,000 Effective MW 25,000 25,000 20,000 20,000 15,000 15,000 10,000 10,000 5,000 5,000 0 0 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 Existing Nuclear Existing Gas/Oil Existing Renewables Existing Coal Interconnection Required Resources Annual Peak 35

Unbundling Demand into baseload, intermediate and peaking requirements (D-3-1, Attachment 1, Figure 11) 100% Peaking Energy (1% ) Peaking Capacity 90% (22% ) 80% Intermediate 70% Capacity (18% ) I ntermediate Energy (11% ) ad 60% o tal L 50% o f T e o 40% tag Base Energy (88% ) ercen 30% Base Capacity P (60% ) 20% 10% 0% 0 801 1601 2401 3201 4001 4801 5601 6401 7201 8001 Hours 36

Chuck Farmer, Director Conservation Integration Conservation Resources: Karen Frecker, Planner Evidence: Exhibit D-4-1 Issues List: A1 to A5 37

Purpose of Presentation • Detail the process that the OPA used to determine the feasible and cost effective Conservation to be included in the IPSP. • Outline the approaches that the OPA is taking to meet or exceed Conservation targets. 38

Resource Requirements: Conservation Resources (D-4-1) • Directive Requirement: – Define programs and actions which aim to reduce projected peak demand by 1350 MW by 2010, and by an additional 3,600 MW by 2025 (total of 4,950 MW for planning period) • Discretion left open by Directive: – What mix of Conservation categories and program types are included in the plan to meet the 2010 (addressed through existing procurement Directives) and 2025 goals? – Should the 2010 and 2025 goals be exceeded? – What is the implementation schedule for Conservation initiatives? 39

Approach to Conservation Planning • Three Steps: 1. Identify potential for each defined conservation type (Energy Efficiency, Fuel Switching, Customer Based Generation, Demand Management/Conservation Behaviour). 2. Allocating capacity by reference to contribution to baseload, intermediate and peak requirements. 3. Develop Portfolio for implementation. 40

Step 1: Identifying Potential (D-4-1, pp. 8-16) • OPA used variety of approaches in estimating the conservation potential. These included: – Energy Efficiency: MKJA CIMS Model supplemented by market scans – Demand Management: OPA experience with demand response programs. – Conservation behaviour: OPA assumed that direct energy and demand savings resulting from this is relatively small but contribute to conservation culture and savings in other categories – Fuel switching: OPA relied on a detailed study by Marbek Resources – Customer Based Generation and Co-generation: OPA relied on CESOP, RESOP and CHP and Net Metering to estimate potential 41

Step 1: Identifying Potential (D-4-1, pp. 8-16) Conservation Relative Relative Categories Contribution to Contribution to Potential Peak Energy Savings Demand Reduction Energy Efficiency 63% 62% Fuel Switching 5% 24% Customer-Based 11% 14% Generation Demand 21% 1% Management 42

Step 2: Allocating Conservation to Resource Needs (D-4-1, pp. 19-21) • Baseload, intermediate and peak loads are served by different types of resources. • Two stages: – categorizing operating characteristics of conservation in terms of ability to meet load type; – allocating conservation target among load types. • Relating conservation to load types allows its integration with supply resources. 43

Step 2: Peak Demand Reduction (D-4-1, pp. 19-21) 2025 5000 2020 4210 2015 3050 2010 1410 Conservation in MW Total 44

Step 3: Program Development (D-4-1, pp. 21-23) • There are three main program types, each with their own characteristics: – Resource Acquisition (incentives and marketing – the most flexible and can produce short term results; also the most expensive) – Capability Building (development of skills and knowledge to deliver programs – necessary to build innovation and market driven services; takes a long time to develop and difficult to demonstrate clear causal relationship between program and results) – Market Transformation (achieving substantial and sustainable increase in market share of energy efficient technologies, buildings and production processes – achieved when effects continue without further intervention) 45

