Hydrail Feasibility Study Report

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Regional Express Rail Program Hydrail Feasibility Study Report

CPG-PGM-RPT-245

Revision B February 2, 2018

Prepared for Metrolinx by:

CH2M HILL Canada Limited (now Jacobs Engineering Group Inc.)

Ernst & Young Orenda Corporate Finance Inc.

Canadian Nuclear Laboratories

Revision Purpose of Submittal Date Comments A Draft December 20, 2017 Submitted to Metrolinx for review B Final February 2, 2018 Updated with review comments

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Contents

Section Page References ...... 1 Acronyms and Abbreviations ...... 1 1 Executive Summary ...... 8 1.1 Hydrail System Structure ...... 9 1.2 Hydrail System Design and Operation ...... 10 1.3 Financial Modelling ...... 15 1.4 Challenges ...... 17 1.5 Opportunities ...... 19 1.6 Recommended Next Steps ...... 21 2 Introduction ...... 22 2.1 Purpose and Objective of the Study ...... 22 2.2 Metrolinx Hydrail Workstream Overview ...... 22 2.3 Report Overview ...... 25 2.4 Study Methodology...... 26 2.5 Permissions ...... 26 3 Hydrogen Overview ...... 27 3.1 Introduction to Hydrogen ...... 27 3.2 Hydrogen Technology ...... 30 3.2.1 Hydrogen Production Options ...... 30 3.2.2 Placing Hydrogen in Context ...... 32 3.2.3 The Hydrail System ...... 33 3.2.4 Hydrogen Fuel Production ...... 34 3.2.5 Fuel Storage – Gaseous and Liquid Hydrogen ...... 36 3.2.6 Fuel Distribution ...... 39 3.2.7 Refuelling and Dispensing ...... 40 3.2.8 Vehicle Propulsion: Hydrogen Fuel Cells ...... 42 3.2.9 Vehicle Power Management – Battery Technology ...... 49 3.2.10 Vehicle Hydrogen Management – Storage Tanks ...... 52 3.2.11 Potential Competing Technologies ...... 54 3.3 Where Hydrogen Can be Used ...... 56 3.3.1 Overview ...... 56 3.3.2 Case Studies ...... 62 4 Hydrail Assessment ...... 67 4.1 Hydrail System Design ...... 67 4.1.1 Key Components Overview ...... 68 4.1.2 Electricity Supply Subsystem ...... 69 4.1.3 Hydrogen Production Subsystem ...... 70 4.1.4 Hydrogen Storage Subsystem ...... 74 4.1.5 Hydrogen Distribution Subsystem ...... 78 4.1.6 Hydrogen Refuelling Subsystem ...... 82

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4.1.7 Hydrogen Dispensing Subsystem ...... 83 4.1.8 Hydrogen Vehicle Subsystem ...... 85 4.2 Hydrail System Operations and Maintenance ...... 95 4.2.1 Operating, Maintaining, and Renewing the Hydrail System ...... 95 4.2.2 Hydrail System Operation Modelling ...... 107 4.3 Electricity Policy and Pricing ...... 126 4.3.1 Governance, Regulatory, and Management Framework ...... 127 4.3.2 Ontario’s Electricity System ...... 128 4.3.3 Electricity Forecasts ...... 135 4.3.4 Electricity Pricing ...... 142 4.3.5 Implications for Hydrail ...... 144 4.3.6 Electricity Pricing Forecast for Hydrail ...... 147 4.3.7 Summary of Key Findings ...... 148 4.4 Costs and Benefits ...... 149 4.4.1 Review of RER Benefit to Cost Ratio Development ...... 150 4.4.2 Hydrail System Modelling ...... 156 4.4.3 Comparative Cost/Benefit Assessment of the Simulation Scenarios ...... 164 4.4.4 Sensitivity Analysis ...... 167 4.4.5 Model Benchmarking ...... 168 4.4.6 Results of the Hydrail Modelling Exercise ...... 170 4.4.7 Updates to the IBC ...... 172 4.4.8 Other Considerations ...... 173 4.4.9 Fiscal Analysis ...... 175 4.4.10 Findings ...... 177 4.4.11 Next Steps ...... 177 4.5 Environmental ...... 178 4.5.1 Evaluation Methodology ...... 178 4.5.2 Evaluation Results ...... 180 4.5.3 Environmental Conclusions ...... 182 4.6 Legal, Policy, and Regulatory Framework ...... 188 4.6.1 Laws and Regulations Governing Metrolinx ...... 188 4.6.2 Existing Laws, Regulations, Standards, and Codes – Hydrogen Facilities and Transportation ...... 189 4.6.3 Other Existing Laws, Regulations, Standards, and Codes Relevant to Hydrail .. 191 4.6.4 How Existing Regulations Might Need to Change for Hydrail ...... 192 4.6.5 Need for Additional Laws, Regulations, Standards, and Codes specifically for Hydrail ...... 193 4.6.6 Proposed Roadmap ...... 193 4.7 Socio-economic Impacts ...... 194 4.7.1 Quantitative Assessment ...... 194 4.7.2 Qualitative Assessment ...... 200 4.7.3 Conclusion ...... 203 4.8 Public Acceptance ...... 204 4.8.1 The California Hydrogen Highway ...... 204 4.8.2 The German Experience ...... 207 4.8.3 Differences between Ontario and the California and German Deployments ... 209 4.8.4 Recommendations for Ontario Deployment ...... 210

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4.9 Implementation Readiness ...... 213 4.9.1 Hydrogen Economy ...... 213 4.9.2 Overview of Hydrogen Related Businesses ...... 219 4.9.3 Hydrogen Fuel Cell Rail Vehicle Market Maturity and Trajectory ...... 221 4.10 Commercial ...... 222 4.10.1 Current RER Procurement Strategy and Impact of Hydrail ...... 222 4.10.2 Jurisdictional Scan ...... 225 4.10.3 Considerations for structuring commercial arrangements ...... 230 4.10.4 Grid Interface, Hydrogen Production, Storage, Distribution and Dispensing ... 231 4.10.5 Hydrail Rolling Stock, Operations and Maintenance of Rolling Stock and Related Maintenance Facilities ...... 234 4.10.6 Procurement Factors ...... 236 4.10.7 Timeline Considerations ...... 239 4.11 Transition Plan ...... 241 4.11.1 Strategy to Introduce Hydrail ...... 241 4.11.2 Timescales ...... 242 4.12 Risks and Opportunities ...... 244 4.12.1 System Design Risks ...... 244 4.12.2 System Implementation Risks ...... 251 4.12.3 System Operational Risks ...... 253 4.12.4 Opportunities ...... 257 5 RER Program Electrification ...... 260 5.1 Current RER Program ...... 260 5.1.1 Scope...... 260 5.1.2 Train Service Plan ...... 263 5.1.3 Procurement of Rolling Stock ...... 266 5.2 RER Electrification Infrastructure Extent and Possible Scope Changes due to Hydrail 268 6 Recommended Next Steps ...... 271 6.1 Actions to Further Develop Hydrail ...... 271 6.1.1 System Size ...... 271 6.1.2 Subsystem Concept Designs ...... 272 6.1.3 Hydrogen Production Location Identification ...... 273 6.1.4 Operational Functionality ...... 274 6.1.5 Cost Estimates ...... 274 6.1.6 Implementation Plan ...... 274 6.1.7 Safety Case Roadmap ...... 275 6.1.8 Prototype Hydrail System ...... 275 6.2 Actions to Align the Hydrail System with Provincial Government Policy ...... 276 6.2.1 Electricity Price Policy ...... 276 6.2.2 Hydrogen Economy ...... 276 6.3 Actions to Integrate the Hydrail System into the DBFOM Procurement Process ...... 277 7 References ...... 278

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Appendices

Appendix A – Symposium Feedback ...... 286 Appendix B – Hydrail Safety Review ...... 289 Appendix C – Ontario Rail Sector ...... 319 Appendix D – Summary of Inputs for Socio Economic Impacts with Key Assumptions ...... 325 Appendix E – List of Contacted Organizations ...... 343

Figures

Figure 1-1 Hydrail System Structure ...... 9 Figure 2-1 The Hydrail Workstream ...... 22 Figure 3-1 Schematic of Water Electrolysis Process ...... 28 Figure 3-2 Electricity and Hydrogen Transactions based on Two Processes ...... 29 Figure 3-3 Hydrogen Production Technologies ...... 30 Figure 3-4 Global Industrial Hydrogen Production Capacity, Production, and Consumption ...... 32 Figure 3-5 The Hydrail System ...... 33 Figure 3-6 Hydrogen Storage Technologies Relevant to Hydrail ...... 37 Figure 3-7 Schematic of Refuelling Storage and Dispensing Setup for Hydrogen Powered Cars ...... 41 Figure 3-8 Fuel Cell Powered Propulsion System in Vehicles ...... 43 Figure 3-9 Fuel Cell schematic Components ...... 44 Figure 3-10 Comparison of Fuel Cell Applications for Various Transportation Sector Vehicles ...... 46 Figure 3-11 Comparison of Six Types of Li-ion Batteries ...... 50 Figure 3-12 High-pressure Type IV Hydrogen Storage Tanks used in Cars ...... 52 Figure 3-13 Reasons for Unavailability of Fuel Cell-electric Buses ...... 53 Figure 3-14 Hydrogen Applications in Four Prevalent Market Areas ...... 56 Figure 3-15 Fuel Cell Adaptation in the United States for Backup Power and Forklift Applications ..... 58 Figure 3-16 PEM Fuel Cell Consumer Vehicles Sold in the Last 6 years ...... 60 Figure 4-1 Hydrail System Components ...... 68 Figure 4-2 Electrical Supply System ...... 69 Figure 4-3 Hydrogen Production subsystem ...... 71 Figure 4-4 PEM Water Electrolyzer Performance ...... 73 Figure 4-5 Hydrogen Storage subsystem ...... 75 Figure 4-6 Hydrogen Distribution subsystem ...... 79 Figure 4-7 Hydrogen Refuelling subsystem ...... 83 Figure 4-8 Hydrogen Dispensing System ...... 84 Figure 4-9 Hydrogen Vehicle System ...... 86 Figure 4-10 Relationship between peak power and acceleration ...... 87 Figure 4-11 Relationship between train weight and fuel requirement ...... 88 Figure 4-12 Space distribution above the powered rail vehicle floor and trucks ...... 89 Figure 4-13 Fuel Cell System Lifetime Changes ...... 96 Figure 4-14 Relationship between Fuel Cell Lifetime and Operational Time ...... 96 Figure 4-15 Relationship between Electrolyzer Lifetime and Current Density ...... 97 Figure 4-16 Monthly Average Electricity in MW from Wind and Solar Installations in Ontario for 2016 ...... 108

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Figure 4-17 Trend of Ontario Grid HOEP ...... 109 Figure 4-18 Average Contribution to Ontario Electricity Supply in 2016 by Source Type ...... 110 Figure 4-19 Fuel Cell System Cost Changes ...... 114 Figure 4-20 Vehicle Cost Breakdown of Locomotive Hydrogen Components ...... 116 Figure 4-21 Vehicle Cost Breakdown of HMU Hydrogen components ...... 116 Figure 4-22 Hydrail Operational Simulation Model Design ...... 117 Figure 4-23 Daily Hydrogen Production Reflecting the use of Cheaper Electricity Price Periods Starting in 2024 ...... 119 Figure 4-24 Electric Power Measures ...... 126 Figure 4-25 Watt-hour Measures ...... 126 Figure 4-26 Electricity Industry Structure in Ontario ...... 129 Figure 4-27 Ontario’s 2015 Energy Production ...... 129 Figure 4-28 Ontario’s 2016 Installed Capacity ...... 131 Figure 4-29 Geographical Zones in Ontario’s Power Transmission System ...... 133 Figure 4-30 Ontario Net Exports, 2007-2016 ...... 135 Figure 4-31 Ontario Net Energy Demand across Demand Outlooks ...... 137 Figure 4-32 Net Summer Peak minus Net Winter Peak ...... 138 Figure 4-33 Installed Capacity and Capacity Contributions ...... 138 Figure 4-34 Capacity Contribution vs. Demand ...... 140 Figure 4-35 Surplus Baseload Generation as a Percentage of Net Demand ...... 140 Figure 4-36 Zone Generation Capacity ...... 141 Figure 4-37 HOEP vs. GA ...... 142 Figure 4-38 Class A Electricity Price Forecast ...... 144 Figure 4-39 Hydrail Modelling Process ...... 150 Figure 4-40 Modular Construction of the IBC Model ...... 152 Figure 4-41 The Cost Estimating Process ...... 157 Figure 4-42 Changes in Cost Estimate Uncertainty Across the Project Development Lifecycle ...... 160 Figure 4-43 Cone of Uncertainty ...... 161 Figure 4-44 Sample Cumulative Distribution Curve for a Project Estimate...... 162 Figure 4-45 Potential Changes in the BCR of an Overhead Electric System Compared to Hydrail ..... 173 Figure 4-46 National Organisation Hydrogen and Fuel Cell Technology Overview ...... 208 Figure 4-47 Hydrogen Economy ...... 214 Figure 4-48 Hydrail System Model Components ...... 230 Figure 4-49 Transition Plan Schedule ...... 242 Figure 5-1 Scenario 5 Extent of Electrification ...... 262 Figure 5-2 Scenario 5 Preliminary Infrastructure Considerations for the Union Station Rail Corridor . 263 Figure 5-3 Scenario 5 Proposed Service Concept – Peak Periods ...... 265 Figure 5-4 Scenario 5 Proposed Service Concept – Off-Peak Periods ...... 266

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Tables

Table 3-1 Rating of Fuel Cell Technologies for Use in Ships and Marine Vessels ...... 45 Table 3-2 Hydrogen Transport Vehicles Inventory ...... 59 Table 4-1 Electricity Supply subsystem Design Parameters ...... 70 Table 4-2 Hydrogen Production subsystem Design Parameters ...... 71 Table 4-3 Proton-exchange Membrane and Alkaline Water Electrolyzer Comparison ...... 73 Table 4-4 Hydrogen Storage subsystem Design Parameters ...... 75 Table 4-5 Comparison of Steel and Carbon-fibre Gas Storage Tanks ...... 78 Table 4-6 Pipeline Distribution subsystem Design Parameters ...... 79 Table 4-7 Truck-based Distribution subsystem Design Parameters ...... 80 Table 4-8 Comparison of Pipeline and Truck Distribution ...... 81 Table 4-9 Hydrogen Dispensing System Design Parameters ...... 84 Table 4-10 Comparison of Regenerative Braking Energy in Electric Locomotives ...... 89 Table 4-11 Hydrail Vehicle System (EMU and Locomotive) Design Parameters ...... 91 Table 4-12 Train Service Plan Impact for Two Timeframes under RER Scenario 5 ...... 93 Table 4-13 Train Service Plan Impact for Two Timeframes under RER Scenario 4 ...... 94 Table 4-14 Lifetime of Hydrail System Components ...... 95 Table 4-15 Rolling Stock Equipment Considered for Each Corridor ...... 99 Table 4-16 Layover and Maintenance Facilities Installation ...... 106 Table 4-17 Hydrail Capital and Operating Cost Impact on Unit Cost of Hydrogen ...... 110 Table 4-18 Large Industrial Price Forecast Values from IESO Module 4 ...... 112 Table 4-19 Equipment Capital Cost Factors for 2024 and Future-cost Cases ...... 114 Table 4-20 Cost of Vehicle Types ...... 115 Table 4-21 Comparison of Infrastructure Configuration Options ...... 120 Table 4-22 Comparison of Time-bound Costs ...... 121 Table 4-23 Comparison of Parameters for Peak Power Change in Powered Vehicles ...... 122 Table 4-24 Comparison of Fleet Mix Scenarios, Locomotives, and EMUs ...... 123 Table 4-25 Comparison of RER Scenarios 4 and 5 ...... 124 Table 4-26 Resources in Relation to Demand Across the Geographical Zones in Ontario's Power Transmission System ...... 134 Table 4-27 Electricity Price Assumptions ...... 147 Table 4-28 Electricity Price Forecast for Hydrail based on Ontario’s 2017 LTEP ...... 147 Table 4-29 Key Assumptions Included in the IBC Model ...... 152 Table 4-30 Categorization of Costs in the IBC ...... 153 Table 4-31 Basic Characteristics of Cost Estimates ...... 156 Table 4-32 Description of Steps Involved in Developing a Point Cost Estimate ...... 158 Table 4-33 List of Sample WBS Elements ...... 163 Table 4-34 Key Cost Drivers for Hydrail ...... 165 Table 4-35 Cost Factors Applied in the IBC ...... 167 Table 4-36 Output of the Sensitivity Analysis ...... 168 Table 4-37 Input Parameters for a Central Hydrogen Production Facility ...... 168 Table 4-38 Results of the Central Hydrogen Production Facility Models ...... 169 Table 4-39 Costs and BCRs for Electrification Scenarios ...... 171 Table 4-40 Hydrail System – Depreciation Rate ...... 176 Table 4-41 Fiscal Impact – Hydrail Compared to Over-head Electrification ...... 176 Table 4-42 Hydrail Preliminary Environmental Review ...... 183

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Table 4-43 Limitations due to Data Inputs ...... 196 Table 4-44 Operating and Capital Costs and Relevant Assumptions ...... 197 Table 4-45 Operating and Capital Costs and Relevant Assumptions ...... 198 Table 4-46 GDP Impacts ...... 199 Table 4-47 Employment (FTE) ...... 199 Table 4-48 Hydrogen Highway Development Overview ...... 205 Table 4-49 List of Organizations in the Hydrogen Business ...... 219 Table 4-50 Business factors to be considered in deploying the Hydrail System for GO ...... 232 Table 4-51 Commercial factors to be considered in deploying the Hydrail System for GO ...... 235 Table 4-52 Broadening Output Specifications on Integrated DBFOM to Accommodate Hydrail ...... 238 Table 4-53 Running Pilot Projects for Hydrail ...... 239 Table 4-54 Hydrail System Design Risk Matrix ...... 251 Table 4-55 Hydrail System Implementation Risk Matrix ...... 253 Table 4-56 Hydrail System Operational Risk Matrix ...... 257 Table 5-1 Scenario 5 Summary of Services ...... 264 Table 5-2 Summary of Key Infrastructure Requirements for RER Electrification ...... 268 Table 7-1 References ...... 278

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References

See Section 7 at the end of text for a list of reference sources used in this report.

Acronyms and Abbreviations

TABLE 0-1 ACRONYMS AND ABBREVIATIONS Acronym Definition $/kWe dollar per kilowatt equivalent $/m2 dollar per square metre $M dollars (millions) % percent £ British pound °C degrees Celsius 24/7 24 hours per day, 7 days per week A/cm2 ampere per square centimetre AAR Association of American Railroads AB 8 Assembly Bill 8 AC alternating current ADA Americans with Disabilities Act AHJ authority having jurisdiction Air Products Air Products and Chemicals, Inc. AODA Accessibility for Ontarians with Disabilities Act APTA American Public Transportation Association ARRA American Recovery and Reinvestment Act Ballard Ballard Power Systems BC British Columbia BCR benefit to cost ratio BEV battery-electric vehicle Blueprint California Hydrogen Blueprint Plan BMVI Federal Ministry of Transport and Digital Infrastructure BOP balance of plant

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TABLE 0-1 ACRONYMS AND ABBREVIATIONS Acronym Definition CaH2Net California Hydrogen Highway Network CAPEX capital expense CEP Clean Energy Partnership

CGH2 compressed hydrogen gas

CH4 methane CHFCA Canadian Hydrogen and Fuel Cell Association CHIC Canadian Hydrogen Installation Code CHP combined heat and power CHVI Cultural Heritage Value or Interest CN Canadian National Railway CNL Canadian Nuclear Laboratories CO carbon monoxide

CO2 carbon dioxide CP Canadian Pacific Railway CRRC Sifang CRRC Qingdao Sifang Company, Ltd. CSA CSA Group CTC Canadian Tire Corporation DBB design, bid, build DBF design, build, finance DBFM design, build, finance, maintain DBFOM design, build, finance, operate, maintain DMU diesel multiple unit DOE U.S. Department of Energy EIA U.S. Energy Information Administration EMF electromotive force EMI electromagnetic interference EMU electrical multiple unit EO Executive Order ESA environmental site assessment EU European Union FCEV fuel-cell-electric vehicle

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TABLE 0-1 ACRONYMS AND ABBREVIATIONS Acronym Definition FCHJU Fuel Cell and Hydrogen Joint Undertaking FCV fuel cell vehicle FEMA U.S. Federal Emergency Management Agency FRA Federal Railroad Administration GA Global Adjustment GHG greenhouse gas GO GO Transit GTHA Greater Toronto and Hamilton Area GW gigawatt GWh gigawatt-hour H+ hydrogen ion

H2 hydrogen gas HFC hydrogen fuel cell HMU hydrogen multiple unit HOEP Hourly Ontario Energy Price hp horsepower HVAC heating, ventilation, and air conditioning hydro hydroelectric IBC Initial Business Case ICEV internal combustion engine vehicle ICI Industrial Conservation Initiative IEC International Electrotechnical Commission IESO Independent Electricity System Operator ISO International Organization for Standardization JV joint venture kg kilogram kg/h kilogram per hour kg/min kilogram per minute km kilometre km/d kilometre per day km2 square kilometre

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TABLE 0-1 ACRONYMS AND ABBREVIATIONS Acronym Definition kmol/d kilogram-mol per day kPa kiloPascal kph kilometre per hour kV kilovolt kW kilowatt kW/L kilowatt per litre KWG KWG Resources kWh kilowatt-hour kWh/kg kilowatt-hour per kilogram L litre L/min litre per minute LDC local distribution company

LH2 liquid hydrogen LHV lower heating value LIB lithium ion battery Li lithium

LiCoO2 lithium cobalt oxide

LiFePO4 lithium iron phosphate LOS level of service LRT light rapid transit LRV light rail vehicle LTEP Long-Term Energy Plan m metre m2 square metre m3 cubic metre MarEx The Maritime Executive MCA multicriteria analysis Mg megagram MHE material handling equipment Minister Minister of the Ministry of Energy Ministry Ministry of Energy

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TABLE 0-1 ACRONYMS AND ABBREVIATIONS Acronym Definition MJ megajoule MJ/kg megajoule per kilogram MOECC Ontario Ministry of the Environment and Climate Change Moose Moose Consortium Inc. MPa megaPascal MU multiple unit MW megawatt MWe megawatt-equivalent MWh megawatt-hour NASA National Aeronautics and Space Administration NEB National Energy Board Nel Nel ASA NFPA National Fire Protection Association NGO nongovernment organization Ni-Cd nickel-cadmium Nikola Nikola Motor Company NiMH nickel-metal-hydride NIP National Innovation Programme for Hydrogen and Fuel Cell Technology NIST National Institute of Standards and Technology No. number NOW National Organisation Hydrogen and Fuel Cell Technology

NOx nitrogen oxides NPV net present value NRC Natural Resources Canada NREL National Renewable Energy Laboratory NWT Northwest Territories O&M operations and maintenance OCS overhead contact system or overhead catenary system OD outside diameter OEB Ontario Energy Board OEM original equipment manufacturer

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TABLE 0-1 ACRONYMS AND ABBREVIATIONS Acronym Definition OH- hydroxyl ion OPEX operating expenses OPO Ontario Planning Outlook OSHA Canada Occupational Safety and Health Regulations PDC Perishable Distribution Centre (Walmart) PDF peak demand factor PEM proton-exchange membrane

PM2.5 particulate matter less than 2.5 μm in diameter PNNL Pacific Northwest National Laboratory ppm part per million PS paralleling station PTE Permit to Enter PtG power-to-gas PVC polyvinyl chloride Q1 first quarter Q4 fourth quarter R&D research and development RAMS reliability, availability, maintainability, and safety RER Regional Express Rail RFP Request for Proposal RFQ Request for Qualifications ROI return on investment ROW right-of-way RSA Railway Safety Act RTD research, technological development, and demonstration SAE SAE International SAR species at risk SBG surplus baseload generation SMR steam-methane reforming SUV sports utility vehicle SWS switching station

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TABLE 0-1 ACRONYMS AND ABBREVIATIONS Acronym Definition TEN-T CEF Trans-European Transport Network TOD transportation on demand Topic Team Marketing, Communications and Public Education Topic Team TPAP EPR GO Rail Network Electrification Transit Project Assessment Process Final Environmental Project Report tpd tonne per day TPS traction power substation TSSA Technical Standards and Safety Authority TTC Toronto Transit Commission TW terawatt TWh terawatt-hour TWh/y terawatt-hour per year U.S. United States UIC International Union of Railways UK United Kingdom UN United Nations UNEP United Nations Environment Programme UP Union Pearson UPS United Parcel Service Vale Vale Railway VIA VIA Rail VOC volatile organic compound W watt WRMF Willowbrook Rail Maintenance Facility

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1 Executive Summary

Metrolinx’s Regional Express Rail Program (RER) is the largest transit infrastructure program in Canadian history that transcends borders and fosters connections between communities across the Greater Golden Horseshoe. Electrifying Metrolinx-owned segments of the GO Transit (GO) network is an important part of delivering on a promise to bring faster and more frequent services across the region; Metrolinx is on track to electrify and expand the rail network, and deliver more two-way, all-day services by increasing the number of weekly trips from about 1,500 to nearly 6,000 by 2025. In June 2017, the Minister of Transportation of Ontario announced that Metrolinx would study the feasibility of using hydrogen fuel cells (HFCs) to electrify the GO network as an alternative to electrification using conventional overhead wires. Recent advances in the use of HFCs to power electric trains in other jurisdictions make it important for Ontario to consider this technology as it has the potential to deliver the planned RER service benefits with reduced cost and time risks. This report investigates the feasibility of operating the GO network using HFC-powered rail vehicles – also known as a Hydrail System – based on an expected service model for the GO network that will start in 2025. It considers both the train service pattern and rail vehicle fleet mix to analyze the technical and financial requirements for operating the Hydrail System. The study concludes that it should be technically feasible to build and operate a Hydrail System for the GO network, and the system’s overall lifetime costs are equivalent to the alternative of a conventional overhead electrification system. It is also acknowledged that such a system is complex, and at this scale, would be a world first. This means that significant challenges would need to be successfully managed to achieve the objective of starting electrified services on the GO network by 2025. Two of the most significant of these challenges are:  Fleet implementation – Designing and building a fleet of HFC rail vehicles for RER services would carry a risk of delay due to the design challenges of integrating the fuel cell system into the rail vehicle platform and the production challenges of building a full fleet of new vehicles.  Electricity price – Due to the large amount of electricity that will be needed for hydrogen production (1% of average daily generated supply in Ontario) by the Hydrail System, the economic viability of Hydrail will depend on how the electricity price variability risk is apportioned with the private sector. There may need to be a provincial government commitment on this within the RER procurement process. However, there are also many significant risks in taking forward the conventional overhead electrification system that could also impact the 2025 milestone. One key differentiatior between the two options is that the Hydrail System also creates the opportunity for broader benefits to Ontario in terms of economic development in the technology sector and as a catalyst for the adoption of hydrogen in other areas of society.

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1.1 Hydrail System Structure The structure of the Hydrail System is shown on Figure 1-1.

FIGURE 1-1 HYDRAIL SYSTEM STRUCTURE

The feasibility study is based on the train service pattern and rail vehicle fleet mix (locomotives and electric multiple units [EMUs]) that Metrolinx intends to operate on the electrified GO network from 2025 on the completion of the RER program of infrastructure enhancements. A simulation model of the operation of the Hydrail System, based on this pattern and fleet, was used to calculate the size of the fuel cell system on the rail vehicles, the size of the electrolyzers needed to produce the hydrogen, and the amount of electricity needed from the grid. These sizing calculations were then used to forecast the capital cost to implement the Hydrail System and its annual operation and maintenance (O&M) costs.

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1.2 Hydrail System Design and Operation

The key factor in determining the feasibility of the Hydrail System is whether it can provide the expected GO functional and operating performance that the RER program needs to deliver. The feasibility study concludes that there is a good level of confidence that this can be achieved based on the assessment of the following:  The functionality and size of the end-to-end Hydrail System  The amount of electricity the system will need to consume to produce the required volume of hydrogen, and the ability of the system to use electricity when the hourly electricity prices are at their lowest  The design of the fuel cell systems to be integrated into the rail vehicles to deliver the performance needed for RER services  The modularity of the components of the system, which creates a high level of performance redundancy  The operation of HFC-powered locomotives using an arrangement of 1 locomotive with 6 carriages, which can then be joined so that 2 locomotives pulls 12 carriages  The expected ability to refuel the HFC-powered locomotives and EMUs in time frames comparable to current diesel locomotive refuelling  The existing commercial availability and technological performance of all components that will be needed for the Hydrail System  The interest of the major global rail vehicle manufacturers in building HFC-powered rail vehicles and the pending introduction of these vehicles into revenue service on other networks  The lessons learned from the Hydrail Symposium held in Toronto which are consistent with, and supportive of, the findings and recommendations in the feasibility study In addition, there are specific benefits that Metrolinx would experience if the Hydrail System is implemented, instead of electrifying the GO network through the conventional overhead catenary system, including:  Capital cost saving – The avoidance of the capital costs of the infrastructure works in the rail corridor to install the overhead catenary system, lower the track in places, raise bridges, and divert utilities (even though the Hydrail System has its own infrastructure works, these are smaller in scale and will generally not interface with the live railway; this delivers a saving in the initial investment that will need to be made in RER)  Environment – There would be fewer lineside trees required to be removed for Hydrail However, the conventional overhead catenary system has benefits over the Hydrail System in the following areas:  There is no requirement for refuelling – this will have a comparative benefit in terms of operating flexibility and cost  Rail vehicle capital cost will be lower due to the HFC system equipment that will be integrated into the HFC-powered rail vehicles  The cost of equipment renewals will be lower, as the cycle of refurbishment is longer for conventional overhead catenary system equipment

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The study of the Hydrail System resulted in several key design and operational conclusions, as follows: 1. The Hydrail System needs to be designed and operated as a complete end to end system. At one end of the system are rail vehicles operating on the GO network. At the other end of the system, power is drawn from the grid needed to produce hydrogen. The hydrogen then moves through the system via storage tanks, distribution infrastructure, and dispensing facilities until it is stored in tanks on the rail vehicle. There are two main options for where the hydrogen could be produced. The first option would use a few large facilities located away from the rail network; in this case, the hydrogen would need to be transported to the refuelling locations by truck or pipeline. The alternative is to locate the hydrogen production facilities near the refuelling facilities. This is the most economically advantageous solution, and is the one that is recommended in the study. 2. One of the key advantages of the Hydrail System compared with conventional electrification is that it can choose when to draw electricity from the grid. This means that it can take advantage of the low prices of electricity that generally occur during the night in Ontario. By maintaining a surplus of hydrogen in storage over what is needed every day, and choosing only to produce hydrogen when the price of electricity is less than a certain value, it is possible to minimize the cost of Hydrail System operations. The overhead catenary system does not have this level of flexibility, as it needs to draw electricity from the grid when required to operate the train, regardless of the price. 3. The HFC-powered locomotive and the HFC-powered EMU will both use an HFC system. This consists of a combination of fuel cell, battery, ultracapacitor, and regenerative braking (as shown in Figure 1-1). The way this system will operate is that the battery and ultracapacitor are sized to provide the power needed for the train to accelerate to its cruising speed between stations. The fuel cell is then used to charge the batteries as the train is cruising. Then, as the train is braking for the next station, the regenerative braking system further charges the batteries and the ultracapacitor. The simulation modelling work that has been undertaken as part of the feasibility study demonstrates that HFC-powered locomotives and EMUs can be designed to deliver the required RER services. The benefit of the regenerative braking system is that it recovers energy from the traction motors that are part of the vehicle’s braking system, and this energy can then also be used to charge the batteries and utltracapacitors. Modern electric rail vehicles all have regenerative braking systems; however, these are not generally sized to maximize the amount of energy that could be recovered. With the Hydrail System, there will be an opportunity to consider how the onboard power management systems are designed so that they maximize the amount of energy recovered during braking. This could further reduce the size of the fuel cell needed and reduce the volume of hydrogen consumed each trip. The ability to integrate this equipment into a locomotive platform has been validated by three rail vehicle manufacturers as part of the initial work undertaken by the HFC Locomotive Project that is also part of the Metrolinx Hydrail Workstream (an overview of this project and the Hydrail Workstream is provided in the Introduction section of this report). 4. The components in the Hydrail System’s subsystems are of a modular design (that is, multiple, small tanks; fuel cells; and batteries). This means that failure, or reduced performance, of one component should not have a significant impact on subsystem operation.

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For example, on the rail vehicles, the fuel cells will be arranged in parallel stacks so that a failure, or reduced performance, of one unit will only result in the fuel cell system’s reduced output power. Even if the entire fuel cell subsystem does become unavailable, there should be sufficient power in the battery system to enable the rail vehicle to operate in a degraded mode so that it can reach a place of safety. The battery subsystem would also be designed so that a failure in one battery unit should only lead to a reduction in peak power available to accelerate the train. 5. While RER train services using conventional overhead electrification are intended to be operated using an electric locomotive pulling 12 unpowered carriages, the Hydrail feasibility study recommends that 2 smaller HFC locomotives are used instead of one. This is because the volume of hydrogen needed on a single locomotive would not be sufficient to meet the service range requirements that Metrolinx needs between refuelling cycles. The additional benefit of using 2 locomotives with 12 carriages is that Metrolinx will have the option of splitting the consist into 2 consists of 6 carriages and 1 locomotive for out-of-peak hours when fewer passengers are travelling. This will reduce the operating costs of the rail network. The concept of one locomotive with six carriages could also be used as an alternative to the current plan to use EMUs for RER peak and off-peak services, and should be considered further. The benefits of this would be:  The locomotives will be compliant with Federal Railroad Administration (FRA) standards (whereas, the EMUs are compliant with International Union of Railways [UIC] standards, which would be new to Canada).  Metrolinx will be able to continue to operate its existing fleet of bi-level carriages. 6. A key determinant of the operational efficiency of the GO network using the Hydrail System will be the length of time that it takes to refuel a rail vehicle with hydrogen. The refuelling duration needs to be minimized whether the refuelling takes place during nonoperational hours at the end of the day, or during a break between trips in the daily service timetable. Hydrogen refuelling facilities designed for use by cars and buses typically only need to transfer low volumes of hydrogen. A facility needed to transfer the volumes required for the Hydrail System has yet to be built. However, an integrated design between the storage on the rail vehicle and the refuelling facility will be based on using multiple tanks on the rail vehicle that can be filled simultaneously using a manifold system. The target refuelling time of about 30 minutes is expected to be feasible through engineering design. However, the need to refuel the HFC-powered rail vehicles is a disadvantage when compared to electric rail vehicles that use the conventional overhead catenary system. This means that these electric rail vehicles have benefits in terms of rail service operational planning because refuelling does not need to be factored into the daily railway operating plans. 7. The technology on which the Hydrail System is based might seem like it is cutting edge and innovative, with inherent risks relating to reliability, safety, and performance. However, all components of the Hydrail System are based on technology that is fully developed, commercially available, and already in use in industrial applications throughout the globe, many of them in extremely harsh environments. This means that we are confident we will achieve a high level of reliability from these components in a heavy railway environment. The challenge in developing the HFC-powered rail vehicles is not so much in the performance of the individual components of the system, but in the integration of these components into a hybrid

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fuel cell system and then into the rail vehicle platform. This challenge is not to be underestimated, as the space available on the rail vehicle is limited, and there are many design constraints that will need to be overcome, particularly weight distribution. However, large rail vehicle manufacturers are highly experienced in systems engineering, and have the tools and knowledge needed to successfully undertake this integration design. 8. Further, the major rail vehicle manufacturers are showing a high level of interest in HFC-powered trains. For example: a. Over the course of 2017, Alstom has been testing its Coradia iLint train, which is an HFC- powered EMU, in Germany. Alstom recently announced that it had received an order for 14 of these trains which are due to go into revenue service in 2021. It is interesting to note that the vendor who is supplying the fuel cells to Alstom for this train is Hydrogenics, based in Mississauga. b. CRRC, the main Chinese rail vehicle manufacturer, has recently announced that it has introduced into revenue service a HFC-powered light rail vehicle (LRV) in the city of Foshan and is planning to expand this concept to other cities that have LRV projects in development. It is also interesting to note that the vendor supplying the fuel cells to CRRC is Ballard Power Systems (Ballard), based in Vancouver. c. Siemens has also recently announced that it has entered into a partnership with Ballard for the development of an HFC-powered train. In addition, other rail vehicle manufacturers have expressed an interest to Metrolinx in participating in the HFC Locomotive Project, which would lead to the construction of a prototype HFC-powered locomotive. However, in assessing the cost of procuring a fleet of HFC-powered rail vehicles there will be a premium for these vehicles in comparison to those required for a conventional overhead catenary system. This will be due to: a. The manufacturer’s design costs for such vehicles being higher as there is a development element of the work that will need to be undertaken b. The cost of the hybrid HFC equipment that will need to be integrated into the vehicles will be more expensive than the electrical equipment that is integrated into a conventional electric rail vehicle 9. Installing the infrastructure required for the overhead catenary system requires a significant amount of construction work to take place in, or near to, the rail corridor. This work includes: a. Erection of overhead line gantries and catenary wires b. Construction of new substations c. Diversion of utilities d. Lowering of the track bed in some locations, and rebuilding some bridges (to obtain the required height clearance) e. Modifying other bridges to erect safety walls

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Implementing the Hydrail System would mean that this work and the associated capital costs would be avoided. The Hydrail System itself would require fixed infrastructure assets to be built in relation to: a. Hydrogen production facilities b. Transportation infrastructure c. Storage facilities d. Refuelling facilities On balance, it is expected that there will be a significant cost saving in the initial capital cost of the fixed infrastructure of the Hydrail System in comparison to that required for the conventional overhead catenary system. 10. The Hydrail System has environmental benefits over the overhead catenary system, particularly in reducing the total number of trees that need to be cleared along the rail corridors.

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1.3 Financial Modelling

An assessment has been made of the Net Present Value (NPV) cost of implementing and operating the Hydrail System. Using a sensitivity analysis approach, a low-cost scenario was created that has a benefit to cost ratio (BCR) of 3.01, and a high-cost scenario was created that has a BCR of 2.65. This compares to a BCR of 3.07 for the existing RER business case based on conventional electrification. These results should be qualified because they could be affected by risks and opportunities that need to be further investigated, including the following:  Cost saving of avoiding the construction of the overhead catenary system  Forecast difference between the prices of night-time (off-peak price) electricity and day-time (peak price) electricity  Forecast price of fuel cells  Overhaul cycle duration of fuel cells  Potential ability to share infrastructure costs with other users  Potential ability to commence RER services earlier than planned Based on the level of design and cost analysis that it has been possible to undertake during the feasibility study, the Hydrail System and the conventional overhead catenary system have equivalent BCRs.

As mentioned in the previous section, the Hydrail System modelling has forecast both the system’s capital and operating costs. These costs were then incorporated into a modified version of the RER business case model to determine the system’s likely BCR. This has enabled the Hydrail System to be compared to the conventionally electrified network from a financial perspective. At this point in the assessment of the costs of the Hydrail System there are many assumptions that have been made about the performance of the system and the likely costs of the system’s components. To account for this uncertainty a sensitivity analysis has been run on many of the model’s input variables. This has created a low-cost scenario, where optimistic values were set for the variables, and a high-cost scenario, where pessimistic values were set for the variables. The outputs of this modelling work show that:  The low-cost scenario has a BCR of 3.01  The high-cost scenario has a BCR of 2.65 This compares to a BCR of 3.07 for the existing RER business case based on conventional electrification. These results need to be qualified as follows:  The implementation and operation costs for RER with conventional electrification are currently being reviewed based on a more up-to-date definition of the project’s scope and prices. This will enable the BCR to be updated and a forecast range between high and low probabilities to be determined.

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 The actual costs for Hydrail could be influenced by the factors identified in the following “Challenges” and “Opportunities” sections. There are four significant areas: 1. The price of electricity – the forecast prices of electricity between 2024 and 2035 have been provided to us by the Independent Electricity System Operator (IESO) and are based on the 2017 Long Term Energy Plan for Ontario. Over the long-term the electricity prices for the Hydrail System will depend on the extent to which: . The current surplus of generating capacity changes . Other users of off-peak electricity enter the market These factors could influence the price of off-peak electricity in a positive or negative direction from the current forecast which in turn would affect the comparative difference in the operating costs of the Hydrail System and conventional electrification. In the context of an RER procurement process with the Hydrail System as an option, it is recommended that certainty is provided to bidders around the long-term pricing of off-peak electricity. This will require consideration by the provincial government. 2. The price of fuel cells – the price range of fuel cells that has been included in the financial modelling is a result of advice from industry sources. These views are based on current volumes of production which are relatively low compared to the production volumes of other technology items. Over the medium-term the price of fuel cells could reduce further if hydrogen becomes a major factor in global strategies for decarbonization. 3. The duration between overhauls for the fuel cells – based on industry sources we have forecast that this duration would be about 9 years for the operation of fuel cells in the Hydrail System. However, there is a significant amount of research being undertaken on fuel cell technology and the possibility of a further improvement in this area should not be discounted. This would also reduce the Hydrail System’s operating costs. 4. Sharing of infrastructure implementation and operating costs – as described in the “Opportunities” section it would be feasible to share the costs of setting-up and operating the hydrogen production facilities with other government and private sector users if the appropriate incentives are put in place. This could lead to an improvement in the BCR for the Hydrail System.  The NPV of the benefits resulting from operating the Hydrail System could be improved over the current RER business case. This could be due to:  The earlier transition to RER services that could be achieved with the Hydrail System  The broader socio-economic benefits that implementing the Hydrail System might generate  The associated commercial opportunities that the Hydrail System might enable. Based on these qualifications, the conclusion of the financial modelling is that, at this stage, there is good equivalence between the Hydrail System and conventional electrification and that further analysis needs to be undertaken on both.

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1.4 Challenges

Hydrail is a complex system and there are likely to be many significant implementation challenges. The feasibility study report has assessed the key risks that could affect the program’s design and implementation as well as the operation of the Hydrail System. The most significant risks are:  Delays in the timescales for the development, build, and introduction into service of HFC- powered rail vehicles  Unexpected operational reliability issues with the HFC-powered rail vehicles after they enter revenue service  Concerns from the public and Metrolinx passengers to the concept of HFC-powered rail vehicles  Delays in achieving approval from the safety regulators to the commencement of revenue services with HFC-powered rail vehicles If any of these risks occurs there could be a delay in the start of RER services. It is therefore recommended that these and the other risks identified need to be further investigated and mitigation plans for them implemented as part of the next stage of the Hydrail Program.