Approach to meeting the 2010 Directive PROGRAM TARGETS CONSERVATION CATEGORIES Free Net Demand Energy Demand Fuel Customer-based Target Program Rider Reduction Efficiency Management Switching Generation (MW) Rate (%) (MW) (MW) (MW) (MW) (MW) New Construction Program 45 30 32 32 Existing Buildings Retrofit 242 30 169 169 Low Income & Aboriginal 16 30 11 11 Demand Response 105 30 74 74 Total Mass Market Programs 408 30 286 212 74 New Construction Program 55 30 39 39 Existing Building Retrofit 492 30 344 274 70 Socially Assisted Housing 29 30 20 20 Total Commercial/Institution Market Programs 576 30 403 333 70 Industrial Markets Industrial Programs 113 30 79 79 Demand Response Programs 451 30 316 316 Total Industrial Market Programs 564 30 395 79 316 Customer-based Generation Customer-based Generation Programs 211 30 148 148 Total OPA Resource Acquisition Programs 1,759 30 1,231 625 390 70 148 Other Influenced CDM Smart Meters 176 0 176 Total Conservation & Demand Management [1] 1,940 1,410 620 390 70 150 46 Source: OPA (Exhibit D-4-1, Table 20)

Current Portfolio of Programs • Program portfolio mix for near term is being carried out under government directives. It consists largely of resource acquisition, with a relatively lower contribution from market transformation and capability building. (Conservation Delivery Cost estimate on a portfolio basis: D-4-1, Table 23). • Portfolio is comprehensive set of programs and initiatives designed to serve all customers and explore different delivery options • Conservation delivery cost estimates were developed on a portfolio basis (D-4-1, Table 23). • Conservation resources proposed for the long term are based on the four conservation categories (D-4-1 Table 22) and delivery costs were also developed on the same basis (D-4-1, Table 23). 47

Is it economically prudent and cost effective to seek to Exceed the Conservation Targets? • OPA is seeking to exceed the target prescribed in the directive provided that it is feasible and cost effective to do so. • The OPA does not believe that it is feasible to plan on exceeding the Conservation target at this time. It would be imprudent to not develop supply resources on the presumption that the Conservation target can be exceeded. Rather, both Conservation and supply opportunities should be developed. • IPSP has flexibility on supply options. If experience from the 2008-2010 Conservation programs demonstrates that there is feasible and cost effective Conservation to exceed the Directive goal, that Conservation will be compared to alternative supply resources before any commitment is made. • The IPSP therefore includes a high conservation scenario (G-1-1, pp. 12-22). 48

Gaining Experience through Conservation Programs • The OPA’s approach is to learn by doing through the delivery of actual programs • Evaluation, Measurement and Verification along with program experience and market research will provide the information necessary to commit to different targets in the future should it prove feasible and cost effective to do so (Evidence on EM&V, D-4-1, pp. 46-50). • This approach was adopted because the OPA agreed with the Stakeholders that it is preferable to refining models to determine feasibility. 49

Meeting Resource Requirements through Conservation (D-4-1, p. 5) 36,000 36,000 Energy Efficiency Demand Weather Normal Peak Demand (MW) Net of Conservation Demand M anagement/Conservation Behaviour 34,000 34,000 IESO Actual (Weather Corrected) Customer-based Generation Fuel Switching Peak Savings (MW) 32,000 32,000 30,000 30,000 28,000 28,000 26,000 26,000 24,000 24,000 2005 2010 2015 2020 2025 2005 2010 2015 2020 2025 50

Renew able Resources: Bob Gibbons, Director Resource Integration Andrew Pietrewicz, Planner Bob Chow, Director Transmission Integration Evidence: Exhibit D-5-1 Issues List: A 6 to A 9 51

Purpose of Presentation • Addresses methodology and analysis used to determine the contribution of Renewable Resources to meet requirements of Supply Mix Directive. • Discusses the integration of renewable resources with transmission enhancements 52

Resource Requirements: Renew able Resources (D-5-1) • Directive Requirement: – Assist the government in meeting its target for 2010 of increasing the installed capacity of new renewable energy sources by 2,700 MW from the 2003 base, and increase the total capacity of renewable energy sources used in Ontario to 15,700 MW by 2025. • Discretion left open by Directive: – What mix of renewable resources are included in the plan to meet the 2010 and 2025 goals? – Should the 2010 and 2025 goals be exceeded? – What is the implementation schedule for the renewable resources? 53