Implementing a Hydrail System on the GO network will require major challenges to be overcome. These include:  The potential for the longer-than-planned development timescales for HFC-powered rail vehicles so that Metrolinx is unable to meet the target of 2025 for the commencement of RER services. Metrolinx has already started mitigate this risk through the process of developing both an HFC-powered locomotive and EMU. By commissioning rail vehicle manufacturers to prepare conceptual designs for both types of vehicles Metrolinx will be able to validate the principles of how an HFC-powered rail vehicle will perform. Beyond this concept design work, the risks of time over-runs during design, build, and testing of rail vehicles would be managed by an appointed rail vehicle manufacturer. Based on the experience of Alstom, which took 3 years to develop and bring into testing their Coradia iLint HFC-powered EMU, it seems feasible to expect a rail vehicle manufacture to complete the development and build of HFC-powered trains in the time available to commence RER services in 2025. Furthermore, Metrolinx would expect to procure an HFC-powered rail vehicle fleet on the basis that the supplier will be responsible for any risks to achieving the specified RER reliability and availability targets.  HFC locomotives and EMUs of the type needed for RER do not yet exist; therefore, real-world experience relating to reliability is limited to the operation of light rail vehicles and buses. This means that even though the vehicles will go through an extensive development and testing process, there is still a risk that when they enter revenue service, they will experience unexpected issues with reliability that cause in-service failures and consequential impacts to customers.

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This risk also applies to the hydrogen production, storage, refuelling, and dispensing facilities; and it is probable that the greatest risk relates to the integration of these systems. However, this risk can be mitigated by implementing and operating a small-scale prototype of the end-to-end system so that lessons can be learned about the system’s operation, performance, and reliability; and so these lessons can be fed back into the design, build, and operation of the full system.  Difficulties in gaining the public’s and Metrolinx passengers’ acceptance of the concept of the Hydrail System. There are many myths and misunderstandings about the safety of hydrogen, which, if not addressed, could lead to resistance to the implementation of a Hydrail System. These would need to be addressed through a comprehensive public communication strategy that provides a considered perspective on safety and the resulting environmental benefits of using hydrogen. The experience of the German government’s public communications strategy in relation to hydrogen indicates that if a similar approach is adopted by Metrolinx, the likelihood that this could become a major challenge would be reduced.  Achieving the approval of relevant safety regulators, including Transport Canada and TSSA, would be a key objective of developing the Hydrail System and bringing it into service. This challenge should not pose a significant risk as codes and standards already exist for all the components that will be used in the Hydrail System. An important consideration for Hydrail is in the regulations that would govern the overall safety management of the Hydrail vehicles in scenarios where there has been an accident or a component failure.It is expected that the safety risk in this situation would be acceptable because of several factors:  Safety in design would be a key objective during the Hydrail System design phase  Metrolinx will assemble a team of world leading experts in all aspects of hydrogen and railway safety to provide it, and the rail vehicle manufacturer, with necessary advice on design safety and regulation development.  Metrolinx will work closely with Transport Canada and TSSA through the design, build, and testing process to understand what rules and regulations need to be developed specifically to cover the Hydrail System.

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1.5 Opportunities

The technical and operational evaluation of the Hydrail System has focussed on understanding how it could be implemented and operated as a standalone system. However, the Hydrail System can also be considered as part of the broader RER Program; as part of the overall public transportation network; and as part of the Ontario economy. As such, there are opportunities that could be developed during the implementation of the Hydrail System that might deliver further benefits to both Metrolinx and the Province, including being able to:  Commence some RER services earlier than the 2025 target date for RER  Operate RER services over the entire GO network; thereby, increasing the benefits of RER Potential opportunities to the province are:  Being able to share the Hydrail System infrastructure capital with other users of hydrogen in the Greater Toronto and Hamilton Area (GTHA)  Being a catalyst for the expansion of businesses with a hydrogen technology focus and the associated highly-skilled jobs Taking forward the development of those opportunities beyond Metrolinx’s transportation mandate will require consideration and guidance from the provincial government.

Taking the Hydrail System forward as the means of electrifying the GO network provides several opportunities to create benefits that would not be available through an overhead catenary system network, including:  The ability to incrementally introduce the HFC-powered rail vehicles into revenue service. This contrasts with the conventional overhead electrification program which can only commence electrified rail services on a rail corridor once all the infrastructure is in place. Aligning the implementation of the RER track and signalling improvements with the development of the HFC-powered rail vehicles creates the opportunity for an initial fleet of these vehicles to be introduced into service on one corridor earlier than the planned start of RER services in 2025. This would enable Metrolinx to build up a level of experience in the operation and performance of the vehicles that could be fed into the development and build of the remaining vehicles in the fleet on the other corridors.  By adopting the Hydrail System it will be possible to eventually operate electrified RER services over the full GO network rather than the scope of corridors that is currently planned for RER. This means that, over time, all the remaining diesel locomotives could be removed from the network with the additional environmental benefits in terms of greenhouse gas (GHG) emission, pollution, and noise reductions.  Implementing the Hydrail System could act as a catalyst for a broader adoption of hydrogen throughout Ontario as part of a potential roadmap for a hydrogen economy in Ontario1. There are

1 Recent published examples of these strategic roadmaps are: Hydrogen Council. 2017b. Hydrogen scaling up. A sustainable pathway for the global energy transition. November. Accessed December 2017.http://hydrogencouncil.com/wp-content/uploads/2017/11/Hydrogen-

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opportunities to align the Hydrail System’s hydrogen production, storage, and distribution infrastructure with the similar infrastructure needed to support HFC-powered buses and cars. The investment in an integrated infrastructure for these complementary requirements would be far more cost effective than if the systems were developed individually.  There are possible broader socio-economic benefits that could be experienced by Ontario as a result of implementing the Hydrail System. These include:  Development of opportunities for businesses in the hydrogen and the fuel cell sector. Ontario already has some businesses that are focussed on producing components of the Hydrail System. These businesses are likely to benefit from implementing a system on the scale of Hydrail  This in turn is likely to lead to an expansion in the number of high skilled jobs that would be required in these businesses and in the operation and maintenance of the Hydrail System Taking forward the development of those opportunities which are beyond Metrolinx’s transportation mandate will require consideration and guidance from the Provincial government.

scaling-up-Hydrogen-Council.pdf; and Government of South Australia. 2017. A Hydrogen Roadmap for South Australia. September. Accessed December 2017. https://service.sa.gov.au/cdn/ourenergyplan/assets/hydrogen-roadmap-8-sept-2017.pdf.

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1.6 Recommended Next Steps While the study concludes that it is technically and economically feasible to build and operate the GO network using HFC-powered rail vehicles, it has also identified aspects of the Hydrail System that warrant further investigation to support the RER procurement process. The proposed next steps are focussed on alignment with the RER procurement strategy which will be open to both the Hydrail System and conventional electrification options. The primary objective of this alignment is to enable the design of the whole Hydrail System to be taken forward to a conceptual design level so that by the time the RER bidders start to prepare their bids they will have access to high quality information about the design and operation of the Hydrail System. This will enable the bidders to accurately assess the risks and benefits of Hydrail System in comparison to electrification using the conventional overhead catenary system. It is proposed that further work is undertaken in those areas of the Hydrail System where the bidders are likely to want a greater level of certainty than currently exists, at the completion of the feasibility study. These are:  Design:  Complete the projects to create conceptual designs for an HFC bi-level EMU and an HFC locomotive  Refine the Hydrail System configuration and size in the Operational Simulation model, including development of concept designs for hydrogen production, storage and fuelling subsystems  Prototyping: Commission the production of a prototype HFC locomotive that can enter revenue service, including the development and prototyping of the refuelling and hydrogen production subsystems that can work with the prototype HFC locomotive so that Metrolinx can learn valuable lessons concerning the Hydrail System’s operations, performance, and reliability  Railway operations: Further investigate the operational areas of the Hydrail System such as maintenance and refuelling  Cost: Recognizing that the Hydrail System would represent a new approach to delivering RER, collaborate with industry vendors to further investigate infrastructure and vehicle delivery and operational costs  Implementation: Further define the development and build phases and the transition plan required to initiate a Hydrail System on the GO network  Hydrogen production: Identify location options for the hydrogen production facilities  Regulations: Work with the safety regulators at the federal and provincial levels to reach clarity on the regulatory environment that will apply to Hydrail  Electricity price policy: Work with the provincial government to develop an electricity price policy that could be applied to the Hydrail System  Hydrogen economy: Work with the provincial government to develop a cross-government business case for hydrogen (including the Hydrail System)  Align with the RER procurement process: Integrate the outputs from these steps into a Hydrail System Reference Concept Design that can be used in the RER procurement process

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2 Introduction

2.1 Purpose and Objective of the Study The Hydrail Feasibility Study Project was initiated because Metrolinx is committed to electrifying the GO network and using hydrogen fuel cell technology to power rail vehicles is now being considered as a viable alternative to rail vehicles powered by an overhead catenary wire system. Therefore, the objective of the study has been to determine whether it is technologically feasible and economically beneficial to use hydrogen fuel cell powered rail vehicles on the GO network, as an alternative to conventional electrification. 2.2 Metrolinx Hydrail Workstream Overview The feasibility study was undertaken as one project within a program of projects called the Metrolinx Hydrail Workstream. The other projects in this workstream are shown on Figure 2-1.

FIGURE 2-1 THE HYDRAIL WORKSTREAM

HFC Bi-Level EMU Concept Design Project As part of the proposed Regional Express Rail (RER) train services it is intended to operate bi-level Electric Multiple Unit (EMU) rail vehicles in consists of four cars and eight cars. In the Hydrail System these would be replaced by Hydrogen Fuel Cell (HFC)-powered bi-level EMUs. The objective of this project is to commission rail vehicle manufacturers, who already have bi-level EMU models, to produce conceptual designs for a HFC-powered bi-level EMU that can meet the requirements of the RER service patterns.

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The conceptual designs will prove the feasibility of integrating an HFC system into an EMU and will provide valuable information about the likely cost and timescales to develop, manufacture and bring this type of EMU into revenue service. HFC Locomotive Project As part of the proposed RER train services, it is intended to operate electric locomotives pulling the existing fleet of unpowered coaches in 12-car consists. In the Hydrail System, these would be replaced with two smaller HFC-powered locomotives. The objective of this project is to commission rail vehicle manufacturers, who already have electric locomotive models, to produce conceptual designs for an HFC-powered locomotive that can meet the requirements of the RER service patterns – in this case it will be a locomotive in a six-car consist. Metrolinx has already completed an initial phase of work that has verified the feasibility of integrating a HFC system into a locomotive platform. It now intends to engage rail vehicle manufacturers to take these ideas forward to the concept design level. The conceptual designs will further demonstrate how an HFC system can be integrated into a locomotive platform, and will provide valuable information about the likely cost and timescales to develop, manufacture, and bring this type of locomotive into revenue service. At the completion of the conceptual design phase, it is Metrolinx’s intention to commission the detailed design and construction of a prototype HFC-powered locomotive that can be used on the GO network. This will provide multiple benefits including gaining experience operating an HFC rail vehicle, and with the refuelling process, its maintenance requirements, it performance, and its reliability. Hydrail Symposium Project As part of the scope of the Hydrail Workstream, a 1-day symposium titled “Hydrail in Ontario: Examining Opportunities for Wireless Electrification” was held in Toronto on November 16, 2017. The objectives of the symposium were to:  Educate and inform an audience of interested Metrolinx and government stakeholders about the opportunities and implications of using a Hydrail System  Learn about global and Canadian developments in the use of hydrogen technologies  Obtain the views of the participants on what the key challenges would likely be if Metrolinx implemented the Hydrail System and identify how these challenges could be overcome The symposium was attended by more than 200 participants and key speakers included:  Steven Del Duca – Minister of Transportation  Phil Verster – Metrolinx Chief Executive Officer (CEO)  Dr. Sunita Satyapal – Director, Fuel Cell Technologies Office, U.S. Department of Energy (DOE)  Dr. David Hart – E4Tech Sustainable Energy Consultancy  Paula Vieira – Director, Transportation and Alternative Fuels Division, Natural Resources Canada

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Sessions within the symposium included:  A panel on public sector perspectives  A panel on private sector perspectives  Presentations form Alstom and CRRC on their HFC-powered rail vehicles  A panel on the key criteria that need to be focussed on to make Hydrail a success This last panel was followed by a session in which participants were asked to provide their views on the topics of:  Safety  Energy  Environment  Workforce and economic development  Implementation The collated outputs of this session are included in Appendix A and align with the findings and recommendations in this report Some of the themes from the conference that are relevant to the potential implementation of Hydrail are:  The importance of communication with the Ontario public about the use of hydrogen and:  How they can be assured of its safety  Its environmental benefits  The significance of the interdependencies between a Hydrail System and the Ontario energy market  How the implementation of a Hydrail System could generate economic development opportunities for technology businesses in Ontario and the need to develop skilled trades to support this  Hydrogen-related businesses are confident that they could respond to meet the demands of implementing a Hydrail System in Ontario if given the opportunity  Other example projects are still in their testing phases and are not yet fully in service  Governments globally, and at the Canadian federal level, are developing policy frameworks to develop and encourage adoption of hydrogen applications.

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2.3 Report Overview In this report, we present a comprehensive assessment of hydrogen technologies and their potential application in a Hydrail System on the GO network. The report is structured into six parts as follows: 1. Part 1 is an Executive Summary that provides an overview of the key findings and recommendations of the report. 2. Part 2 is this Introduction that provides an overview of each section and a description of the methodology followed by the feasibility study team. 3. Part 3 is titled Hydrogen Overview and contains two sections:  Section 1 is an introduction to the subsystems and components that make up the Hydrail System.  Section 2 is a description of the types of applications where these hydrogen systems are generally used and case studies that support this. 4. Part 4 is the core of the report and contains 12 sections:  Section 1 describes in detail the subsystems within the Hydrail System.  Section 2 describes the results of the Operational Simulation modelling that identify the size of the Hydrail System.  Section 3 describes the electricity market in Ontario and the forecast prices of electricity that Hydrail is likely to be subject to.  Section 4 summarizes the cost assessment performed on the Operational Simulation modelling outputs, and demonstrates how the BCR for RER based on the Hydrail System compares to that of RER with conventional overhead electrification.  Section 5 provides a brief environmental assessment of RER using the Hydrail System, and compares it to RER using conventional overhead electrification. It also considers the scenario of the Hydrail System being applied to the entire GO network.  Section 6 provides an overview of existing regulations, standards, and codes that are relevant to Hydrail, and identifies gaps where there will need to be the development of new regulations or the extension of existing ones.  Section 7 provides an assessment of the socio-economic benefits that could result for the broader Ontario economy and workforce as a result of implementing the Hydrail System.  Section 8 describes case studies of how other jurisdictions have approached the task of building support for the use of hydrogen and recommends how this could be deployed in Ontario.  Section 9 provides an overview of the strategies that other jurisdictions are adopting to encourage a transition to the use of hydrogen, and how businesses are responding to this in the rail vehicle market and more generally.  Section 10 considers options for how the Hydrail System could be implemented in the context of the overall RER procurement strategy.

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 Section 11 sets out a potential strategy for how the Hydrail System could be taken forward in alignment with the RER procurement strategy.  Section 12 reviews the risks that could affect the design, implementation, and operation of the Hydrail System, and also identifies potential opportunities for delivering additional benefits to Metrolinx and the province. 5. Part 5 is titled RER Program Electrification and contains two sections:  Section 1 is an overview of the RER Program.  Section 2 identifies how the current of the conventional overhead electrification would change if a Hydrail System is implemented. 6. Part 6 contains recommended next steps and associated timescales. 2.4 Study Methodology The Hydrail feasibility study commenced at the start of June 2017 and was completed at the end of December 2017. The study was undertaken by experts from three organizations: 1. CH2M HILL Canada Limited (CH2M [now Jacobs]) served as the overall project manager for the study and provided content in relation to railway operations, rail vehicles, environment overview, and transition planning. 2. EY prepared the Electricity Policy and Pricing, Cost and Benefits, Socio-Economic Impacts, Public Acceptance and Commercial sections of the study, as well as the sub-section on the Hydrogen Economy. 3. Canadian Nuclear Laboratories (CNL) provided inputs in the areas of hydrogen technologies, Hydrail System modelling, and applicable codes and standards. Support to the study was provided by departments within Metrolinx, particularly in relation to Fleet Engineering and Environment, plus businesses, universities, industry associations, and government agencies (provincial and federal). A full list of the organizations that the study team interacted with is provided in Appendix E. 2.5 Permissions The report’s authors have obtained pemission to use the illustrations and photographs used in the report from their owners except for the photograph in Figure 3-13 where ownership could not be established. The report’s authors also acknowledge that the pictograms incorporated into Figures 1-1, 3-5, 4-1, 4-48 and B-1 were created by Hydrogenics Corporation who have given permission for their use.

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3 Hydrogen Overview

The objective of Part 3 is to provide the reader with an understanding of the various technologies that underpin the use of hydrogen as a stored power source and provide examples of existing hydrogen related projects that are relevant to the Hydrail concept. It will include a summary of the technologies, their capabilities and current capacity plus commentary on the maturity of these technologies. This will include:  Hydrogen generation  Storage  Distribution  Fueling  On vehicle storage  Reconversion of hydrogen to power (fuel cells), and  Ancillary equipment such as on vehicle batteries and regenerative breaking. This is intended to provide a basis of understanding that is then used in Part 4 where the Hydrail System, as applied to the GO network, is defined. 3.1 Introduction to Hydrogen This section provides background knowledge on hydrogen as a fuel and energy storage solution, and the technologies that support the hydrogen system, converting natural gas or generated electricity to hydrogen for temporary energy storage, and back from hydrogen to electricity to power electrical equipment. The discussion in this section provides basic information and confidence that the technology is developed, modular, off-the-shelf, and has established levels of performance. Hydrogen atoms permeate the Universe. Yet on Earth, while hydrogen is abundant and essential to life, it is always chemically combined—particularly in the form of water and, to a lesser extent, as oil and gas—because any free hydrogen quickly combines with oxygen in the air. However, there are simple ways to produce pure hydrogen from water, hydrocarbons, or both. The simplest approach is by passing an electric current through water, the process known as electrolysis, which can easily be arranged to produce pure streams of hydrogen and oxygen. Every school chemistry lab routinely demonstrates this process, which is illustrated on Figure 3-1.

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FIGURE 3-1 SCHEMATIC OF WATER ELECTROLYSIS PROCESS2

Water always contains ions in the form of positively charged hydrogen ions (H+) and negatively charged hydroxyl ions (OH-). By passing an electric current—a stream of negatively charged electrons— + H are neutralized and converted into molecules of hydrogen gas (H2) at the cathode. Meanwhile, at the anode, the applied current is stripping electrons from hydroxyl ions and converting them into molecules of oxygen gas and neutral water molecules. The only input is a substantial amount of electrical energy; in theory, about 39.3 kilowatt-hours (kWh) to produce 1 kilogram (kg) of hydrogen. (In practice, some electrical energy is lost, and 50 kWh/kg is typical.) The bulk of the electrical energy is now stored in the hydrogen and can be retrieved by reversing the electrolysis process in what is called a fuel cell. Combined with the lightness of hydrogen, the relatively large amount of energy that is stored when water is converted into hydrogen means that the reverse of converting hydrogen back to water is an exceptionally low-weight source of energy. For trains, primary energy could come from onboard supplies of hydrogen; this is Hydrail. Hydrogen is just one of a number of energy currencies and, like monetary currencies3, are interchangeable. So Hydrail’s energy originates in electricity from the grid. The first currency conversion happens at a convenient, fixed location where electricity is converted into hydrogen. The hydrogen is then loaded onto trains.

2 U.S. Department of Energy (DOE). 2017. https://www.energy.gov/. Accessed October 2017. https://energy.gov/sites/prod/files/pem_electrolyzer.png 3 The concept of energy currencies is attributed to David S. Scott in his 2008 book Smelling Land: the Hydrogen Defense against Climate Catastrophe (Canadian Hydrogen Association).

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A second currency conversion occurs when hydrogen is reconverted into electricity to power the train (Figure 3-2)4. Although it is also possible to convert hydrogen into heat energy by burning it, its direct conversion to electricity is advantageous both because it is a more efficient conversion and because electricity is a more versatile form of energy.

FIGURE 3-2 ELECTRICITY AND HYDROGEN TRANSACTIONS BASED ON TWO PROCESSES5

4 Hoffrichter, Andreas. 2013. Hydrogen as an Energy Carrier for Railway Traction. Doctoral thesis. The Birmingham Centre for Railway Research and Education Electronic, Electrical and Computer Engineering College of Engineering and Physical Sciences. The University of Birmingham. April. 5 Efficiencies are discussed in Section 4.1.3.

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3.2 Hydrogen Technology 3.2.1 Hydrogen Production Options Hydrogen has to be manufactured with engineered processes. Electrolysis is one of four process technologies that can produce hydrogen, as shown in Figure 3-3.