Approach to Identifying Renew able Portfolio • Four Steps: 1. Establish the potential for each renewable resource type (hydro, wind, biomass, solar) without consideration of transmission limitations or hydroelectric policy constraints. 2. Identify the transmission needed to achieve the wind and hydroelectric potential. 3. Establish the all inclusive costs for developing the potential renewable resources. All-inclusive costs include project development and construction costs as well as transmission connection, and network upgrade costs. 4. Determine the resources to be included in the IPSP based on feasible renewable resource potential and timelines as well as cost, with transmission constraints and hydroelectric policy constraints considered. 54

Step One: Renew able Resource Potential (D-5-1, p. 23) Table 12: Potential Renewable Resources – (Installed MW) Capacity ( MW) Hydroelectric Sites with no Policy Constraints 1,194 Sites with Policy Constraints 5,786 Wind Large Sites 9,267 Small Sites 2,787 Bioenergy 565 488 Solar TOTAL POTENTI AL 20,085 Source: OPA * Additional Solar resources having a capacity less the 500 kW are included in the Conservation Plan (Exhibit D-4-1). 55

Step 2: Identifying Transmission Requirements • Many wind and hydro sites are at remote locations and therefore require transmission lines to connect them to the main transmission network. • By “clustering” some sites, connection costs can be reduced by sharing a common transmission line. • The potential wind clusters are (D-5-1, p. 24): Cluster Cluster Cluster Sites Capacity Energy (MW) (GWh) East L Superior S9, S19, S2, S21, S24, S25, S4, S6, S 17, S 32 1,752 4,273 Manitoulin D25, S27, S20, D19, S13, S22, S35, S8 1,069 2,543 Lakehead S55, S32, S42 579 1,345 Bruce Peninsula S5, S46 380 951 Goderich D37, D38, S8, D32 429 1,074 Pembroke S18, S26, S29 207 503 North Bay D39, S34, S37 402 951 West of London S 57, S 52, D 26 337 786 Parry Sound S15, S28, S38, S41, S49 237 561 Thunder Bay S12, S10, S11, S14, S3 604 1,476 TOTAL 5,996 14,461 56

Step 3: Establishing All Inclusive Costs • Establishing the all inclusive costs for developing potential renewable resources is done in four stages: – establishing base levelized unit energy costs (LUECs) with no associated transmission (D-5-1, Att. 1) – adding connection costs, including shared lines within a cluster – adding regional and inter-regional transmission line and station upgrade costs, as applicable – adding cost impact of transmission losses 57

Step 3: Establishing All Inclusive Costs Table 17: Potential Renewable Resources – Range of Unit Energy Costs by Region All-I nclusive Unit Energy Costs (¢/ kWh 4 % DR) Minimum - Maximum Hydroelectric Eastern 3.97 - 8.55 Northeastern* 2.48 - 6.44 Northwestern* 2.48 - 8.30 Southern 3.11 - 7.02 Wind Eastern 8.27 - 9.59 Northeastern 8.74 - 11.01 Bruce 7.87 - 9.29 Northwestern 9.64 - 11.50 Southern 7.44 - 10.10 Bioenergy 8.10 - 11.90 Source: OPA. Note: “DR” is social discount rate expressed in real terms. * For the purpose of comparison with large wind sites, hydroelectric sites smaller than 10 MW in Northeastern and Northwestern Ontario have been excluded from this table. 58

Step 4: Determine Renew able Portfolio • RESOP : All renewable standard offer projects committed as of July 2008 are included. Small potential (less than 10 MW) will continue to be contracted through the standard offer program within existing distribution and transmission capacity limits. • Solar: 488 MW of RESOP projects (smaller facilities are included in Conservation category of customer supplied generation (D-4-1). • Bio-energy: Potential of 565 MW is all included. • Hydroelectric: All feasible hydro included (2,921 MW) on the basis that it is generally more economic than wind. • Wind: Large wind resources (larger than 10 MW) make up the remaining supply up to the renewable target in the Directive. Given the uncertainty of developing these resources, the IPSP has identified twice this amount. 59