FIGURE 3-3 HYDROGEN PRODUCTION TECHNOLOGIES

Fossil Carbon Processes convert the energy in hydrocarbons to pure hydrogen by several routes. The currently predominant route to hydrogen reforms natural gas by steam-methane reforming (SMR) and similar variations on this technology. This is an energy-efficient process, and today produces about 96 percent of the hydrogen essential to converting oil into usable refined products. However, SMR processes also co-produce one CO2 molecule for every four molecules of hydrogen.

Using SMR and other CO2-producing variations to produce hydrogen is questionable because there is also the possibility of producing hydrogen and pure carbon from natural gas. This is called partial reduction. It is recognized as an interesting possibility, since the carbon is produced in a stable form that would not require sequestration. However, partial reduction and SMR both require processing CH4, which is a powerful greenhouse gas (GHG). Partial reduction is also an inefficient process, since it produces only half as much hydrogen as an SMR process, and industrial-scale processes for partial reduction are undeveloped.

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Carbon-Neutral Processes rely on diverse biological processes capturing CO2 from the atmosphere, the release of hydrogen from their products, and return of the CO2 to the atmosphere. However, they are inefficient and not available on a large scale. Sulphur-iodine, copper chloride, and high-temperature electrolysis are the principal Thermo- Chemical Processes that are currently under development for large-scale hydrogen production but are not currently commercially available. While all use some input of electrical energy, a substantial proportion of the input energy comes from heat. So, electricity usage would be reduced and somewhat higher input prices accommodated. The advantages of the water electrolysis process over other hydrogen production technologies include:  GHG-free: If the electricity is from a GHG-free generator, then electrolysis is the simplest GHG-free hydrogen production technology in terms of fewer processes required to obtain hydrogen.  Modular: Additional capacity for hydrogen requires the addition of electrolyzer stacks.  Clean process: During operation, only electricity and water are used to make hydrogen; no additional chemicals or raw materials are needed.  Simple O&M: There are no moving parts within the electrolyzer stack, so operational issues arising from such mechanical interactions and periodic maintenance requirements are minimal.  Load-following: Electrolysis provides the ability to follow the demand for hydrogen and use electrical grid time periods with cheaper electricity prices.  Simpler decommissioning: After the lifetime operation of the plant, decommissioning is much simpler due to the limited number of parts and accessories. For these reasons, it is proposed that the Hydrail System uses water electrolysis instead of the other technologies. 3.2.1.1 Hydrogen Production Scale This section describes the breakdown and scale of hydrogen global production capacity, production sources, and consumption markets. On Figure 3-4, the “Merchant” component of global capacity is the significant feature, since it represents the 23,000 tonnes of hydrogen that is produced for dispersed consumption. (The remainder is produced and used locally, either within a plant site or over the fence from a separate supplier.) The 4 percent or 5,500 tonnes per day (tpd) produced globally by electrolysis is widely dispersed and largely corresponds to the 4 percent of consumption categorized as “General”. Its uses are diverse, including hydrogenation of vegetable oils, various steel-making applications, passivation of semiconductors, and use as a launch fuel for some space vehicles.

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FIGURE 3-4 GLOBAL INDUSTRIAL HYDROGEN PRODUCTION CAPACITY, PRODUCTION, AND CONSUMPTION

About 1,500 tpd of hydrogen is produced and consumed by industry (mainly, refineries) in Canada6. These numbers highlight the availability of knowledge and expertise in Canada and across the globe in handling large volumes of hydrogen daily. The hydrogen requirement for the Hydrail System within the GO network would be an order of magnitude smaller in scale than the current daily Canadian production of hydrogen and comparable to the existing scale of electrolytic production. 3.2.2 Placing Hydrogen in Context To reduce emissions, various options exist for displacement of petroleum fuels for different forms of transportation, most depending on electricity as the intermediate source, produced by primary low- emitting energy source, such as nuclear, hydraulic, wind, or solar. Electricity is predominantly sourced from a grid, so has distinctive differences from other primary energy sources: it cannot be directly applied beyond the reach of the grid, and it cannot be stored. For some transportation applications, extending the grid to track electrification for trains and trolley vehicles is an option. Otherwise, for vehicle applications, electricity has to be captured chemically. This can be by transforming chemicals in batteries (for example, by converting lithium cobalt oxide [LiCoO2] to lithium metal in lithium ion batteries [LIBs], or by synthesizing a fuel, usually by changing water into hydrogen). As discussed in Section 3.2.11, since today’s battery technology is impractical for high-frequency, high-capacity, high-speed trains, the practicable choices for applying electricity to these types of rail transportation is either to do so directly through track electrification or indirectly by converting hydrogen to electricity on-board the train, using a fuel cell. The hydrogen production, hydrogen storage, and electricity production processes would form part of an overall Hydrail System for the GO network. These processes and associated subsystems are described in the next sections.

6 Pacific Northwest National Laboratory (PNNL) and U.S. Department of Energy (DOE). 2016c. Resource Center: North American Merchant Hydrogen Plant Production Capacities (1000 kg/day or larger). Accessed October 2017. https://h2tools.org/sites/default/files/data/North percent20America_merchant_hydrogen_plants_Jan2016_MTD percent2B.xlsx.

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3.2.3 The Hydrail System The Hydrail System is shown on Figure 3-5. The technology for each of the subsystems in the overall system is described in the following sections.

FIGURE 3-5 THE HYDRAIL SYSTEM

3.2.3.1 Ontario’s Electricity Supply Ontario’s electricity grid draws over 90 percent of its electricity from a mix of nuclear, hydraulic, wind, and solar sources, which share the advantage of being low-emitting. Ontario’s grid is comparable to the provinces of Quebec, Manitoba, and British Columbia in being green, emitting very little CO2. But where these other provinces derive their electricity predominantly from controllable hydroelectric (hydro) sources, Ontario’s green generating sources have limited or no capability to adjust to the varying load demand on the grid. The collective result is intermittent excess capacity averaging over 1,000 megawatts (MW)7. Over the 20-year period from 2016-2035, an average annual surplus of 12.2 terawatt-hours (TWh) is predicted by an independent assessment of the Ontario grid8. This is representative of the surplus that would exist due to additional baseload generation required to meet the province’s GHG reduction targets for 2030 and 2050. This includes new generation of 20 to 40 TWh of electricity required by 2025, per the assessment of Ontario’s 2013 Long-term Energy Plan9. This considers the loss of 20 TWh of clean baseload generation from the closure of Pickering Nuclear Generating Station (PNGS)10. While projections are speculative, there is reasonable certainty that shorter-term mismatches between supply and demand will continue to exist, driven both by fluctuations in daily electricity demand and fluctuating generation by renewable technologies on multiple time scales. Details of how Hydrail could access this fluctuating surplus of electricity over demand are discussed in Sections 4.2.2.1 and 4.3.

7 HOEP data from the Independent Electricity System Operator, http://ieso.ca/ 8 Market Intelligence and Data Analysis Corporation (MIDAC). 2016. Grid Integrated Electrolysis. Prepared for Next Hydrogen. October 31. 9 Brouillette, Marc. 2016a. Ontario’s Emissions and the Long-term Energy Plan: Phase 1 – Understanding the Challenges. Strategic Policy Economics. November. Accessed November 2017. https://strapolec.ca/uploads/Ontario_s_Emissions_and_the_LTEP_- _Phase_1_Final_Report_November_2016.pdf 10 Market Intelligence and Data Analysis Corporation (MIDAC). 2016. Grid Integrated Electrolysis. Prepared for Next Hydrogen. October 31.

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Track electrification has no flexibility in the use of electricity, and its demand will peak at times of existing peaks of electricity demand on the Ontario grid. While it uses only about one-third of the electricity consumed by Hydrail, track electrification’s use of electricity at peak periods will likely be derived in substantial proportion from CO2-emitting gas-fired generation. With Hydrail, electricity will overwhelmingly be consumed at times of off-peak demand when gas-fired generation levels are low to nonexistent. So, despite using three times as much electricity as track electrification, Hydrail would draw less than 7 percent of its electricity input from gas-fired sources and could be comparably effective as electrification for RER decarbonization. Either approach will produce less than 20 percent of emissions from diesel traction. This is discussed in detail in Section 4.2. 3.2.4 Hydrogen Fuel Production 3.2.4.1 Hydrogen Production by Water Electrolysis There are two alternative approaches to electrolysis technology. The long-established approach uses either potassium or sodium hydroxide as an electrolyte to allow the current to pass through a reservoir of water (to create alkaline cells). The newer approach uses SMR technology as proton- exchange membrane (PEM) fuel cells, but operated in reverse and not requiring the presence of an electrolyte. Both technologies are well-established11, and the choice between them is an economic one, based on capital cost, cell efficiency, maintenance frequency, and the ability to handle high-current densities. Alkaline cells require very little maintenance; PEM cells need to be periodically rebuilt (at around 30,000 hours of operation) due to slow membrane deterioration. PEM cells have more flexibility to accept high-current densities when electricity is most affordable. Producing and handling hydrogen on the scale needed for the RER GO network is not a significant issue. Using SMR, individual oil refineries consume hydrogen at two to four times the entire RER requirement. Though usually operated on a much smaller scale, electrolytic production is a long- established alternative method wherever very high purity is required and the technology is intrinsically modular. 3.2.4.2 Reliability, Maintainability, and Safety With many industrial processes, equipment needs increase as demand for the product grows—the classic “scale-up.” This is not the case with water electrolysis, which is a modular technology. Using proven modules of 3- to 10-MW capacity (50 to 150 kg/h of hydrogen), the total deployment needed for the RER GO network is handled by deploying the appropriate number of modules. Water electrolysis using alkaline cells has been in use on an industrial scale for over a century. Because they have few moving parts (pumps and compressors), the cells have been found to require very little maintenance. With the category of alkaline cells, there are two broad classifications: unipolar and bipolar12. CNL used a unipolar installation to produce deuterium (heavy hydrogen) gas commercially for 25 to 30 years with almost no maintenance and total reliability.

11 Zoulias, Emmanuel, Elli Varkaraki, Nicolaos Lymberopoulos, Christodoulos N. Christodoulou, and George N. Karagiorgis. 2004. A Review of Water Electrolysis. Pikermi, Greece: Centre for Renewable Energy Sources (CRES). Accessed November 2017. http://hydrogenoman.com/docs/click percent20on percent20the percent20attached.pdf 12 The differences between unipolar and bipolar cells are configurational, distinguished by whether cells are fed current individually or in groups.

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Out of four individual cells, one gas separator replacement was required, and gaskets had to be replaced twice. Another cell operated in a prototype plant for 2.5 years without problems. With bipolar cells, fabrication from nickel is advisable to avoid corrosion from stray currents. Discussion with A. Stuart, who was Technical Manager of the Electrolyzer Corporation (Canada’s main supplier of alkaline cells for more than 50 years) confirmed CNL’s experience: alkaline cells will operate for 20 to 30 years before they need to be refurbished and have lifetimes of 50 years13. Experience with the newer technology of PEM cells has so far been similar, but the separator of a PEM cell is an exception. Where alkaline cells need a physical barrier to separate the gases, the membrane in a PEM cell is a more active component, allowing the passage of protons. This is an operations issue, with replacement of this membrane needed when the cell voltage becomes too high. Because the impact on the membrane is cumulative with hours of operation, and the Hydrail cells are not operated continuously, cell rebuild for membrane replacement is estimated to be needed after about 7 years. Water electrolysis using alkaline cells has been in use on an industrial scale for over a century. The few moving parts are pumps and compressors, and the cells require very little maintenance. Installations have operated for decades with very high reliability. Both alkaline and PEM electrolyzers have excellent safety characteristics14, with the reservation that hydrogen purity deteriorates with oxygen contamination when the cells are operated at higher pressures. This is not a significant issue in the pressure range (up to 3 megapascals [MPa]) used in this assessment. A master’s thesis by Joonas Koponen15 gives an excellent overview of electrolyzer technology. Koponen notes that, compared to the alkaline type, the PEM type of electrolyzer has much lower cross-over contamination, and ability to operate over a wide range of current density and to respond easily to varying current. Only operation above 100 bar (which is not envisaged) requires the use of thicker membranes. Koponen continues: “The gas crossover rate is much lower than in alkaline water electrolyzers enabling the use of almost the whole range of rated power. Additionally, the solid polymer membrane enables the electrolyzer to respond more quickly to fluctuations in the input power. Thus, PEM electrolyzers can be operated in a much more dynamic fashion than alkaline electrolyzers.” As with almost all situations where hydrogen is produced, stored, or used, providing good ventilation backed up with hydrogen detectors can completely avoid buildup of hydrogen concentrations in air that could support ignition. Electrolytic cells need protection from freezing conditions, so the building where they are housed must be designed to accomplish proper ventilation with interlocks to shut down electrolysis if the ventilation system fails. While proper ventilation design is sufficient, this can easily be backed up by incorporating large blow-out panels in the building walls to ensure that a deflagration cannot transform into detonation. Additional information on safety is provided in Appendix B.

13 Stuart, Andrew, Technical Manager of the Electrolyzer Corporation. 2017. Personal communication with Nirmal Gnanapragasam Canadian Nuclear Laboratories. October 17. 14 Grigoriev, S.A., V.I. Porembskiy, S.V. Korobtsev, V.N. Fateev, F. Auprêtre, and P. Millet. 2011. “High-pressure PEM water electrolysis and corresponding safety issues.” International Journal of Hydrogen Energy. Vol. 36, Issue 3. pp. 2721-2728. February. Accessed October 2017. https://www.sciencedirect.com/science/article/pii/S0360319910005392 15 Koponen, Joonas. 2015. Review of water electrolysis technologies and design of renewable hydrogen production systems. Master’s thesis. Lappeenranta University of Technology, LUT School of Energy Systems Degree Programme in Electrical Engineering. Accessed November 2017. https://www.doria.fi/bitstream/handle/10024/104326/MScThesis_JKK.pdf

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3.2.5 Fuel Storage – Gaseous and Liquid Hydrogen The Hydrail concept includes intermittent production of hydrogen with the electrolyzers operating, at times, dictated by the price of electricity and operating requirements of the Ontario grid. Consequently, hydrogen has to be stored. There is a second storage requirement for a supply of hydrogen to be available for overnight train refuelling. Those requirements are both land-based. A third storage requirement is the mobile one for storage on the trains. There are four different storage technology types relevant to the Hydrail project, as shown on Figure 3-6. Hydrogen storage is a key component when handling hydrogen from production to application, with distinction in terms of location of storage: stationary (fixed in location), and mobile (onboard vehicles). The storage technologies have evolved based on the following characteristics, similar to other energy storage technologies,16 such as batteries, compressed air, and pumped hydro.  Time-driven: The duration of storage dictates the type and form of storage required, both in terms of physical and economic limitations. For example, storing in the liquid phase is not advisable beyond 3 to 5 days due to boil-off and consequent loss of hydrogen to avoid storage tank overpressurization. Underground storage17 can hold a large volume of gas for months and has the potential to smooth seasonally variable production—similarly to the widely used storage of natural gas.  Space-driven: The density of storage is a key component that determines two aspects of storage: volume of storage, and space required for that volume of storage. Depending on the application and storage location, compressed gas and liquid are two potential phases to store hydrogen. Liquid hydrogen provides almost double the density of compressed gas at 70 MPa. Solid phase storage through metal and chemical hydrides provides comparable densities to 70 MPa gas but not the transfer rates required for the volume of hydrogen involved with the Hydrail application.  Demand-driven: Storage of hydrogen is tied closely to the delivery characteristics, such as the transfer rates and losses. If large and permanent demand exists for hydrogen in a region, expanding perhaps beyond Hydrail for the RER system, then pipeline distribution and storage18 could be used to buffer storage and provide reliability. The lengths of pipelines could be anything from short links between a hydrogen production site and a nearby fuelling point, to a network of pipelines across the RER network.

16 Sabihuddin, S., A. E. Kiprakis, and M. Mueller. 2014. "A Numerical and Graphical Review of Energy Storage Technologies." I. Taniguchi, ed. Energies. ISSN 1996-1073. December 29. Accessed October 2017. www.mdpi.com/1996-1073/8/1/172/pdf 17 Panfilov, M. 2016. "4 – Underground and pipeline hydrogen storage." Compendium of Hydrogen Energy, Volume 2: Hydrogen Storage, Transportation and Infrastructure. pp. 91-115. Accessed October 2017. http://dx.doi.org/10.1016/B978-1-78242-362-1.00004-3 18 Gondal, I.A. 2016. "12 – Hydrogen transportation by pipelines." Compendium of Hydrogen Energy, Volume 2: Hydrogen Storage, Transportation and Infrastructure. pp. 301-322. Accessed October 2017. http://dx.doi.org/10.1016/B978-1-78242-362-1.00012-2

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Figure 3-6 illustrates the storage options.

FIGURE 3-6 HYDROGEN STORAGE TECHNOLOGIES RELEVANT TO HYDRAIL

3.2.5.1 Design and Functionality Compressed gaseous hydrogen is stored in cylinders, tanks, or vessels, depending on the pressure. For pressures up to 20 MPa and stationary storage, gas can be stored in large tanks made of carbon or stainless steels, similar to the way propane is stored. For high-pressure storage, there are four types of pressure vessels, depending on the construction, application, and pressure requirements. Types I and II are for stationary storage applications, while Types III and IV are for mobile storage applications. The energy inputs for gaseous and liquid hydrogen differ significantly, as follows:  For both forms, the estimated total energy to produce hydrogen at 2 MPa by electrolysis is 65 kilowatt-hours per kilogram (kWh/kg). There are expectations for modest reductions in the future, since it is currently almost double hydrogen’s lower heating value (LHV)19.

19 All hydrogen-containing fuels have two heating values, depending on whether the energy released does (the higher heating value) or does not (the lower heating value, LHV) include the heat released when water vapour condenses. This is particularly significant for hydrogen, since its only product of combustion is water.

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 For gaseous storage, the subsequent compression to 90 MPa (to facilitate fast filling of locomotive tanks at 70 MPa) and cooling to -40 degrees Celsius (°C) requires about 8 percent additional energy (including the total energy to produce and compress the hydrogen).

To produce liquid hydrogen (LH2) requires about 17 percent additional energy. This is an undesirably large premium, unless there are circumstances that make use of LH2 inescapable. There is little hope that the additional energy for liquefaction can be reduced.20 3.2.5.2 Reliability, Maintainability, and Safety Handling hydrogen (produced by electrolysis or otherwise) is very well-established. Probably because of its perception of being hazardous, hydrogen attracts close attention to its containment, handling, ventilation, and avoidance of ignition sources. Providing good ventilation—either through frequent air changes or being open to the outdoors—is backed up by deployment of hydrogen detectors interlocked to shut down operation. Over 50 years of working with hydrogen for extensive experimental usage and protracted production of deuterium gas, CNL has experienced no significant events attributable to hydrogen, and only a handful of instances when minor leaks were detected. Gaseous hydrogen is becoming well-characterized as a fuel for transportation applications. There is less experience with liquid hydrogen. That it is a liquid and extremely cold are additional considerations for its safe handling. As a transport fuel, it has so far been mostly used as a propulsion material in some rockets for space launches by the National Aeronautics and Space Administration (NASA). Through its use for cryogenic separation of hydrogen isotopes, CNL has had limited experience with its use and with no significant problems. LH2 does require some additional measures not needed for gas storage, such as selection of proper materials (stainless steel or aluminum but not carbon steel, which is brittle at very low temperatures) and providing measures for rapid, controlled dumping of LH2 should there be a loss of vacuum in the containing vessel.

There are arguments for and against the two storage forms, as LH2 or as compressed hydrogen gas (CGH2), as follows:

 Storage: LH2 volumes are a little over half that for CGH2. Onboard storage could turn out to be particularly difficult with CGH2; diesel multiple units (DMUs) will be more difficult than locomotives in this respect.

 Train fuelling will probably be faster with LH2 but requires more elaborate equipment to 21 handle -253°C cold . After the first fill with LH2—when the tank has to be cooled—filling is straightforward. With CGH2, some precooling will always be required to offset the heat from hydrogen’s adiabatic expansion.

 Safety is manageable with both, and losses are rare in any circumstance. With CGH2, losses from the extremely robust cylinders are improbable and would disperse rapidly. With LH2, leakage or

20 Praxair Technology, Inc. 2011. Advanced Hydrogen Liquefaction Process. Contract Number: DE-FG36-08GO18063. Project ID PD018. Presented at the DOE annual Merit Review Meeting. Joe Schwartz, presenter. Tonawanda, New York: Praxair. May 10. Accessed October 2017. https://www.hydrogen.energy.gov/pdfs/review11/pd018_schwartz_2011_p.pdf. In a program 80 percent funded by the DOE, Praxair spent close to $1 million in 2011 trying to improve the efficiency of hydrogen liquefaction and got almost no improvement. This work hoped to improve energy usage from 14 to 11 kWh/kg. It achieved only 13.7 kWh/kg. Even 11 kWh/kg is one-third of hydrogen’s LHV. The heat from ortho-para conversion is greater than the heat of liquefaction (0.45 megajoule per kilogram [MJ/kg]); it has to be catalyzed or will lead to vaporization when it occurs spontaneously because it’s about 18 percent of the existing total (approximately 2.5 kWh/kg). The Praxair report contains the statement that “Liquid hydrogen might not be the best way to supply the ‘Hydrogen Economy’, but it will play a significant role in the transition period.” 21 Hillmansen, S. 2003. The application of fuel cell technology to rail transport operations. London, England: Department of Mechanical Engineering, Imperial College of Science, Technology and Medicine.

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losses, though highly improbable, are perhaps somewhat more plausible, and they would disperse more slowly.  Neither fuel form is familiar to the public, so they would need to be educated to gain their support. The case for CGH2 could be marginally easier, particularly since it is already widely in operation.

LH2 for onboard use has the added requirement of providing equipment to vaporize the liquid, except initially, using heat from the fuel cells.

CGH2 has been the fuel chosen so far by almost all adopters of HFCs. Approximately 11,000 fuel cell forklifts were in daily use in North America in 201622. Most of these devices are made by PlugPower and are located in the United States (U.S.)23. Fuel cell material handling equipment (MHE) remain the most successful fuel cell vehicles (FCVs) to date. The application of fuel cell MHE in other regions has not been comparable to the U.S. due to smaller fleets, fewer operating hours, different regulations, and lower subsidies. The DOE reports that approximately $10 million in funding was allocated to the MHE sector through the American Recovery and Reinvestment Act of 2009. Fuel-cell-powered forklifts provide the most extensive application of the technology so far, and can be managed like railway applications. No safety problems have been reported from these or other applications. Additional information on safety is provided in Appendix B. 3.2.6 Fuel Distribution Fuel distribution for Hydrail is only required for certain infrastructure scenarios. For example, if the hydrogen production is located at a distance away from the GO network, then the fuel needs to be brought to the refuelling facilities, similar to diesel being brought from distribution centres across the GTHA. For a scenario where the hydrogen production is near the refuelling stations, fuel distribution may not be required. There are two types of fuel distribution currently being considered by the study: pipeline distribution of hydrogen, and trucking of hydrogen. Trucks are currently used by gas companies to transport hydrogen from production facilities to industrial customers. For the scale needed for the RER system, hydrogen pipelines will be needed, either locally or extensively, though they could be supplemented by truck transport. While pipelines lack the flexibility of trucking, they are a cheaper option when hydrogen is being moved on daily, large scales. In such cases, there is the need for local piping to connect trains to high- pressure supply tanks and those tanks to the source of the hydrogen. Whether pipes long enough to be thought of as a pipeline are needed will depend on whether hydrogen is produced close to the refuelling points. When the scale of use is large enough, it is possible to contemplate the possibility of extensive distribution by smallish (approximately 150-mm diameter) pipelines, but this assessment depends on where hydrogen will be produced. Hydrogen-only pipelines of various lengths up to hundreds of kilometres operate in several locations, including Alberta and the Sarnia area of Ontario. The technology is fairly similar to natural gas distribution, except that pipe materials have to be selected

22 Office of Energy Efficiency & Renewable Energy. 2016. State of the States: Fuel Cells in America in 2016. Washington, D.C.: U.S. Department of Energy. November. Accessed October 2017. https://energy.gov/eere/fuelcells/downloads/state-states-fuel-cells-america- 2016 23 E4tech. 2016. The Fuel Cell Industry Review 2016. Accessed October 2014. www.fuelcellindustryreview.com.

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT for hydrogen compatibility (that is, using stainless steel rather than high-strength carbon steel because the latter is susceptible to hydrogen embrittlement). No instances of a hydrogen pipeline rupturing have been reported. 3.2.6.1 Design and Functionality Hydrogen fuel for Hydrail would be produced by electrolysis using electricity from the Ontario electricity grid. This introduces some complexity, as well as great flexibility. The electrolysis load is substantial, so locations of interface with the grid need to be selected with reference to excess or restricted current-carrying capabilities. Should it be necessary to address this constraint, hydrogen could most readily be transferred to refuelling points by buried pipelines with diameters of the order of 150 millimetres (mm). One possibility would be to route such pipelines along track rights-of-way (ROWs). Choice of locations for generation is for a future, more detailed level of study: sites could be distributed around the RER network or centralized; they could be close to refuelling points, or located remotely with longer pipelines. One possible concept, which is used by the petrochemical and refinery industries, is a single network of interconnected pipelines with more than one point of hydrogen injection and multiple draw-off locations. Because of hydrogen’s very low viscosity, designs can incorporate little or no pumping, with hydrogen moving within the pipeline network in response to pressure gradients. 3.2.6.2 Reliability, Maintainability, and Safety Pipelines distributing gas use well-established technology and are reliable. Gas pipelines are mainly vulnerable to external impacts, so should be either buried or, slightly less securely, elevated. If, as envisaged, both short pipelines for train fuelling and longer pipelines for wider distribution are entirely on railway land, this should achieve a high level of security. The technology to detect and isolate leakage from a hydrogen-gas pipeline is identical to the standard practice of the natural gas industry. Insulated, short pipelines for refuelling with LH2 would require more extensive engineering and could not be buried. Road shipment by tanker of both gaseous and liquid hydrogen is routine and provides a means of backing up pipeline supply should the primary electrolytic supply be temporarily disrupted. Additional information on safety is provided in Appendix B. 3.2.7 Refuelling and Dispensing Refuelling and dispensing comprises buffer storage tanks (refuelling tanks) and the hydrogen transfer unit (dispensing using) that connects to the tail vehicle for fuelling – similar to a diesel fuel pump. These would most likely be sited in facilities similar to where diesel fuelling occurs today within the GO network. 3.2.7.1 Design and Functionality Refuelling is a distinctive feature for Hydrail, unlike track electrification but akin to existing diesel operation. Design for fast refuelling of up to one or two tonnes of hydrogen for a single locomotive is a significant but surmountable design challenge. Fast refuelling with CGH2 in 2 minutes for hydrogen- fuelled cars is routine, using a verified gas-tight connector, but the quantities for a locomotive are two orders of magnitude larger, somewhat less for individual EMUs.

If the system used LH2, fuelling would be very similar to that for diesels with gas-tight connections. For fuelling rail vehicles with gaseous hydrogen, the existing technology can be adapted to fit the Hydrail

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT application without major redesign using a combination of multiple nozzles, moderate enlargement of nozzles, and lengthened refuelling time. The design draws lessons from similar setup for other hydrogen applications in the transportation sector, including cars and buses, as shown on Figure 3-7. The schematic provides a view of the hydrogen being transmitted from the storage and distribution (via pipeline at 2 MPa) to the refuelling system, which has a cascade of tanks (S-1, S-2, and S-3) and valves at higher pressure (87.5 MPa). The gas would be pressurized from the supply at 2 to 87.5 MPa using a series of compressors (C-1), depending on the volume of gas being compressed. The gas is transferred to the tank onboard the FCV, which is at a relatively lower pressure (70 MPa). To achieve enough transfer rates of gaseous hydrogen when it expands from 87.5 to 70 MPa, the gas needs to be cooled to -35 to -40° C using the cooling machine. For operational reliability and safety, devices such as temperature sensors (T), pressure indicators (P-1, P-2), control valves, and pressure relief valves (PSV) are used.

FIGURE 3-7 SCHEMATIC OF REFUELLING STORAGE AND DISPENSING SETUP FOR HYDROGEN POWERED CARS24

CGH2 will be dispensed from track-side tanks at 85 to 100 MPa, either pre-cooled or passed through a heat-exchanger to chill it to -40°C (to accommodate hydrogen’s heat of expansion), and connected to the train using existing technology for secure transfer of compressed gaseous fuels. The limiting factor for rates of gas fuelling is understood to be a maximum feed rate to individual tanks of 8 kg/min. However, since the storage will be configured to as many as 20 individual tanks, this does not pose a significant constraint. Fuelling with liquid hydrogen would be similar to that for diesel fuel, except the design must accommodate the very low temperature of the fluid, and be connected with a leak-tight seal.

24 National Renewable Energy Laboratory (NREL). 2014. Hydrogen Station Compression, Storage, and Dispensing Technical Status and Costs. Independent Review published for the U.S. Department of Energy Hydrogen and Fuel Cells Program. Technical Report NREL/BK- 6A10-58564. Contract No. DE-AC36 08GO28308. May. Accessed October 2014. https://www.nrel.gov/docs/fy14osti/58564.pdf.

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3.2.7.2 Reliability, Maintainability, and Safety The location of refuelling points will depend on future discussions with RER Operations. Refuelling would be an upgraded version of the existing process.

For onboard storage of CGH2 at the proposed standard pressure of 70 MPa, the existing technology for refuelling cars and buses needs to be upgraded, probably complemented by using several connection points to meet the specified target for refuelling time. These aspects of Hydrail all depend on existing technology. The U.S. Government’s Office of Energy Efficiency and Renewable Energy states25: “High-pressure tanks (3,600 psi [250 bar]) have been used safely in compressed natural gas vehicles (NGV) for many years. Improved versions of these tanks made of high-strength composite materials are now used to store hydrogen at higher pressures (5,000 [350 bar] and 10,000 psi [700 bar]) to achieve greater driving range in hydrogen-fueled vehicles. High-pressure hydrogen tanks are designed not to rupture and are held to rigorous performance requirements. Furthermore, these tanks undergo extensive testing to make sure that they meet these performance requirements.” A pressure of 700 bar is envisaged for on-board gas storage for Hydrail. Since the Hydrail design is modular, these storage tanks will have dimensions — particularly diameter — that match the configurations used extensively in other vehicle applications. These tanks have been in service for at least a decade with extensively tested performance. In 2010, the DOE’s Argonne Lab issued an assessment report on both the 350-bar and 700-bar tanks. Of note, the tanks are designed and tested to accept 25 percent overpressure to allow for excursions during fast filling. They are rated for 5,500 cycles of filling26. For Hydrail, the network of tanks needs to be engineered; but reliability, availability, maintainability, and safety (RAMS) present no uncharted issues. Refuelling locations should always be equipped with leak detectors — these are intrinsic to the nozzles with locked fittings— and either be provided with good ventilation or open-air dispersion. Additional information on safety is provided in Appendix B. 3.2.8 Vehicle Propulsion: Hydrogen Fuel Cells The fuel cell is at the core of the fuel cell based propulsion system for both light- and heavy-duty vehicular applications, as shown on Figure 3-8. The fuel cell delivers electricity in the form of direct current (DC) to electrically charge the onboard batteries. While more discussion on fuel cells and batteries is available in the next two sections, a brief description of the drive motors is required to understand the technologies and the preference for Hydrail. The batteries divert some of the electricity (DC) to a convertor that modulates the direct current with phase difference to achieve an alternating current (AC) to power an AC motor or to a converter that

25 Office of Energy Efficiency & Renewable Energy. 2017. High-Pressure Hydrogen Tank Testing. Fuel Cell Technologies Office, DOE. Accessed November 2017. https://energy.gov/eere/fuelcells/high-pressure-hydrogen-tank-testing 26 Hua, Thanh, Rajesh Ahluwalia, J-K Peng, Matt Kromer, Stephen Lasher, Kurtis McKenney, Karen Law, and Jayanti Sinha. 2010. Technical Assessment of Compressed Hydrogen Storage Tank Systems for Automotive Applications. ANL-10/24. Argonne, Illinois: Nuclear Engineering Division, Argonne National Laboratory; and Lexington, MA: TIAX LLC. Accessed November 2017. https://www1.eere.energy.gov/hydrogenandfuelcells/pdfs/compressedtank_storage.pdf

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT balances DC voltage to power a DC motor. For heavy-duty vehicles, including locomotives, AC motors are preferred over DC motors for these reasons27:  AC motors are simpler to construct, they require no mechanical contacts to work, such as brushes, although newer DC motors have no brushes either.  AC motors are lighter than DC motors for equivalent power.  Modern electronics allow AC motors to be controlled effectively to improve both adhesion and traction.  AC motors can be microprocessor controlled to a fine degree, and can regenerate current down to almost a stop; whereas, DC regeneration fades quickly at low speeds.  AC motors are more robust and easier to maintain than DC motors. The AC or DC motor would then deliver the traction power through the gear box and axle drive train to spin the wheels to move the vehicle.

FIGURE 3-8 FUEL CELL POWERED PROPULSION SYSTEM IN VEHICLES

Oxygen Light-duty Vehicles (air) (cars, buses, SUVs, etc.)

DC/DC Gear Box Hydrogen Fuel Cell Electricity (DC) Batteries Electricity (DC) Electricity (DC) DC Motor Dr ive Tr ain Convertor and Axles

Water

Oxygen (air) Heavy-duty Vehicles (locomotives, trucks, etc.)

DC/AC Gear Box Hydrogen Fuel Cell Electricity (DC) Batteries Electricity (DC) Electricity (AC) AC Motor Drive Train Convertor and Axles

Water © Canadian Nuclear Laboratories, 2017 3.2.8.1 Design and Functionality A fuel cell is a device that converts the chemical potential energy (energy stored in molecular bonds) of a fuel into electrical energy28. The streams and key components of a fuel cell are shown on Figure 3-9.

27 The Railway Technical Website. 2017. Electric Traction Control. Accessed November 2017.http://www.railway- technical.com/trains/rolling-stock-index-l/train-equipment/electric-traction-control-d.html 28 Hydrogenics. 2017a. Fuel Cells. Accessed October 2017. www.hydrogenics.com/technology-resources/hydrogen-technology/fuel-cells/.

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FIGURE 3-9 FUEL CELL SCHEMATIC COMPONENTS 29

Energy in the form of heat can also be produced by burning hydrogen gas in the presence of oxygen to produce water. Howerver, heat engines are fundamentally limited by what is known as Carnot efficiency and consequently, heat engines rarely achieve 40 percent efficiency in their conversion of the energy content of the fuel. Whereas fuel cells are not constrained by Carnot and efficiencies of 50 to 60 percent are attainable. There are a number of fuel cell technologies. These are summarized in a study of fuel cells for ships (as shown in Table 3-1). Each type has its own technological attributes.

29 U.S. Department of Energy (DOE). 2017. Fuel Cell Animation. Office of Energy Efficiency & Renewable Energy. Accessed December 15, 2017. https://energy.gov/eere/fuelcells/fuel-cell-animation,

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TABLE 3-1 RATING OF FUEL CELL TECHNOLOGIES FOR USE IN SHIPS AND MARINE VESSELS

Where hydrogen is the fuel, electricity, water, and heat are the only products of the chemical reactions that occur in different segments of the fuel cell. HFCs can have almost twice the efficiency of traditional combustions technologies30. For instance, a conventional fossil fuel power plant typically generates electricity at 33-35 percent efficiency. Fuel cells can generate electricity at an efficiency level of up to 60 percent. In addition, fuel cells also operate quietly and have fewer moving parts compared to conventional methods of producing electricity. They are also extremely compact, far smaller than a classical internal combustion engine. HFCs are currently being used extensively to provide commercial stationary power and in specialty vehicle applications (notably, forklifts). The main reason for slow commercialization of fuel cells in

30 U.S. Department of Energy (DOE). 2006. Hydrogen Fuel Cells. DOE Hydrogen Program. October. Accessed October 2017. https://www.hydrogen.energy.gov/pdfs/doe_fuelcell_factsheet.pdf

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT other sectors, including transportation, is not the technology itself, but the lack of infrastructure, which has to be in place to allow the technology to be widely adopted. The modularity and linear addition of cells to make stacks of various sizes and shape to fit the application makes fuel cells a much sought-after propulsion technology for different vehicle types. The ability to fill onboard tanks with hydrogen quicker than charging batteries for battery-electric vehicles (BEVs) is another practical attraction to fuel-cell-electric vehicles (FCEVs). The additional range can be added to vehicles at the design phase by merely adding a tank of H2, which is much lighter than the equivalent weight of batteries for the same range. The Hydrogen Council has recently published their overview of the roles best suited to BEVs and FCEVs, shown on Figure 3-10. The attributes of HFCs have triggered much interest among vehicle manufacturers around the world for cars, trucks, sports utility vehicles (SUVs), vans, buses, trains, ships, and airplanes to use fuel-cell- based propulsion systems. The full spectrum with comparison to the weight of vehicles and the distance each vehicle would travel per day is shown on Figure 3-10. Note that for most surface transportation vehicles, the fuel cells are part of a battery-based hybrid system to take advantage of the regenerative braking and to provide enough power for acceleration.

FIGURE 3-10 COMPARISON OF FUEL CELL APPLICATIONS31 FOR VARIOUS TRANSPORTATION SECTOR VEHICLES

31 Hydrogen Council. 2017a. How hydrogen empowers the energy transition. January. Accessed October 2017. http://hydrogeneurope.eu/wp-content/uploads/2017/01/20170109-HYDROGEN-COUNCIL-Vision-document-FINAL-HR.pdf

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Figure 3-10 shows that the most attractive and amenable technology is the PEM fuel cell, and PEM fuel cells are the default option for Hydrail for the RER system, since marine and rail applications have similar heavy-duty cycles and hours of operation. PEM fuel cells closely resemble PEM electrolyzers operated in the reverse direction. Rather than using electricity to split water into hydrogen and oxygen, the PEM fuel cell is fed hydrogen to the anode and oxygen (as air) to the cathode to produce water and electricity. A catalyst—usually platinum— dissociates molecular hydrogen into two protons and electrons; and the PEM membrane, which is the key technology in all PEM devices, allows the passage of H+ but prevents the passage of electrons, which must then rejoin the protons through an external electrical circuit, providing the electrical output of the fuel cell. At the cathode, the protons and electrons are reunited in reaction with an oxygen molecule, forming water. PEM cells operate in the region of 60 to 80°C, with pressure ranging from 1 to 3 MPa. Where hydrogen is the fuel, electricity, water, and heat are the only products of the chemical reactions that occur in different segments of the fuel cell. HFCs can have almost twice the efficiency of traditional combustion technologies32. For instance, a conventional fossil fuel power plant typically generates electricity at 33-35 percent efficiency. Fuel cells can generate electricity at an efficiency level of up to 60 percent. In addition, fuel cells also operate quietly and have fewer moving parts compared to conventional methods of producing electricity. They are also extremely compact, far smaller than a classical internal combustion engine. Canadian companies lead the world in bringing PEM technology to maturity. The Hydrogen Council has recently published their overview of the roles best suited to BEVs and FCEVs, shown on Figure 3-10. The attributes of HFCs have triggered much interest among vehicle manufacturers around the world for cars, trucks, SUVs, vans, buses, trains, ships, and airplanes to use fuel-cell-based propulsion systems. The full spectrum with comparison to the weight of vehicles and the distance each vehicle would travel per day is shown on Figure 3-10. Note that for most surface transportation vehicles, the fuel cells are part of a battery-based hybrid system to take advantage of the regenerative braking and to provide enough power for acceleration. Canadian fuel cells dominate in markets worldwide for transportation and stationary applications. Bringing the technology to the point of commercialization has had to address cost, scalability, endurance, and resistance to freezing. Scalability and operation in Canadian winter cold have been resolved. Endurance is now more than 30 000 hours and continues to accumulate in real-time. On cost, Ballard claims they have achieved a 65 percent reduction in 6 years, and costs continue to fall (see Section 4.2.2.2). Both for fuel cells and electrolyzers, PEM technology has come of age and is fully capable of scale-up. Hydrogenics’ fuel cells are already operating in the world’s first hydrogen-fuelled railway application in Germany, Alstom’s iLint. From one recent order alone, Ballard is supplying fuel cells for over 300 buses in China33. In June 2017, Hydrogenics is signing a purchase agreement to supply 1,000 bus units over the next 2 to 3 years with a different Chinese company. An announcement this October by

32 U.S. Department of Energy (DOE). 2006. Hydrogen Fuel Cells. DOE Hydrogen Program. October. Accessed October 2017. https://www.hydrogen.energy.gov/pdfs/doe_fuelcell_factsheet.pdf 33 Casey, Tina. 2015. "Boom! China Adds 333 Fuel Cell Electric Buses." CleanTechnica. September 29. Accessed October 2017. https://cleantechnica.com/2015/09/29/boom-china-adds-333-fuel-cell-electric-buses/

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT the Viking Cruise line that their next ocean-going ship will be powered exclusively by PEM cells fuelled by hydrogen is on the same scale34 as the entire RER GO network. Even at the much lighter scale of automobiles, Honda, Mercedes-Benz, Hyundai, and Toyota have begun commercial production of fuel-cell-powered cars. On October 26, 2017, an HFC-powered tram went into commercial operation in Tangshan, Hebei province, China. One year earlier, a hybrid tram system— partly powered by HFCs but with part of the route supplied by 750 overhead DC power—began operation in Qingdao, Shandong province. On the reconversion of hydrogen to electricity, except for the cruise ship—which is not yet a reality—the scale of power requirements for individual units on the RER GO network is significantly larger than existing fuel cell deployments, so the capability to scale up PEM fuel cell technology is an important consideration. At today’s scale of up to 200 kW per fuel cell module, around 20 to 30 such modules will be needed to power an RER locomotive. However, PEM fuel cell technology is intrinsically modular, and assembling modules either in parallel or in series is straightforward. EMUs will require fewer modules and are closer to the Alstom iLint, which combines four Hydrogenics modules. 3.2.8.2 Reliability, Maintainability, and Safety Reliability of fuel cells has enabled the growth of fuel cell applications in various transportation vehicles across the world, including that three major automobile manufacturers have started selling fuel-cell-powered vehicles to customers. There is proven revenue service operation of fuel-cell- powered transit buses beyond 25 000 hours of operation. Fuel cells have been operating in vehicles across the world, with a combined revenue service operation of more than 11 million kilometres of travel. Maintenance and failure of fuel cells is unlike that for conventional vehicles: fuel cells very gradually lose performance (rather than failing totally) and maintenance consists mainly of software download to determine the state of individual cells. When a cell’s performance is no longer considered adequate, it is rebuilt—at about 60 percent of the original cost—with a new membrane assembly. Additional experience is garnered from stationary fuel cell applications in grid services, and from combined heat and power (CHP) applications for backup or main power source for homes (mostly in Japan). The advantage of fuel cells, unlike other engines that have moving parts, is the high reliability and low maintenance, irrespective of where it is applied. They are modular, so a good fuel cell design could be added or reduced, depending on the power profile needed for a given application – transportation vehicle or other.