Meeting the 2010 Renew able Resources Goal (Installed Capacity in MW) (B-1-1, Table 2) 60

Meeting the 2025 Renew able Resources Goal Existing, Committed and Planned Resources (Resources Used in Ontario - Installed MW) (B-1-1, Table 3) 61

Should Renew able Resource Targets be Exceeded? • Incremental renewable resource is large wind. If target exceeded, large wind facilities would displace alternative supply of combined cycle gas turbine. On basis of LUEC analysis, CCGT is more cost effective (D-5-1, p. 42): Table 24: Impact of Renewable Resources in Excess of the 2025 Target (Levelized Annual Costs) Additional Displaced Resource Resource (Wind) (CCGT) Capacity 207 41.4 (Installed MW) Fixed Costs 47 4 ($ millions)* Fuel Cost 0 30 ($ millions)* Total Cost 47 34 ($ millions)* Source: OPA Note: Levelized annual costs, based on a 4% real discount rate. CCGT capacity is based on the 20% effective capacity of wind. Fixed Costs include fixed operating costs and attributed transmission costs. Fuel Cost includes variable operating costs. 62

Renew ables Implementation: 2010-2015 Committed and Planned Stage 1 – 2010-2015 Developments: South Total: 3,180 MW of Renewable Generation Resource Capacity (MW) Hydro 120 Wind 1,700 Bioenergy 150 Solar 260 Total 2,230 Northeast Resource Capacity (MW) Hydro 560 Wind 0 Bioenergy 60 Solar 40 Total 660 560 MW 290 MW Northwest Resource Capacity (MW) Hydro 190 Wind 80 Bioenergy 20 Solar 0 Total 290 TOTAL 3,180 100 MW Required transmission additions: 2,230 MW • Completion of 500 kV line from the Bruce area to the Greater Toronto Area • New 230 kV enabler line to Goderich • New 230 kV enabler line along Bruce Peninsula • New 230 kV enabler line along Manitoulin Island • Series capacitors on North-South Tie & SVC at Porcupine TS and Kirkland Lake TS • Shunt capacitor banks at Essa TS, Hanmer TS and Porcupine TS 63 • New 230 kV line along East Lake Nipigon

Renew ables Implementation: 2016-2019 Planned Developments, in addition to Stage 1: Stage 2 – 2016-2019 South Total: 4,280 MW of Renewable Generation Incremental Cumulative Resource Capacity (MW) Capacity (MW) Hydro 0 120 Wind 360 2,060 Bioenergy 140 290 Solar 0 260 Total 500 2,730 Northeast Incremental Cumulative Capacity (MW) Capacity (MW) Resource Hydro 320 880 Wind 200 200 Bioenergy 30 90 Solar 0 40 Total 550 1,210 880 MW 340 MW Northwest Incremental Cumulative Resource Capacity (MW) Capacity (MW) Hydro 30 220 Wind 0 80 Bioenergy 20 40 Solar 0 0 Total 50 340 330 MW TOTAL 1,100 4,280 Required transmission additions: 2,730 MW • All Stage 1 upgrades, plus • Shunt capacitor banks at Mississagi TS and Algoma TS • SVC at Mississagi TS • New 500 kV line from Sudbury to GTA • New 500 kV line from Sudbury to Moose River Basin 64

Renew ables Implementation: 2020 and Beyond Planned Developments, in addition to Stage 2: Stage 3 – 2020 and beyond South Total: 6,300 MW of Renewable Generation Incremental Cumulative Resource Capacity (MW) Capacity (MW) Hydro 0 120 Wind 0 2,060 Bioenergy 0 290 Solar 0 260 Total 0 2,730 Northeast Incremental Cumulative Resource Capacity (MW) Capacity (MW) Hydro 1,610 2,490 Wind 300 500 Bioenergy 40 130 Solar 0 40 2,490 MW Total 1,950 3,160 410 MW Northwest Incremental Cumulative Resource Capacity (MW) Capacity (MW) Hydro 70 290 Wind 0 80 Bioenergy 0 40 Solar 0 0 Total 70 410 670 MW TOTAL 2,020 6,300 Required transmission additions: 2,730 MW • All Stage 2 upgrades, plus • New 500 kV line from Sudbury to Albany River • New 500 kV line from Sudbury to the Algoma District • New 230 kV line from east Lake Superior to Sault Ste Marie 65

Non-Renew able Resources: Bob Gibbons, Director Resource Integration Andrew Pietrewicz, Planner Evidence: Exhibit D-6-1 to D-91 Issues List: A 10 – A 23 66

Purpose of Presentation • The purpose of this presentation is to address how non-renewable resources contribute to meeting resource requirements after the contribution of feasible and cost effective Conservation and renewable resources. • The non-renewable resources are: – Nuclear for Baseload – Coal Replacement – Natural Gas Fired Resources 67

(Evidence D-6-1; Issues A 10 to A 14) Nuclear for Baseload 68

Nuclear for Baseload (D-6-1) • Directive Requirement: – plan for nuclear capacity to meet baseload requirements and limit the installed in-service capacity of nuclear power over the life of the plan to 14,000 MW. • Discretion Left Open by Directive: – What is the baseload requirement after the contribution of existing and committed projects and planned Conservation and renewable supply? – How does nuclear power compare to alternative ways to meet remaining baseload requirements? – What is the schedule for implementing baseload resources? 69

Determining Baseload Requirement • The IPSP identified baseload capacity requirements as equivalent to the load demand in any given year that exists at least 72% of the time – or 6,300 hours a year. (D-3-1) • It then determines how to meet the baseload requirement by applying the following steps: – Determining the contribution to meeting baseload requirements from existing and committed baseload resources. – Determining the contribution from planned conservation, renewable and combined heat and power. – Determining the remaining baseload requirements. – Addressing the scenarios with and without Pickering refurbishment (Cases 1A and 1B respectively) – Determining the feasible amount of, and contribution from, the preferred option. 70

Steps 1, 2: Determining contribution from existing and committed resources • Baseload requirements are currently met from a number of existing and committed resource types: – Conservation – Water – Wind – Coal – CHP; and – Nuclear • These resource types (with the exception of coal after 2014) are also planned to continue to meet baseload requirements. Specifically, the feasible and cost effective contribution of water, wind, CHP and conservation are all planned to be achieved. 71

Step 3: The baseload gap after the Contribution of existing, committed and planned resources: 35 TWh (D-6-1, p. 15) Figure 8: Existing and Committed Baseload Resources + Planned Conservation, Renewable and CHP Baseload Resources (TWh) 180 180 170 170 160 160 150 150 140 140 130 130 120 120 110 110 100 100 TWh 90 90 80 80 70 70 60 60 50 50 40 40 30 30 20 20 10 10 0 0 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 Existing Committed Planned Conservation , Renewables & CHP Baseload Source: OPA 72

Step 4: Determining the Preferred Option to meet the gap • The remaining options for baseload are CCGT and nuclear power. • The IPSP compares these two types of plants and, considering uncertainty in key factors, concludes that the higher variable costs of operating a CCGT plant make it more expensive than a nuclear plant to meet baseload requirements. (D-3-1, Att. 1). • There is considerable uncertainty with respect to capital costs generally, nuclear procurement costs, commodity costs, emissions compliance costs, load growth, and Conservation performance at this time. • The OPA is not seeking to procure any nuclear capacity in the near term (i.e., by 2010). It is expected that there will be better information on many of these matters before it is necessary to make a specific commitment to any additional supply resources to meet baseload requirements. 73

Step 5: Determining the Contribution from Nuclear • The baseload gap after the contribution of all other committed and planned resources is at least 35 TWh in 2027. • The IPSP initially included approximately 3,040 MW of nuclear capacity at Bruce A and approximately 10,300 MW of planned nuclear capacity. As a result of the government’s initiatives, the IPSP now assumes an additional committed nuclear capacity of approximately 3,260 MW at Bruce B and a range of 2,000 to 3,500 MW at Darlington. • As a result, the reference plan indicates a need for approximately 3,500 to 5,000 MW of baseload, nuclear capacity. 74