Any leaks or changes in flow rate of H2 in the system would shut down the operation of fuel cells, so the battery system or a secondary fuel cell stack would provide the reliability for service. There are sensors that would be placed near the fuel cells (from automobile fuel cell experience) and the tanks, so that leaks detected would disrupt the supply right away to contain the risk. Additional information on safety is provided in Appendix B.

34 The Maritime Executive (MarEx). 2017. World's First Hydrogen-Powered Cruise Ship Scheduled. October 2. Accessed October 2017. http://maritime-executive.com/article//worlds-first-hydrogen-powered-cruise-ship-scheduled. At 62 400 kW rated capacity, peak hydrogen consumption will be over 3.5 tonnes per hour.

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3.2.9 Vehicle Power Management – Battery Technology Beside the fuel cells, power-intensive applications, such as trains, buses, and trucks, use a hybrid propulsion system, where a battery system delivers the peak power required when leaving the platform and also regeneratively captures power from the brakes while decelerating. 3.2.9.1 Design and Functionality For vehicle propulsion, battery weight is a crucial consideration, so battery development explored the use of the lightest metal, lithium, with cells powered by movement of lithium ions. The key breakthroughs with this technology occurred in 1979 with use of lithium cobalt oxide (LiCoO2) as the source of lithium ions for the charging phase; and in 1980, of porous carbon as the repository for these ions. 35 Rapid development since then has firmly established lithium ion batteries (LIBs) in many markets and as the technology for applications in electric transportation. As annual production of LIBs moved into billions, the price has fallen sharply, even as the technology has improved rapidly both in volume and weight charge density. LIBs are the accepted choice for batteries over a wide range of applications, including stand-alone and hybrid vehicle systems. A detailed description of LIB technology is beyond the capacity of this review but it is an area of intense development. There are at least six major categories of LIBs distinguished by the composition of cathodes36:

1. Lithium Cobalt Oxide (LCO), LiCoO2

2. Lithium Manganese Oxide (LMO), LiMn2O4

3. Lithium Nickel Manganese Cobalt Oxide (NMC), LiNixMnyCo1-x-yO2

4. Lithium Nickel Cobalt Aluminum Oxide (NCA), LiNi0.8Co0.15Al0.05O2

5. Lithium Iron Phosphate (LFP), LiFePO4 (LFP) 6. Lithium Titanate: Li4Ti5O12 (LTO) NMC types are the fastest growing category37, excelling in energy content, power, cycle life and thermal stability according to Blomgren. Even within the NMC category, there is diversity of cathode design. Elsewhere in LIBs, competing designs of anode (basically carbon, but with many morphologies) and electrolyte (an organic carbonate such as dimethyl carbonate [CH3O]) continue to be subject to intense research. With worldwide demand projected by Pillot to grow by a factor of over 2.5 between 2017 and 2025, developments will continue to drive down price, improve capacity and stability even as prices are projected to continue to fall on a weight basis. Blomgren quotes current prices for LIBs as low as US$190 per kWh and the objective of BEV car makers at $125 US/kWh. A comparison of six aspects of these six Li-ion battery types is provided on Figure 3-11. These aspects are: specific energy; specific power; safety; performance; lifespan; and cost.

35 BASF We create chemistry. 2017. “Beating the Battery Barrier.” New Scientist. Issue 3144. September 23. Accessed November 2017. https://www.newscientist.com/article/mg23531440-100-beating-the-battery-barrier/. 36 Blomgren, G.E., “The Development and Future of Lithium Ion Batteries”, J. Electrochem. Soc., 164 (1), pp A5019-A5025, 2017. Available at: http://jes.ecsdl.org/content/164/1/A5019.full 37 Pillot C., “The Rechargeable Battery Market and Main Trends 2014-2025”, 32nd International Battery Seminar and Exhibit, 3/9/2015. Available at: http://www.avicenne.com/pdf/Fort_Lauderdale_Tutorial_C_Pillot_March2015.pdf

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FIGURE 3-11 COMPARISON OF SIX TYPES OF LI-ION BATTERIES38

(a) Lithium Cobalt Oxide (b) Lithium Manganese Oxide

(e) Lithium Nickel Cobalt Aluminum Oxide (f) Lithium Titanate

From the comparison on Figure 3-11, the lithium titanate battery (f) provides the best performance and safety while being the most expensive of the li-ion batteries. Ultracapacitors (also known as supercapacitors) can also be deployed alongside batteries as a tribrid. Their main attraction is their high rates of charge and discharge. They do not depend on chemical reaction but on physical storage of electrons. While an order of magnitude more resistant to capacity

38 Types of Batteries, Battery University. Available at: http://batteryuniversity.com/learn/article/types_of_lithium_ion

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT loss with cycling than existing LIBs, they do experience a slow loss. Like batteries, ultracapacitor lifetime is extended if it is never charged to full voltage and kept cool (less than 40°C)39. 3.2.9.2 Reliability, Maintainability and Safety All batteries gradually lose capacity with cycling, a major constraint on their deployment in heavy-duty applications. The opportunity for improvement is huge, and there has been dramatic progress. In November 2016, Yasunaga, a Japanese battery manufacturer claimed that they had developed a special positive electrode surface treatment which would allow the battery to have more than twelve times the cycle life of conventional lithium-ion batteries. Batteries were tested to 60,000 to 102,400 cycles before falling to 70 percent of the original new capacity, compared to the conventional battery that would only do 5,000 to 6,000 cycles. 40 Lifetime extension over cycles is immensely important to our Hydrail application because the battery is capturing power whenever the train stops, and releasing that power to provide acceleration boost whenever it restarts. So, while a BEV might reasonably operate for a day on one or two charges, a Hydrail commuter train could experience perhaps 100 battery charge-discharge cycles per day. To sum up, the current situation is that for almost all fuel-cell vehicle applications, fuel cells deployed as a hybrid combination with LIBs can already accommodate loss of battery capacity with time. While formidable difficulties exist in the application of battery technology alone due to the exacting conditions of commuter or freight rail—all of weight, bulk, charge rate, and cost, separately—battery technology is evolving rapidly. Yasunaga’s technology is just one example with considerable potential to enhance fuel cell hybrids, including Hydrail, by simplifying their design and reducing the frequency for battery replacement. Continuing improvement can be anticipated. The early deployment of LIBs had problems, notably two well-publicized incidents with LIBs catching fire occurred on a Boeing 787 aircraft, an early instance of LIB use in heavier duties. The U.S. National Transport Safety Board concluded that a manufacturing defect in a single cell had led to its short- circuiting, leading to a thermal runaway as overheating spread to neighbouring cells41. The resolution in response to these incidents has been to ensure adequate separation of individual cells to ensure sufficient cooling and avoid a cascade of cells failing. Two newer applications of LIBs in e-cigarettes and in hover boards have led to small fires and some injuries. A U.S. Federal Emergency Management Agency (FEMA) review42 of these incidents concluded that their use in e-cigarettes was inappropriate. Notwithstanding design overreach in miniaturizing Samsung’s Galaxy 7 phone, with proper design LIBs are now deployed without problems in billions of devices ranging in scale from phones to massive stationary electricity storage banks. Additional information on safety is provided in Appendix B.

39 Stack Exchange Inc. 2017. "How durable is a supercapacitor." Electrical Engineering. Accessed October 2017. https://electronics.stackexchange.com/questions/26366/how-durable-is-a-supercapacitor 40 http://www.fine-yasunaga.co.jp/english/ir/pdf/news/press20161122english.pdf 41 National Transportation Safety Board. 2014. Auxiliary Power Unit Battery Fire Japan Airlines Boeing 787-8, JA829J. AIR-14-01. November 21. Accessed October 2017. https://www.ntsb.gov/investigations/AccidentReports/Pages/AIR1401.aspx 42 FEMA, “Electronic Cigarette Fires and Explosions in the United States 2009 - 2016 July 2017”, https://www.usfa.fema.gov/downloads/pdf/publications/electronic_cigarettes.pdf

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3.2.10 Vehicle Hydrogen Management – Storage Tanks The hydrogen storage tanks onboard mobile vehicles are specially designed to be used for onboard fuelling of fuel cell systems. The current design standards are derived from other modes of transport such as buses which are adapted in Coradia iLint where 35 MPa tanks typically used in buses were used for light-rail application. 3.2.10.1 Design and Functionality As discussed earlier in Section 3.2.5, hydrogen could be stored in either gaseous form or in liquid form. However, the fuel cells onboard the rail vehicle can only operate using gaseous hydrogen, so when storing liquid hydrogen onboard, a high-pressure gaseous buffer tank needs to be included. There is usually only one large liquid hydrogen tank that would be used onboard with additional equipment to convert liquid to gaseous hydrogen. If high-pressure or CGH2 is chosen for storage onboard, then Type IV tanks at 70 MPa (as shown in Figure 3-12) are the current commercial option available. This would help conserve space onboard to provide the required range of revenue service per day without a refill during the daytime (or during regular service).

FIGURE 3-12 HIGH-PRESSURE TYPE IV HYDROGEN STORAGE TANKS USED IN CARS43

The storage tanks onboard the rail vehicle would be similar to that shown in Figure 3-12 for cars, smaller and more in numbers to accommodate the high-pressure required and to make use of any available space onboard the vehicle. The electrical connection indicated in Figure 3-12 is for controlling the valves and pressure regulators and enable power to the sensors. These would also be different for the rail vehicle, as there would be more tanks, so there would be an array of sensors, valves, and regulators to be monitored and controlled.

43 HySafe (Safety of Hydrogen as an Energy Carrier) website. Available at: http://www.hysafe.net/wiki/uploads/BRHS/Ch_2_11_Fig5_V1.jpg

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3.2.10.2 Reliability, Maintainability and Safety The RAMS for onboard storage tanks are more significant than the storage solutions for the fixed infrastructure of the Hydrail System. As these tanks are travelling with passengers across an urban area. Although no RAMS is available for such tanks on a rail application with passengers, there is enough experience for onboard storage tanks from buses and in private vehicles such as cars. By design, once these tanks are mounted into the vehicle as per codes and standards, there are no moving parts except for the valves and regulators which have been proven in the field for RAMS. The tanks would hold pressure up to 5,000 refills44 before it needs replacing. If each tank is filled only once a day, then this translates to about 13.5 years of lifetime. The tank structure and the carbon fibre- reinforced plastic winding method45 used to make these tanks have reliability over long-periods of time and operate safely. In terms of operational RAMS on vehicles with similar tanks, there are two examples cited here for support. One is that more than one Toyota Mirai – the fuel cell powered car with tanks similar to the one being considered for the Hydrail vehicles, has been successfully used by a taxi company in London, England by operating without any issues (or fault-free service) for 50,000 miles46. The other one is from the fuel cell powered bus operators in the US. The charts in Figure 3-13 shows the reasons for unavailability of fuel cell powered buses from four transit agencies in the US.

FIGURE 3-13 REASONS FOR UNAVAILABILITY OF FUEL CELL-ELECTRIC BUSES47

44 Hexagon Composites, email dated 2017 September 26, from Jorn Helge Dahl. 45 T. Yoshida and K. Kojima. Toyota Mirai Fuel Cell Vehicle and Progress Toward a Future Hydrogen Society. Available at: https://www.electrochem.org/dl/interface/sum/sum15/sum15_p45_49.pdf 46 Available at: https://www.fleetnews.co.uk/news/fleet-industry-news/2017/11/15/toyota-mirai-hydrogen-fuel-cell-car-reaches-50-000- miles-with-green-tomato-cars 47 L. Eudy and M. Post. Fuel Cell Buses in U.S. Transit Fleets: Current Status 2017. NREL/TP-5400-70075, November 2017.

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Except for OCTA AFCB in Figure 3-13, the other transit agencies had very minimal impact from the hydrogen propulsion system. From the same literature, none of this unavailability was reported due to storage tanks onboard these buses. The safety aspects of these tanks are very similar to any pressure vessels or tanks being used to store hydrogen as discussed earlier in Section 3.2.7. The fatigue acceleration that could potentially arise from the vibration that occurs onboard the rail vehicle should be addressed through engineered damping. For gaseous tanks, leaks from rupture of tanks through mechanical force or piercing during an accident or regular maintenance is possible. These are easily identifiable from sensors and the tanks could be isolated for replacement. The Type IV tanks have undergone enormous testing and safety regulations that addresses things like fire, explosion and other hazards near these tanks, which are very well summarized elsewhere48. For liquid hydrogen tanks, loss of cryo-insulation could result in sudden boil-off of hydrogen which would be vented through the pressure relief valves included in the tank design. Additional information on safety is provided in Appendix B. 3.2.11 Potential Competing Technologies 3.2.11.1 Power exclusively from batteries Battery technology is an area of intense research and development with DOE targeting a price of $125/kWh for 202049 and GM projecting $100/kWh by 2021. When comparing the cost of fuel cells and batteries, note the difference in units (kW versus kWh). Further note that, while a fuel cell can deliver its rated power, an LIB battery must operate over at most 15-25 percent of its nominal capacity if it is to avoid excessive reduction in lifetime. Effectively, this at least quadruples the size and cost of batteries. Consider the case of train that would consume 500 kg/d of hydrogen using fuel cells. At 50 percent efficiency for the fuel cells, it will deliver 8.5 MWh from 700 kW of fuel cells. Cost of fuel cells at 1000 $/kW would be $700,000. The battery equivalent, using 25 percent of its nominal capacity and $100/kWh, is $3 400 000. This is using projected costs for batteries and pessimistic costs for fuel cells. If one uses projected future costs for fuel cells, the fuel cell cost could drop well below $100,000. The weight of LIBs is another consideration. Using a reasonable 200 Wh/kg for LIB weight, the weight of batteries for this typical example would be 170 tonnes, an additional 20 percent weight to the total (860 tonnes) of an entire fuel-cell powered train. and allowing 50 percent efficiency for conversion of hydrogen into electricity in a PEM cell, (High-pressure carbon-fibre-reinforced tanks have one-quarter of the weight50 of batteries containing the same electrical capacity or one-sixteenth of the batteries’ effective electrical capacity.) Particularly since fuel cell technology is still also in a phase of technological improvement, one would conclude that the superiority of Hydrail is under no obvious threat from battery technology. Indeed, when one compares the economics of hydrogen-burning fuel cells using electrolytic hydrogen with those of batteries, it becomes clear why so many of the automobile companies are marketing fuel-cell powered light vehicles. If hydrogen-fuelling was anywhere close to being as widely availability as electricity, hydrogen-burning fuel cells would likely be pre-eminent for all vehicles. Of course, this is

48 S. Tretsiakova-McNally and D. Makarov. Lecture on Safety of hydrogen storage. Available at: http://www.hyresponse.eu/files/Lectures/Safety_of_hydrogen_storage_notes.pdf

49 https://energy.gov/sites/prod/files/2016/06/f32/es000_howell_2016_o_web.pdf

50 https://www1.eere.energy.gov/hydrogenandfuelcells/pdfs/mfg2011_plenary_leavitt.pdf

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT not an issue for Hydrail where providing fuelling points for RER’s Hydrail is merely a small part of the system design. 3.2.11.2 Continuous Power from Alternatives to Catenaries In 2011, several leading rail manufacturers were developing such systems51. Ansaldo has its TramWave System with a buried version of overhead catenaries using a segmented ferromagnetic belt in a conduit that becomes “live” only in the presence of the rail vehicle. Alstom’s APS system is similar. Both of these systems are designed for trams and have problems with snow and ice—as traditional catenary systems do. Bombardier’s Primove System claims to avoid the problem of snow and ice with a contactless approach using inductive coupling. All of these are for light-rail application and currently in the prototype demonstration phase. Primove-powered buses have, however, passed 500 000 km of service operation in five European cities52. Alstom’s APS trams have amassed over 20 million kilometres in five French cities53. A recent thesis study by Thomas Navadi54 concludes that inductive transfer of electricity to a moving vehicle was 60 to 70 percent more expensive than systems with catenaries and only 35 percent energy efficient. While a rail system would probably have more efficient transfer—since non-alignment between the power source and the collector is considered by Navadi to be a large part of road vehicles’ inefficiency, efficiency of energy use is an important consideration given that these technologies do not time-shift electricity demand. Navadi’s estimate of high capital cost is currently another major disadvantage of these non-catenary systems. They have not been applied to heavy- duty applications. 3.2.11.3 Power from Batteries with Frequent Recharge Recognition of the limitations of batteries for extended operation has led to research on ways to recharge batteries rapidly while a vehicle is briefly stopped or even while it is moving. The ways that this could be accomplished are the same as those used to transfer power continuously with the systems described in the previous section. Introducing batteries seems an unnecessary complication that would add weight, have limited battery life, and have to deal with heat dissipation during rapid charging of a battery pack.

51 http://www.masstransitmag.com/article/10262406/the-future-is-here-catenary-less-power-for-light-rail, 2011

52 http://primove.bombardier.com/media/news/news-detail-page/article/2017/01/18/348.html

53 http://www.alstom.com/products-services/product-catalogue/rail-systems/Infrastructures/products/aps-ground-level-power-supply/

54 Navadi, T., “Analysis of Wireless and Catenary Power Transfer Systems for Electric Vehicle Range Extension on Rural Highways”, University of Illinois at Urbana-Champaign, 2016 May, https://www.ideals.illinois.edu/bitstream/handle/2142/91554/ECE499-Sp2016- navidi.pdf?sequence=2

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3.3 Where Hydrogen Can be Used 3.3.1 Overview There are various applications for hydrogen beyond massive industrial consumption, some of which are summarized on Figure 3-14 The market maturity of these applications is indicated in three different colours on the figure, as Demonstration, Commercialization, and Established, based on our literature review.

FIGURE 3-14 HYDROGEN APPLICATIONS IN FOUR PREVALENT MARKET AREAS

At a gathering pace over the last century, hydrogen has been used for numerous industrial applications: in petroleum refining, to produce ammonia fertilizers; in steel making to do what; and many others. For refining in the petroleum industry, it is used to remove sulphur and nitrogen from crude feedstocks; it is also used to produce more volatile products, such as gasoline and kerosene by direct addition (hydrofining) and breaking of molecules (hydrocracking). Hydrogen is increasingly used in place of coal or coke to remove the oxygen from iron ore and provide a passive atmosphere during steel making.

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These large-scale industrial uses have established hydrogen as a bulk commodity. Now new applications are emerging, mainly in stationary applications but, increasingly, in transportation. 3.3.1.1 Grid Stabilization and Energy Storage Today, hydrogen electrolyzers and fuel cells provide grid stabilization and energy storage services in many countries, especially in Europe. While hydrogen technologies are currently deployed for only about 1 percent of the energy storage services55 compared with other bulk and seasonal storage technologies, its importance is expected to grow by using long-term storage in underground caverns in the same way that natural gas is currently stockpiled to meet the demands of winter usage. In addition, Toronto Hydro is currently testing a compressed gas scheme using the pressure of water to contain the pressure of air in bladders underwater off Toronto Island.56 3.3.1.2 Backup Power Use of HFCs for backup power or for regular power has become a norm to support telecommunication towers spread across the country in various nations, including Canada, the United States (U.S.), and others. Countries like Japan have been using fuel cells as backup power for homes and residential buildings, as fuel cells provide the benefit of CHP. The deployment of fuel cells for backup power has been growing with help from large organizations investing in the technology. This includes the U.S. Federal Government, through American Recovery and Reinvestment Act (ARRA) funding, which saw growth from 2009 to 2012, as shown on Figure 3-15.

55 Sandia Corporation. 2017. DOE Global Energy Storage Database. Office of Electricity Delivery & Energy Reliability. Accessed October 2016. https://www.energystorageexchange.org/projects 56 Toronto Hydro. 2017. "Toronto Hydro is testing the world’s first underwater compressed air energy storage project in Lake Ontario, near Toronto Island." Underwater Energy Storage. Accessed November 2017. https://www.torontohydro.com/sites/electricsystem/gridinvestment/powerup/pages/compressedairenergystorageproject.aspx

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FIGURE 3-15 FUEL CELL ADAPTATION IN THE UNITED STATES57 FOR BACKUP POWER AND FORKLIFT APPLICATIONS

3.3.1.3 Automotive Vehicles The Toyota Mirai is a proton-exchange membrane (PEM) fuel-cell-powered vehicle already commercially available. It uses two carbon-fibre-reinforced composite tanks operating at 700 bar for a range of approximately 550 kilometres (km). It takes 3 minutes to fill the tank. Like Toyota’s Prius model, the Mirai uses the same nickel-metal-hydride (NiMH) battery for its hybridization, recapturing braking energy and augmenting the fuel cell stack’s power output during acceleration. Maximum fuel cell stack output is 114 kilowatts (kW). Toyota noted that their FCV development started in 1992, with the fuel cell hybrid vehicle (FCHV), which was first leased in 2002. Subsequently, three big technical issues were addressed over several years: 1. The cruising range was increased to more than 500 km from 5 kilograms (kg) of hydrogen storage. 2. Cold start was demonstrated in a field test at Yellowknife, Northwest Territories (NWT) to −30 °C. 3. Refuelling time was lowered to about 3 minutes. In addition, fuel stack density was increased from 1.4 kilowatts per litre (kW/L) in 2008 to 3.1 kW/L in 2017. Toyota continues with further developments of the fuel cell to lower cost; notably, by reducing the platinum loading at both cathode and anode. Some of the deployment numbers are provided in Table 3-2 for cars and other vehicle types.