Planned Nuclear Implementation (Case 1A) (D-6-1, p. 22) Figure 10: Nuclear Capacity under Case 1A (MW) 16000 16000 14000 14000 12000 12000 10000 10000 MW 8000 8000 6000 6000 4000 4000 2000 2000 0 0 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 Case 1A Existing Case 1A Committed Case 1A Planned 75

Planned Nuclear Implementation (Case 1B) (D-6-1, p. 23) Figure 11: Nuclear Capacity under Case 1B (MW) 16000 16000 14000 14000 12000 12000 10000 10000 MW 8000 8000 6000 6000 4000 4000 2000 2000 0 0 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 Case 1B Existing Case 1B Committed Case 1B Planned 76

(Evidence: D-7-1; Issues List A 20 to 22) Coal Replacement 77

Coal Replacement (D-7-1) • Directive Requirement : – plan for coal-fired generation in Ontario to be replaced by cleaner sources in the earliest practical time frame that ensures adequate generating capacity and electricity system reliability in Ontario • Discretion Left Open by Directive: – How do existing, committed and planned conservation initiatives, renewable resources and nuclear power contribute to meeting the contribution that coal-fired generation currently provides to meeting Ontario’s electricity needs with respect to capacity, energy production, and reliability (flexibility, dispatchability, and the ability to respond to unforeseen supply availability)? – What are the remaining requirements in all of these areas? – How does the IPSP’s combination of gas and transmission resources meet these remaining requirements? 78

Approach to Replacing Coal • Five Steps: 1. Plan for maximum feasible and cost effective contribution from conservation and renewable resources 2. Identify the contribution of existing committed and planned nuclear and CHP resources 3. Identify contribution of existing and committed gas-fired generation. 4. Determine remaining requirement for supply to ensure adequate generating capacity and system reliability in the absence of coal-fired generation. 5. Plan for resources to meet remaining requirement (identified in step 4) in the earliest practical time frame. 79

Steps 1-4: Determining the gap left by removing coal after existing, committed and planned resources (D-7-1, p.5) Figure 1: Contribution from Existing, Committed and Planned Conservation, Renewable, Nuclear, Gas/Oil & Interconnection Resources in the Absence of Coal-fired Resources and Planned Gas-fired Resources (MW) 45,000 45,000 40,000 40,000 35,000 35,000 30,000 30,000 Effective MW 25,000 25,000 20,000 20,000 15,000 15,000 10,000 10,000 5,000 5,000 0 0 2007 2008 2009 2010 2011 2012 2013 2014 Existing Nuclear Committed Nuclear Existing Gas/Oil Committed Gas Existing Renewables Committed Renewables Planned Renewables Committed Conservation Planned Conservation Interconnection Annual Peak Required Resources Source: OPA 80

Step 5: Evaluating the Resources to fill the gap • In addition to providing capacity, coal fired generation provides operating flexibility. • Steps 1-4 have exhausted the feasible and cost effective contribution of every resource apart from natural gas (and associated transmission) to meeting the contribution provided by coal. • Issue is therefore the optimal combination of gas and transmission to make this contribution. A number of options were considered feasible (D-7-1, pp. 7-8): – Gas fired generation near existing gas supply but outside of area with local reliability needs (i.e., near Dawn hub) + Local Area Transmission – Gas fired generation where there are local reliability needs (Northern York Region, Kitchener Waterloo, Southwest GTA and GTA) – Conversion of existing coal fired generation to gas + Local Area Transmission – Continued operation of Lennox 81

Evaluation of Alternatives • Keeping Lennox in-service was determined to be cost effective and it was included in the Plan (D-8-1, Attachment 1) • Local area generation ( Northern York Region, Kitchener Waterloo, Southwest GTA and GTA) was the preferred remaining option: – meets the time frame for coal replacement (D-7-1, p. 9) – provides the lowest cost option as well as additional reliability, flexibility, environmental or societal acceptance benefits (D-7-1, p. 9, E-5-1, E-5-2, and E-5-3). 82