57 U.S. Department of Energy (DOE).2014. FY 2013 Annual Progress Report. DOE Hydrogen and Fuel Cells Program. Jennifer Kurtz (Primary Contact), Sam Sprik, Todd Ramsden, Genevieve Saur, Chris Ainscough, Matt Post, and Mike Peters, authors. National Renewable Energy Laboratory. September. Accessed October 2017. http://nreldev.nrel.gov/hydrogen/cfm/pdfs/2013_apr_forklift_and_backup_power.pdf

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TABLE 3-2 HYDROGEN TRANSPORT VEHICLES INVENTORY Vehicles World58 U.S.59 Active Vehicles 1,260 1,295 Passenger Vehicle Total 918 1,266 Toyota Mirai 406 991 Hyundai ix35 Tucson FCEV 325 132 Mercedes-Benz B-Class F-Cell 100 47 Toyota Highlander FCHV-adv 0 62 Honda FCX Clarity 0 17 Other 87 17 Scooters 101 0 Buses and shuttle buses 110 28 Light commercial vehicles 38 0 Other or unknown vehicle types 93 1 Planned Vehicles in 2017 899 102 Total Vehicles by the End of 2017 2,159 1,397

Initially only in Japan, in 2017, Toyota launched a fuel-cell-powered bus adapting the Mirai architecture with 2 of the Mirai’s fuel cell stacks and 10 of its hydrogen tanks, which provide considerable range. Indicating a significant commitment to fostering HFC development, Toyota is offering royalty-free use of their related suite of patents until the end of 2020. Both the Honda fuel-cell-powered Clarity and Hyundai’s fuel-cell-powered Tucson are only available in Southern California, where there are enough hydrogen fuelling stations. Their specifications are broadly comparable to Toyota’s Mirai. Fuel cells for vehicle propulsion on road vehicles, such as cars and sports utility vehicles (SUVs), are growing rapidly in recent years, as indicated on Figure 3-16.

58 Pacific Northwest National Laboratory (PNNL) and U.S. Department of Energy (DOE). 2016a. International Hydrogen Vehicles. Spreadsheet data. Accessed October 2017. http://hydrogen.pnl.gov/sites/default/files/data/International_Hydrogen_Fueled_Vehicles_8.xlsx. 59 Pacific Northwest National Laboratory (PNNL) and U.S. Department of Energy (DOE). 2016b. U.S. Hydrogen Vehicles. Spreadsheet data. Accessed October 2017. http://hydrogen.pnl.gov/sites/default/files/data/US_Hydrogen-Fueled Vehicles_6.xlsx.

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FIGURE 3-16 PEM FUEL CELL CONSUMER VEHICLES SOLD60 IN THE LAST 6 YEARS

3.3.1.4 Material Handling Vehicles In Balzac, Alberta, Walmart’s new perishable distribution centre relies entirely on PEM-fuel-cell- powered forklifts and palette trucks61. Walmart chose this technology after 18,000 hours of field testing. Amazon is spending US$70 million to replace its forklift batteries in 11 warehouses with HFCs62. In contrast to batteries of any type, the fuel cells in this near continuous application are expected to operate for 10 years. This is a new enough application that the PEM fuel cell lifetime is a projection. Nonetheless, the projection is an indication of confidence in the lifetime of PEM fuel cells that manufacturers can now deliver; after their design life, they can be rebuilt. Some applications require operation at low temperatures, and Walmart’s test operations were unimpaired down to -29°C. The shipping industry (cargo ships, primarily) already uses fuel cells in various services63, including propulsion, onboard power generation, and CHP. This highlights the scaling and duty flexibility of various fuel cell types, including PEM fuel cells.

60 The International Council on Clean Transportation (ICCT). 2017. Developing hydrogen fueling infrastructure for fuel cell vehicles: A status update. Briefing prepared by Aaron Isenstadt and Nic Lutsey. October. Accessed October 2017. http://theicct.org/sites/default/files/publications/Hydrogen-infrastructure-status-update_ICCT-briefing_04102017_vF.pdf 61 Canadian Hydrogen and Fuel Cell Association (CHFCA). 2016. Case Study - Walmart Canada Fuel Cell Forklift Fleet. Accessed October 2017. http://www.chfca.ca/say-h2i/materials-handling/walmart-canada-fuel-cell-forklift-fleet 62 ars Technica. 2017. Amazon will replace some of its battery forklifts with hydrogen fuel cell ones. Conde Nast. April 5. Accessed October 2017. https://arstechnica.com/information-technology/2017/04/amazon-will-replace-some-of-its-electric-forklifts-with-hydrogen-fuel-cell- ones/ 63 DNV GL - Maritime. 2017. Study on the Use of Fuel Cells in Shipping. EMSA European Maritime Safety Agency. Tomas Tronstad, Hanne Høgmoen Åstrand, Gerd Petra Haugom, and Lars Langfeldt, authors. Version 0.1. January. Accessed October 2017. www.emsa.europa.eu/emsa-documents/latest/download/4545/2921/23.html

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3.3.1.5 Public Transit The public transit deployments of hydrogen-powered vehicles have begun through HFC-powered buses, mostly. There are about 150 buses currently in operation around the world (as shown in Table 3-2), and hundreds of buses are planned to be introduced by various transit companies in the next few years as part of the decarbonization targets set by the governments in countries such as China and members of the European Union (EU) to meet their commitments to the Paris Agreement of the United Nations (UN) Framework Convention on Climate Change, Article 4.1964. For buses, Ballard’s fuel cells have now passed 25,000 hours of operation without significant maintenance in a small fleet of vehicles being operated by Transport for London in the United Kingdom (UK). Deployed in 15 countries in the past 10 years, Ballard claims a cumulative 11 million km of operation in revenue service in a wide range of climatic conditions and duty cycles65. The pace of deployment of fuel-cell-powered buses is accelerating rapidly. Bloomberg reported66 that in September 2016, Ballard began delivering the first of 330 fuel cell buses to two cities in Guangdong province, Yunfu and Foshan. That order alone will quadruple the global fleet of hydrogen-powered buses. Most recently, on June 8, 2017, Hydrogenics signed a Purchase and License Agreement with Blue-G New Energy Science and Technology Corporation for 1,000 fuel cell bus power modules67—presumably for 500 buses. 3.3.1.6 Fuel Cell and Hydrogen Joint Undertaking (European Union) The Fuel Cell and Hydrogen Joint Undertaking (FCHJU) is a substantial organization launched in 2014 under the EU’s 6th Framework Programme for Research and continued under the EU Horizon 2020 Framework. The partners are committed to supporting the program until at least 2024. It is led by companies representing the entire supply chain for fuel cell and hydrogen energy technologies. The three members of the FCHJU are the European Commission, fuel cell and hydrogen industries represented by Hydrogen Europe, and the research community represented by Hydrogen Europe Research. To quote from their website68: “This is a unique public private partnership supporting research, technological development and demonstration (RTD) activities in fuel cell and hydrogen energy technologies in Europe. Its aim is to accelerate the market introduction of these technologies, realising their potential as an instrument in achieving a carbon-lean energy system.”

64 United Nations Framework Convention on Climate Change. 2017. The Paris Agreement. October 12. Accessed November 2017. http://unfccc.int/paris_agreement/items/9485.php 65 Ballard Power Systems (Ballard). 2017. "Ballard Powered Fuel Cell Electric Bus Achieves 25,000 Hours of Revenue Operation." Newsroom. August. Accessed October 2017. http://ballard.com/about-ballard/newsroom/news-releases/2017/08/29/ballard-powered-fuel- cell-electric-bus-achieves-25-000-hours-of-revenue-operation 66 Bloomberg L.P. 2017. China's Buses Bolster Ballard's Three-Decade Quest for Hydrogen. Natalie Obiko Pearson, author. March 26. Accessed October 2017. https://www.bloomberg.com/news/articles/2017-03-26/china-s-buses-bolster-ballard-s-three-decade-quest-for- hydrogen 67 Hydrogenics. 2017b. "Hydrogenics Signs Purchase and License Agreement valued at over 50M USD for 1,000 Fuel Cell Bus Power Modules." News & Updates. June 8. Accessed November 2017. http://www.hydrogenics.com/2017/06/08/hydrogenics-signs-purchase-and- license-agreement-valued-at-over-50m-usd-for-1000-fuel-cell-bus-power-modules/

68 Fuel Cell and Hydrogen Joint Undertaking (FCHJU). 2017. Who We Are. Accessed October 2017. http://www.fch.europa.eu/page/who- we-are.

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Its stated objective is to: “Overcoming barriers to deployment: There are still many technical and non-technical barriers to overcome before fuel cell and hydrogen technology is widely commercially available. A concentrated effort of all players is necessary, because the research needed to develop the technologies is often so complex that no single company or public research institution can perform it alone. Funding contributed by the partners has ranged upward of €600,000 in each of the six-year Framework periods and is currently over €200,00 per year.” The FCHJU appreciates the case for deployment of hydrogen and fuel cells: “Fuel cells, as an efficient conversion technology, and hydrogen, as a clean energy carrier, have a great potential to contribute to addressing energy challenges facing Europe. They will allow renewable energy technology to be applied to transport, facilitate distributed power generation, and help Europe cope with the intermittent character of renewables such as wind power.” They also appreciate the need for support of ongoing development and for building hydrogen supply infrastructure ahead of the demand that can only appear when fuelling is widely available. With its massive combination of the funding of private industry backed by large, multiyear government contributions from across the EU, substantial improvements in HFC technology will continue to unfold, lowering the technology’s capital costs and, to a lesser degree, its operating costs. 3.3.2 Case Studies 3.3.2.1 BC Transit (Whistler, British Columbia) BC Transit operated a 20-vehicle fleet of fuel-cell-powered buses for transit in the skiing and tourist community of Whistler for 36 months between 2010 and 2013. The buses used Ballard’s PEM fuel cells and were hybridized with lithium phosphate batteries69. The concept was to showcase fuel cell technology for the 2010 Winter Olympics. The buses were well-accepted by the public, drivers, maintainers, and the local community. The project was delivered on-time and on-budget. The buses travelled more than 4 million km over their 4 years of operation, operating up to 22 hours per day in temperatures ranging from -20 to +34.7°C. Over 590 tonnes of hydrogen were dispensed in over 23,000 fills without any safety incidents. An average of 15.7 kg of hydrogen was used for each 100 km of travel, displacing 52.5 litres (L) of diesel fuel, and avoiding emissions of almost 6,000 tonnes of CO2. There were no intrinsic problems with the fuel cells, and all but two of the 22 fuel cell power packs exceeded 8,000 hours of operation. Now, this was something of a pioneering deployment of fuel cells to power buses, and it proved to be an excellent learning opportunity, which was carefully analyzed by the U.S. National Renewable Energy Laboratory (NREL) for the Californian Air Resources Board70. This showed the need for well- directed integration of the various components (for example, integrating the fuel cell with its compressed air supply, or adapting the suspension to a different distribution of weights). With the

69 Lithium phosphate batteries belong to the LIB family. They use lithium iron phosphate (LiFePO4) instead of the more usual lithium cobalt oxide (LiCoO2) as the cathode material. LiPO4 gives longer life and faster charge and discharge rates, but a somewhat lower energy density than LiCoO2. 70 Eudy, L., and M. Post, M. 2014. BC Transit Fuel Cell Bus Project Evaluation Results: Second Report. Technical Report NREL/TP-5400-62317. National Renewable Energy Laboratory. September.

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT wisdom of hindsight, it became clear that staff should have advanced training for different types of maintenance, and that distinctively different spare parts needed to be stocked. 3.3.2.2 Independent Electricity System Operator Power-to-Gas (Markham, Ontario) Until about the middle of the 20th Century, “town gas” for heating was usually generated from coal. Town gas was a mixture of about equal quantities of hydrogen and carbon monoxide (CO). It had the serious disadvantage of CO’s toxicity and has, today, almost completely been displaced by natural gas. However, hydrogen—the other component of town gas—is not toxic and is poised to re-enter the gas- for-heat application. In the middle of 2015, the IESO procured a 2-megawatt (MW) power-to-gas (PtG) project to demonstrate the ability of hydrogen to provide grid services in Ontario71. The selected respondents (Hydrogenics and Enbridge Gas) will produce hydrogen from the 2 MW of electricity from the grid using the water electrolysis technology and then inject the gas into the natural gas pipeline owned and operated by Enbridge Gas. The PtG facility located north of Toronto will start operating in the next few months, providing the expected benefits to the grid by converting surplus electricity. 3.3.2.3 Canadian Tire Warehouse (Brampton, Ontario) Forklifts are early adopters of fuel cell technology. Using internal combustion engines to power vehicles in large, enclosed, populated spaces presents the challenge of providing adequate ventilation. Very large, modern distribution centres rely on extensive use of forklifts, and Canadian Tire Corporation (CTC) was a leader in turning to HFC to power their forklift fleet in their Brampton warehouse. The traditional approach for forklifts has been to use a battery-electric drive using lead-acid batteries. These have four disadvantages: 1. Recharging the batteries is slow, so the system relies on change-out at a recharge station. This is slow and cumbersome. 2. Lead-acid batteries deliver a declining voltage as their charge level falls. This leads to a trend of noticeably slowing performance during a shift. 3. The batteries are heavy. 4. Batteries need to be replaced every 2 to 3 years. Rather than moving to newer types of batteries, the emerging consensus is to turn to HFCs. For their Brampton, Ontario centre, CTC uses onsite alkaline fuel cells to produce their hydrogen with grid electricity. The hydrogen then used in PEM fuel cells on the forklifts. The major advantages of the system are fast refuelling and higher asset utilization. The implementation of HFC forklifts at Brampton has been so successful that CTC is now equipping a new distribution centre in Bolton, Ontario with them. 3.3.2.4 Walmart Canada Fuel Cell Forklift Fleet Walmart’s entire fleet of material handling equipment (MHE) at the Walmart Perishable Distribution Centre (PDC) in Alberta is now powered by HFCs72. Walmart decided to incorporate HFC forklifts and palette trucks in the PDC facility after the successful 4-month trial of fuel cell forklifts at two distribution

71 Independent Electricity System Operator (IESO). 2016c. IESO Report: Energy Storage. March. Accessed October 2017. http://www.ieso.ca/-/media/files/ieso/document-library/energy-storage/ieso-energy-storage-report_march-2016.pdf 72 Canadian Hydrogen and Fuel Cell Association (CHFCA). 2016. Case Study - Walmart Canada Fuel Cell Forklift Fleet. Accessed October 2017. http://www.chfca.ca/say-h2i/materials-handling/walmart-canada-fuel-cell-forklift-fleet.

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT centres. This trial achieved a 3.5 percent increase in productivity over comparable battery-powered forklifts. The forklifts are using hydrogen produced by Air Liquide from 98 percent hydro power, and fuel cells from Ballard. The Canadian Hydrogen and Fuel Cell Association predicted that this technology is delivering a $2 million reduction in operating costs (projected over a 7-year period) and contributing to a reduction of 530 tonnes of CO2 per year. 3.3.2.5 Raglan Mine Energy Storage (Nunavik, Québec) Glencore’s Raglan Mine is located in the extreme northern part of Québec in the Nunavik region. As well as being an exceptionally low-cost producer of nickel, the mine coproduces copper and cobalt, and some precious metals. The reserve will support indefinite operation. Because of its remote, harsh, far-northern location, the mine is aiming for as much self-sufficiency as possible. One approach they have adopted is to harness wind energy, an abundant but unpredictable resource. Tugliq Energy Company was engaged to build and operate a system based on a 3-MW wind turbine to provide primary production of electricity, and then convert that to hydrogen by electrolysis. The 200-kW PEM fuel cell assembly can supply up to 20 hours of the mine’s electrical load. Potentially, hydrogen could also be supplied to fuel underground mine vehicles. In 3 years of operation (since August 2014), Tugliq has avoided consumption of 6 million litres of diesel fuel. Even allowing for very good wind availability in the Arctic, this is indicative of the system achieving a high-capacity factor over what is a comparatively short operating lifetime to date73. Unlike batteries, modern fuel cells are insensitive to low-temperature operation: Hydrogenics first- ever fuel cell was deployed in Antarctica. So, while a BEV struggles to meet the heating demands of even southern Canada in winter, the integrated system at Raglan with its fuel cell stack easily accommodates winter temperatures that average around -20°C for 4 months of the year and delivered 97.8 percent availability in its first 20 months of operation, including two winters. Having demonstrated reliability and robustness to meet the risk profile of mining companies like Glencore, their experience as educated buyers and operators provides the assurance for applicability to community-sized deployments in remote areas of Canada’s North, as well as in less harsh environments. 3.3.2.6 Fuel Cells used in Maritime Applications In 2017, the U.S. Department of Energy’s (DOE’s) Fuel Cell Technologies Office in the Office of Energy Efficiency & Renewable Energy released a report74 detailing the results of a maritime fuel cell generator project. This project was intended to:  Demonstrate an HFC power generator for marine applications  Verify increased energy efficiency at part loads and reduced emissions  Identify areas requiring further research

73 Tugliq Energy Co, www.tugliq.com 74 Office of Energy Efficiency & Renewable Energy. 2017. DOE Shows Fuel Cells Used in Maritime Applications Can Increase Efficiency by 30 percent. Washington, D.C.: U.S. Department of Energy. July 21. Accessed October 2017. energy.gov/eere/fuelcells/articles/doe-shows-fuelcells-used-maritime-applications-can-increase-efficiency-30.

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 Analyze the business case  Address regulatory and other market barriers A 100-kW generator with 72 kg of hydrogen storage was designed and built by Hydrogenics, with safety and regulatory reviews by the Hydrogen Safety Panel, U.S. Coast Guard, and the American Bureau of Shipping. The project showed that it is possible to increase energy efficiency by up to 30 percent at part load, and reduce emissions to zero through the use of HFCs. In a 2016 review paper, van Briet et al.75 note that, because fuel cells are modular in nature and the intrinsic performance of a single cell is not different from a large stack, ships can benefit from distributing units throughout the ship without a penalty of increased fuel consumption, reducing electricity transport losses, and improving redundancy. Furthermore, fuel cell systems are noted for being well-suited to fluctuating shipboard demands, since they have good part load characteristics. Very recently, the luxury cruise line Viking announced that their next ocean-going ship will depend entirely on HFCs for its 62.4-MW power system. Unlike the system envisaged by van Briet et al., which would produce hydrogen onboard by reforming a liquid fuel, Viking intends to supply their ships with LH2. 3.3.2.7 Qingdao Light Rail Transit (Shandong Province, China) In 2015, Ballard signed a joint development and supply agreement to develop and commercialize a fuel cell engine specifically designed for integration into low floor trams manufactured by CRRC Qingdao Sifang Company, Ltd. (CRRC Sifang), a Chinese rolling stock manufacturer. The agreements included 2016 delivery of 10 customized FCvelocity modules, and the agreements have an initial value expected to be approximately $6 million. For this customer’s requirements, Ballard developed a new prototype configuration of their FCvelocity fuel cell module to deliver 200 kW of net power for use in powering trams in urban deployments. Ballard shipped five of these 200-kW modules to CRRC Sifang in 2017, and these will be used in the world’s first fully commercial service of fuel-cell-powered trams in Foshan starting in 2018. This hydrogen-powered tram will run in Foshan in southeastern China. A 17.4-km track will be built in two phases at 760 million yuan ($140.0 million) with 20 stations. Construction began in February 201776. This is an Asian first, as China will deliver new hydrogen light rail service in the region. A demonstration model of the trains was first rolled out in Qingdao in 2015. 3.3.2.8 Canadian Fuel-Cell Buses in China In 2015 June, Ballard received an order for fuel cell modules for 33 buses in the cities of Yunfu, (Guangdong) and Rugao (Jiangsu), and 3 months later, for another 300 buses. This has just been the beginning and Zhongshan and Broad-Ocean Motor Co., Ballard’s biggest shareholder, who are now building three factories in China to make fuel-cell modules for vehicles using Ballard technology. Hydrogenics is also active in China, with an order to supply 1,000 fuel cell units for buses to Blue-G. Beside being a potentially huge market, the Chinese commitment to reducing GHG emissions is reinforced by the need to reduce local air pollution. As with many other new technologies, one can

75 van Biert, L., M. Godjevac, K. Visser, and A. Purushothaman Vellayani. 2016 “A Review of Fuel Cell Systems for Maritime Applications.” Journal of Power Sources. 327, pp. 345-364. 76 Smartrailworld.com. 2017. An Asian first as China will deliver new hydrogen light rail service. March 12. Accessed October 2017. https://www.smartrailworld.com/an-asian-first-as-china-will-deliver-the-first-hydrogen-train

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT expect China to master fuel-cell-bus technology rapidly and then to deploy their experience on the export market. In choosing to partner with local companies, the technically advanced Canadian fuel- cell manufacturers appear to have recognized the value of this collaboration for entry to a major, global vehicle market. 3.3.2.9 Vattenfall Fuelling Station (Germany) In partnership with Shell, the Vattenfall electricity company has operated a fuelling station in Hamburg since 2012 to supply cars and buses with 350-bar hydrogen (subsequently augmented with 700-bar capability). Half of its hydrogen is produced onsite by electrolysis; the remainder is shipped in77. So far, the station’s customers are largely city buses. While car refuelling service is available, there has been little implementation in Germany so far. However, the experience in southern California shows that HFC car ownership expands rapidly after a reasonably dense network of fuelling points is available, and the German situation is about to change with H2 Mobility planning to open 400 stations there by 2023. 3.3.2.10 Alstom Coradia iLint (Lower Saxony, Germany) Germany’s first hydrogen-fuelled commuter train, with PEM cells from Hydrogenics, has been undergoing track trials since early in 2017 and will enter service before the end of the year. Alstom’s Coradia iLint is based on a diesel Coradia Lint antecedent, with the iLint replacing the diesel traction with fuel cell technology. It has a sustainable train performance, matching that of regular regional trains, running at 140 kilometres per hour (kph), with a 600 to 800 km per tankful autonomy, and accommodating up to 300 passengers. Like almost all fuel-cell-powered vehicles, it is a hybrid, using LIBs for regenerative braking and initial acceleration. Quoting from a New York Times story78, “…about 40 percent of Germany’s rail network is not electrified. And Alstom executives say that it would be cheaper to replace the diesel-powered trains with hydrogen vehicles than to string electric lines along the tracks. “Alstom says it has preliminary orders for 50 to 60 trains from German regional authorities. A commuter line like this one looks well-suited to hydrogen. The company can build a fuel supply system in a safe place like a rail yard of its choosing.”