Replacing Coal • The total system capacity gap from 2012 to 2015 will be filled by planned gas-fired resources consisting of Lennox and new gas-fired generation located in local areas. However, there is an additional requirement to maintain about 300 MW of coal-fired generation in the Northwest during this period in order to maintain reliability of supply. • This still leaves a capacity gap to 2012 which requires Lennox and some coal-fired facilities to remain in service combined with reliance on interconnections. 83

(Evidence D-8-1; Issues A15 to A 19) Natural Gas-Fired Resources 84

Natural Gas Fired Resources (D-8-1) • Directive Requirement: – maintain the ability to use natural gas capacity at peak times and pursue applications that allow high efficiency and high value use of the fuel. • Discretion Left Open by Directive: – How can gas be used for peaking, high value and high efficiency purposes? – What is the IPSP’s plan for additional gas resources? 85

Peaking Requirements • The IPSP identifies peaking capacity requirements as equivalent to the load demand in any given year that exists up to 14% of the time – or 1,226 hours a year. (D-3-1, Attachment 1) • In comparing simple-cycle gas turbines (SCGT) to combined cycle gas turbines (CCGT), the IPSP compares these type of facilities and concludes that the higher variable costs of operating a SCGT plant make it relatively more expensive than a CCGT for peaking purposes and therefore concludes that SCGT should be used for peaking purposes. 86

High Efficiency and High Value use of Gas • High efficiency use of gas is for the supply of electricity from CCGT and combined heat and power (“CHP”). • CCGT and CHP are more cost effective than SCGT when used to meet intermediate load • The use of gas has high value where it is provides a material advantage over alternatives, in terms of lower cost, enhanced flexibility, shorter lead times, improved system operability or enhanced environmental performance (D-8-1, p. 3). • Because gas is a flexible resource, it functions as a swing supply in the IPSP (G-1-1). 87

Committed and Planned Gas Resources (D-8-1, p. 16) Table 9: Allocation of Committed and Planned Gas-Fired Resource Requirements Pickering B Refurbished Pickering B Not Refurbished Project/ Site Generation Type MW In-Service Generation Type MW I n-Service Lennox CST 2,100 2011 CST 2,100 2011 CHP (Committed) CHP 500 2013 CHP 500 2013 Northern York Region SCGT 350 2011 SCGT 350 2011 (Committed) Kitchener-Waterloo- SCGT 450 2012 SCGT 450 2012 Cambridge-Guelph Southwest GTA CCGT 850 2013 CCGT 850 2013 (Committed) GTA SCGT 550 2014 SCGT 550 2014 NUG Replacement SCGT/CCGT 469 2013 + SCGT/CCGT 1,368 2013 + Unspecified/ Proxy Gas SCGT/CCGT 650 2018+ SCGT/CCGT 825 2017 + Total 5,919 Total 6,993 Source: OPA. GTA could be met by either CCGT or SCGT, but was modeled as SCGT. 88

Transmission: Bob Chow, Director Transmission Integration Bing Young, Director Transmission Integration Evidence: Exhibit E-1-1 to E-7-1 Issues List: A 24 to A 26, A 32, A 34 89

Purpose of the Presentation • Identify the directive requirements for the transmission elements of the Plan • Provide an overview of how transmission has been planned to achieve the objectives of the Supply Mix Directive • Summarize the requirement for plan level environmental assessments for identified transmission projects 90

Transmission (Exhibit E) • Directive Requirement: – Plan to strengthen the transmission system to: • Enable the achievement of the supply mix goals set out in this directive • Facilitate the development and use of renewable energy resources such as wind power, hydroelectric power and biomass in parts of the province where the most significant development opportunities exist • Promote system efficiency and congestion reduction and facilitate the integration of new supply, all in a manner consistent with the need to cost effectively maintain system reliability 91

Enabling Supply Mix Goals: Supply Resources and Reliability Little Jackfish Sudbury North & East Nipigon Thunder Bay THUNDER BAY Area SUDBURY Sudbury East Lake West North / South Superior Manitoulin Northern Bruce Oshawa York Region Peninsula Southwest GTA TORONTO Milton Goderich Legend KWCG E nabling R enewable Development E nabling C oal Phase-Out E nabling Nuclear Incorporation WINDSOR R egional R eliability and S ervice Needs 92

Achieving Supply Mix Goals: Conservation (E-2-3) • No specific transmission projects have been proposed to facilitate conservation. • Assumptions of conservation in the regions and local areas have been incorporated in the development of the transmission plan (D-4-1, Table 12). 93

Achieving Supply Mix Goals: Renew able Resources • A number of transmission projects included in the IPSP are aimed at facilitating renewable development – North-South Transmission Reinforcement (E-3-1) – Sudbury West Transmission Reinforcement (E-3-2) – Sudbury North Transmission Reinforcement (E-3-3) – Incorporating East L. Superior Renewable Resource Development (E-3-4) – Incorporating Little Jackfish and East L.Nipigon Renewable Resource Developments (E-3-7) – Enabling Goderich Area Renewable Resource Development (E-3-8) – Enabling Bruce Peninsula Renewable Resource Development (E-3-9) – Enabling Manitoulin Island Renewable Resource Development (E-3-10) • The evidence in these areas also include IESO Reports and, where applicable, reviews of the environmental impacts of the proposals and reasonable alternatives to the proposals 94

Achieving Supply Mix Goals: Renew able Resources (cont’d) • The transmission evidence includes the LUEC analysis used to compare renewable resources (E-2-2, Att. 1) • A recommendation that the OEB reviews the funding of enabler lines and related issues to facilitate renewable resource developments (E-2-2, pp. 13-15, and E-2-2, Att. 2) • The proposed Bruce to Milton transmission expansion for delivering renewable (and nuclear) resources from the Bruce area is being addressed outside of the IPSP 95

Achieving Supply Mix Goals: Nuclear Pow er (E-2-4) • The sole transmission project recommended to facilitate nuclear generation is the construction of a new Oshawa transformer station (E-4-1). The timing of this project will be affected by the decisions to refurbish Pickering B. • Transmission to incorporate new nuclear at Darlington is not required until beyond 2020. 96

Achieving Supply Mix Goals: Natural Gas (E-2-5) • Natural gas resources relate to transmission largely with respect to where gas fired generation should be sited. • Local area generation is planned for areas where there are pressing reliability needs; installing generation at these sites will defer or avoid the need for transmission enhancements. • The specific sites are: – Northern York Region (has since been Directed) (E-5-1) – Kitchener-Waterloo-Cambridge-Guelph (E-5-2) – Southwest GTA (has since been Directed) (E-5-3) • The proposed sites were compared to alternative sites (e.g., Sarnia, Nanticoke). 97

Achieving Supply Mix Goals: Coal Replacement (E-2-6) • The only major transmission reinforcement in the Plan associated with coal replacement is related to the shut down of the Thunder Bay Generating Station. – possible construction of a new 22 km double-circuit 230 kV transmission line from Lakehead TS to Birch TS • Other transmission reinforcements (adding voltage support facilities in southwestern Ontario) for facilitating the shutdown of Nanticoke units are being implemented by Hydro One. 98

Projects to Ensure Reliability • In addition to the local area supply generation proposals - GTA, KWCG, SWGTA (under Directive), and NYR (under Directive) - the IPSP addresses reliability in three other areas: Windsor Essex, Central & Downtown Toronto and Milton • The Windsor Essex project (E-5-4) is proceeding outside of the IPSP. – Hydro One will be initiating the EA process and will be proceeding with a Section 92 leave-to-construct application 99

Projects to Ensure Reliability • Central and Downtown Toronto (E-5-5) • Development work recommended to address potential reliability needs in the 2015-2017 timeframe: – Supply Capacity – should load growth be higher and/or local conservation levels be lower than expected (pp. 11-14). – Infrastructure Renewal – in the next 5-10 years, Hydro One plans to carry out substantial refurbishment in the downtown system including key facilities at major transformer stations. Timely completion of this work may not be possible without an additional supply source to maintain uninterrupted supply (pp. 14-18). – Vulnerability to High Impact Events – such events can result in a significant loss of supply to downtown Toronto for prolonged periods (pp. 18-24). • Development work for distributed generation and transmission options are recommended 100