77 Fuel Cell and Hydrogen (FCH). 2016. “Hamburg's Hydrogen Buses and New Refuelling Station.” Clean Hydrogen in European Cities Newsletter. January 13. Accessed October 2017. http://chic-project.eu/newsletters/draft-chic-newsletter-122011/infrastructure- development-draft-chic-newsletter-122011/hamburgs-hydrogen-buses-in-operation 78 Reed, Stanley. 2017. “Hamburg Is Ready to Fill Up With Hydrogen. Customers Aren’t So Sure.” Business Day. New York Times. July 4. Accessed October 2017. https://www.nytimes.com/2017/07/04/business/hydrogen-cars-trains-planes-hamburg.html

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4 Hydrail Assessment

The objective of Part 4 is to provide a holistic view of the Hydrail System and how it can be taken forward. The sections in this part provide insights into Hydrail’s:  Required system design  Operational requirements and capacity  Capital and operating costs  Environmental implications  Requirements in relation to regulations  Socio-economic implications  Public acceptability  Implementation readiness  Procurement strategy  Transition plan  Risks and opportunities that will need to be managed if the Hydrail System is implemented The sections also provide a comparison of the Hydrail System with conventional overhead electrification so that the reader can understand the comparative benefits and dis-benefits between the two systems. 4.1 Hydrail System Design Based on the above this section identifies the technology choices that are available for the configuration of the Hydrail System. It does this by assessing the hydrogen technology options identified in Part 3 to the required functionality of the Hydrail System at the level of its sub-systems. The output of this section are the parameters that are included in the Operational Simulation model described in section 4.2. The Hydrail System design entails the integration of various hydrogen component subsystems with various technologies that are existing in the market for both off-the-shelf purchase or as custom order items. The Hydrail System envisioned for the GO network would comprise the seven subsystems shown on Figure 4-1. It includes, from the GO service end: 1. Hydrogen vehicle 2. Hydrogen dispensing 3. Hydrogen refuelling 4. Hydrogen distribution 5. Hydrogen storage 6. Hydrogen production 7. Electricity supply

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The components that would form the integrated hydrogen rail system in Ontario are:

FIGURE 4-1 HYDRAIL SYSTEM COMPONENTS

With the Hydrail System the subsystems of the vehicle, dispensing, refuelling, distribution, and storage share common characteristics with the current diesel-based system. However, unlike diesel, the scope of the Hydrail System includes the process of fuel production. A benefit of this is that the fuel price should be less variable than diesel as it brings into the control of Metrolinx one of the market externalities that currently affects it. 4.1.1 Key Components Overview Each of the subsystems within Hydrail, from hydrogen production to dispensing, is modular, to meet the evolving requirements of GO rail corridor. For example, the hydrogen storage can be built to meet the initial needs of an enhanced RER service on a given corridor and could then be expanded as the train service on the corridor grows over the future years. In relation to the hydrogen production subsystem, there are two options for where these can be located: 1. At a distance from the GO network 2. Onsite: located fairly close to refuelling facilities The first option could be a single, central facility or several locations convenient to refuelling points. The second option would be at as many locations as there are refuelling points. Due to modularity, dispersing electrolysis has little effect on total costs for either option. The decision as to which of the above options is preferred, will depend on the specific nature of each corridor and the decision criteria will include: availability and cost of land, electrical grid accessibility and any zoning restrictions.

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4.1.2 Electricity Supply Subsystem The end-to-end Hydrail System begins with the supply of electricity to make hydrogen through water electrolysis technology. The Ontario electrical grid (as discussed in Section 3.2.3.1) is predominantly carbon-free with various supply options, as shown on Figure 4-2, from nuclear, to hydro-electric, to solar, and wind, with natural gas providing the peak-demand service. So, hydrogen production using surplus electricity results in over 80 percent GHG reduction for the GO system. The grid is primarily made up of the following components categorized as generators, consumers, and grid services (as implied in the layout on Figure 4-2). Depending on the price of electricity, as well as capacity for hydrogen storage, electricity is drawn from the Ontario grid and converted into hydrogen by water electrolysis, mainly at times of grid oversupply and low value for electricity in the market. Occasionally, when the hydrogen capacity is too low in the fuel inventory, electricity at higher prices is used—governed by the imperative of always meeting the GO network’s requirement for hydrogen.

FIGURE 4-2 ELECTRICAL SUPPLY SYSTEM

The parameters in Table 4-1 were used to design the electricity supply subsystem for the Hydrail System and support its operation in the long term.

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TABLE 4-1 ELECTRICITY SUPPLY SUBSYSTEM DESIGN PARAMETERS Parameter Description Significance Impact Electricity price HOEP represents the electricity High, varies every hour and is tied to Operating cost ($/MWh) market price determined an hour the surplus electricity in providing ahead of time, giving enough potential cost-savings when response time for the hydrogen producing hydrogen during periods production equipment to react of lower priced electricity Electricity required Total amount of electricity required High, represents a significant amount Operating cost (GWh/d) by the Hydrail System per day of electricity consumption for one application in the province Surplus electricity Excess electricity that is generated High, determines the lower priced Operating cost supply (GWh) but never used due to lack of electricity at certain times of day and demand at certain times of day could change in the future, depending on the increase or decrease in demand for electricity and supply capacity Future demand Apart from demand arising in Medium, reduces the available Operating cost (GWh) other sectors, electricity for other surplus electricity; however, the modes of transportation (e.g., amount of surplus existing now and in electric vehicles) could take the future79 would be sufficient to advantage of the surplus keep Hydrail operating costs lower electricity, so the demand for surplus could increase Notes: $/MWh = dollar per megawatt-hour GWh = gigawatt-hour GWh/d = gigawatt-hour per day HOEP = Hourly Ontario Electricity Price

4.1.3 Hydrogen Production Subsystem The key elements of the water electrolyzer-based hydrogen production subsystem are shown on Figure 4-3. The electrolyzer stack converts water into hydrogen and oxygen, and all the other components are support equipment to make this conversion happen. The electrolyzers are made up of four primary components: 1. Feed water system 2. Electrolyzer stack 3. Cooling and drying systems 4. Power electronics (or power management) The components except the stack are jointly called the balance of plant (BOP). The stack is at the core of the hydrogen production subsystem shown on Figure 4-3 made up of several electrolysis cells stacked together. The stack is held together using mechanical compression either through bolt-nut

79 Market Intelligence and Data Analysis Corporation (MIDAC) and NextHydrogen. 2016. Grid Integrated Electrolysis – Facilitating Carbon Emission Reductions in the Transportation, Industrial and Residential Sectors. October 31. Accessed October 2017. https://tinyurl.com/ybptfola

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT clamping with appropriate torque applied to the individual bolts or through other means at the time of manufacture. Hydrogen produced by the electrolyzer is in gaseous phase and is sent to the hydrogen storage subsystem for further compression or liquefaction, depending on the option chosen for the distribution and fuelling systems onboard the rail vehicle.

FIGURE 4-3 HYDROGEN PRODUCTION SUBSYSTEM

The parameters in Table 4-2 were used to design the hydrogen production subsystem for the Hydrail System to support long-term investment and operations.

TABLE 4-2 HYDROGEN PRODUCTION SUBSYSTEM DESIGN PARAMETERS Parameter Description Significance Impacts Electrolyzer cost A major cost component within the High, there are numerous modules of Capital cost ($/kWe) Hydrail System that is reducing with electrolyzer stacks needed to improvements in design, materials, produce the required hydrogen for and construction the Hydrail System. This cost is declining with improvements in design and growing numbers being produced. Electrolyzer The deviation from theoretical High, affects the amount of electricity Operating cost efficiency (kWh/kg) efficiency (33 kWh/kg), the energy required to produce hydrogen, so required to produce 1 kg of hydrogen, needs to be as low and close to the or the electrical conversion efficiency theoretical efficiency as possible Electrolyzer current The electrical current across the active Medium, manufacturers have Operating cost density area of each electrolysis cell within the enabled a wide range of operational (A/cm2) electrolyzer stack current densities that can be used depending on the electricity price. Range: 2 to 5 Power consumption per unit of hydrogen produced increases with rising current density. Hydrogen Since the Hydrail System would only High, determines the increase in Capital and production size produce hydrogen at times of lower capital cost of the Hydrail System in operating costs (number) electricity prices, the number of additional electrolyzer stacks needed electrolyzer stacks needed increases to produce the required hydrogen by that much

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TABLE 4-2 HYDROGEN PRODUCTION SUBSYSTEM DESIGN PARAMETERS Parameter Description Significance Impacts Refurbishment Specified as hours of operation Medium, when the performance of Maintenance; lifetime (hours) instead of years, since the electrolyzer the electrolyzer degrades to the point replacement cost Range: 40000 to will not be operated uninterruptedly that it impacts its electricity 100,000 to use lower priced electricity periods; consumption, it needs to be it is lower for PEM than for alkaline refurbished; operation at higher electrolyzers current densities reduces the lifetime Refurbishment cost Electrolyzer stacks are refurbished Medium, impacts the lifetime cost of Maintenance; factor when they reach the end of their the project, such that there is some replacement cost (% of initial capital lifetime, where the components, such savings in the long-term cost) as metal plates and other components in the BOP, are retained if quality is Range: 30 to 60 intact Land cost factor The size of each electrolyzer stack Low, the cost of land should not be Capital cost of ($/m2) determines the total land area significant, even within the GHTA Hydrail System required for the Hydrail System and the relevant cost of land Notes: $/kWe = dollar per kilowatt equivalent GHTA = Greater Toronto and Hamilton Area $/m2 = dollar per square metre kg = kilogram percent = percent kWh/kg = kilowatt-hour per kilogram A/cm2 = amperes per square centimetre PEM = proton‐exchange membrane

The inefficiency in the electrolyzers would result in heat generation from the stacks, so they have to be cooled to maintain the operating temperature at about 60 degrees Celsius (ºC). Usually, they are air cooled for smaller stacks, but for larger stack sizes or a combination of many smaller stacks, cooling water circulation with significant amount of cooling water would be required. To minimize the water usage, a cooling tower might be required. The current assessment estimated the amount of makeup water that would be needed by the cooling tower and is included in the assessment of the total amount of water required by the Hydrail System. 4.1.3.1 Operational Characteristics: Current Density and Cheap Electricity The current density is a flexible operational parameter inherent to water electrolyzers that supports the operating economics of hydrogen generation for the Hydrail System. The performance curve in Figure 4-4 suggests the range of flexibility available to take advantage of the lower price of electricity at certain periods in a day within the Ontario electrical grid. The curve in Figure 4-4 shows the power consumption to produce one cubic metre of hydrogen by Hydrogenic’s PEM electrolyzers. Higher current density is less energy-efficient but concentrating hydrogen production at times of low electricity price can still be cost-efficient and using higher current densities at times of low electricity cost also reduces the capital cost of electrolysis cells.

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FIGURE 4-4 PEM WATER ELECTROLYZER PERFORMANCE80

4.1.3.2 Proton-exchange Membrane (PEM) and Alkaline Electrolyzers As mentioned in Section 3.2.4 there are two types of water electrolyzers that are considered as part of the hydrogen production subsystem: a PEM electrolyzer and an alkaline electrolyzer. There are advantages and disadvantages between the two when compared, as listed in Table 4-3.

TABLE 4-3 PROTON-EXCHANGE MEMBRANE AND ALKALINE WATER ELECTROLYZER COMPARISON No. Parameter PEM Water Electrolyzer Alkaline Water Electrolyzer 1 Electrolyzer Higher: 60-70 percent achievable, so results in Lower: 50-55 percent achievable, so efficiency relatively lower operating cost results in relatively higher operating cost 2 Capital cost Lower: 500-800 $/kWe Higher: 700-900 $/kWe 3 Single stack size Up to 3 MW Up to 10 MW 4 Gas outlet pressure Up to 3 MPa without compression Up to 1 MPa without compression 5 Electrolyte Offline, after deterioration, which might impact Online, during regular operation, so the maintenance operations when the electrolyte needs stack can remain intact indefinitely, replacement as part of the stack refurbishment improving lifetime of operation phase 6 Lifetime Lower: 50,000 hours of continuous operation Higher: 100,000 hours of continuous operation 7 Gas loss for drying None 3.5 percent of the produced gas 8 Technology maturity Developed, yet to be established; deployed at Established; deployed for large-scale and deployment small-scale application 9 Ideal application Small- to large-scale production: Single stack Large-scale production: Single stack size size currently available up to 3 MW currently available up to 10 MW Notes: MPa = megapascal MW = megawatt

80 Hydrogenics Inc., email dated 2017 August 23 from Joe Cargnelli

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The higher electrolyzer efficiency of PEM would have up to 15 percent reduction in operating cost compared to the alkaline electrolyzers. Until the efficiency of the alkaline electrolyzer is improved to match that of the PEM, for Hydrail-type systems, the PEM looks more attractive from an operating cost perspective. The impact from the larger stack size, longer lifetime, and economy of scale is yet to be assessed for the two types of electrolyzers. The larger stack size, for example, when using alkaline electrolyzers, is attractive for central or combined production scenarios. There could be one production facility for a combination of more than one or two GO rail corridors, requiring a larger number of electrolyzers in one given location, so the alkaline electrolyzers could prove economic benefits based on the initial and replacement capital costs. In terms of making a recommendation on these two technologies for use within the Hydrail System, it is too early, as there are unknowns (listed as follows) that make the decision difficult at this time:  The number of central or combined locations for production  If it is onsite production, the installed capacity requirement  Transition plan for the Hydrail System – all corridors or one at a time, as this would also impact the decision on large-scale central production or small-scale onsite production  Operational characteristics of the individual production centres at each location 4.1.4 Hydrogen Storage Subsystem The hydrogen storage subsystem is expected to be part of the production system or sited right next to the production system, as a temporary or transition storage system to manage the large volume of gas that would be needed by the Hydrail System. The key equipment within the hydrogen storage subsystem is shown on Figure 4-5 for both liquid and gas phases. The common equipment for either phase includes:  Compressor  Flow controllers  Regulators  Sensors  Tanks  Control system that distributes and manages electrical power  Control signals to all the relevant equipment within the storage system The liquid phase, in addition, would have a refrigeration plant as part of the liquefaction plant to cool the hydrogen to about -253°C; at which point, hydrogen becomes a liquid. The gaseous hydrogen produced by the electrolyzers needs to be stored until it is required by the refuelling system. The amount of storage is dictated by the amount of electrolysis described earlier, to take advantage of the lower market price of electricity in the Ontario grid.

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FIGURE 4-5 HYDROGEN STORAGE SUBSYSTEM

The parameters in Table 4-4 helped to design the hydrogen storage system for the Hydrail System to support its long-term investment and operations.

TABLE 4-4 HYDROGEN STORAGE SUBSYSTEM DESIGN PARAMETERS Parameter Description Significance Impacts Feed gas pressure Pressure of the gas that the storage Medium, dictates the additional Operating cost (MPa) system receives; the H2 outlet pressure compression that may be required Range: 3 to 10 from the production system when storing as compressed gas Storage pressure Pressure at which the gaseous High, designed to be at relatively Capital cost (MPa) hydrogen could be stored temporarily lower pressures, such that low-cost Range: 10 to 20 before it is dispatched to the refuelling carbon steel tanks could be used, system; the pressure is chosen based although the lower pressure could on tank materials and related costs increase the number of tanks needed to store the same volume of gas Storage duration Duration of storage to support the Medium, larger duration helps in Capital cost (hours) varied production schedule. Larger using lower-cost electricity. But the Range 24 to 96 capacity allows for greater access to space in the storage location might lower-cost electricity not be supporting the additional tanks needed to support the longer duration. Storage tank cost Cost of the storage tank, including the High, dictates the type and storage Capital cost factor ($/kg) support structures to estimate the tank pressure for gaseous hydrogen; there portion of the total capital cost of the is a coherent relationship between the storage system based on the total cost, tank material, and pressure volume of gas that needs storage

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TABLE 4-4 HYDROGEN STORAGE SUBSYSTEM DESIGN PARAMETERS Parameter Description Significance Impacts Storage phase, One of the phases hydrogen could be Medium, initiates a series of design System CGH2 stored in; the gaseous phase is aspects throughout the Hydrail configuration, well-understood and characterized in System, starting from the stationary energy the industry, and is a known storage to the vehicle onboard requirements, automobile fuel when it comes to storage operating cost hydrogen applications

Storage phase, LH2 This is one of the phases in which High, liquid hydrogen requires Operating and hydrogen could be stored. Liquid additional processing of the gaseous capital costs phase storage is well understood and hydrogen that comes from the characterized in the industry, but it is production system, so it is energy less characterized as a fuel onboard intensive the vehicle Tank storage This refers to the design volume of Medium, impacts the system cost and Capital and real volume storage per tank, used to determine the commissioning of the storage estate costs (m3) the total number of tanks required to system, especially if the land area store the available H2 from the available is limited or if the land is very production system as per the design expensive; would trigger the design of multilevel stacking of tanks on top of each other to reduce the overall footprint Land cost factor This is the factor that determines the Low, unless located in urban areas Capital cost ($/m2) total cost of land that is required by the with high land costs; it would have less storage system based on the location. impact on costs if it is in the ROW

Compressor plant This is the capital cost of H2 Medium, could become expensive if Capital cost cost compressor, estimated based on the the volume of gas or the design ($M) pressure required and the volume of pressure of the tanks is increased gas to be compressed Liquefaction plant This is the capital cost of liquefying the High, increases with the volume of gas Capital cost cost H2 from the production system for to be stored, and the operation of this ($M) storage, estimated based on the plant requires additional electrical cooling energy required energy, which would impact operating cost, so is tied to the electricity market price discussed earlier Lifetime (years) This is the lifetime of the material of the Medium, would change if the dynamic Replacement Range: 15 to 20 storage tanks, and is impacted by the loading of the tanks changes (i.e., if cost number of fills (or charge cycle) and there is an increase in the number of the material of the tank construction fills beyond the intended daily requirement) Notes: $M = dollars (millions)

LH2 = liquid hydrogen m3 = cubic metre ROW = right-of-way

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4.1.4.1 Gaseous and Liquid Phases of Hydrogen Liquid phase storage tanks are much different from gas phase storage tanks, and fewer liquid tanks would be required for the same amount of gas. The choice between liquid phase and gaseous phase storage is based on several factors, although from our assessment, the liquid phase one does not seem viable for the proposed Hydrail System. The suppliers of merchant hydrogen are attuned to moving relatively small quantities of hydrogen as liquid (LH2). However, on the larger scale of the proposed RER Hydrail System, there are substantial reasons for operating purely with CGH2, as follows:

 Energy Input: To include LH2 as part of the Hydrail System, energy usage is increased by 10 percent, and energy cost is increased by 20 percent because—unlike electrolysis—the liquefaction process is not readily interruptible and cannot focus on periods of low-cost grid values.  Capital Cost: The cost of a liquefaction plant for the entire RER system is estimated at $160 million This adds complexity to the supply chain and, with no evident substantial cost offsets, this is an additional cost.

 Distribution Cost: Centralization of LH2 would be preferred on economic grounds—the capital cost of liquefaction plants does not scale well. That leads to a need for extensive distribution, and LH2 precludes gas distribution by pipeline. Admittedly, pipeline distribution may encounter some public resistance, but is likely to be practicable. Trucking is cheaper with liquid than with gas, but either, for almost any distance, is much more expensive than pipelining.  Problems with Solid Oxygen: Hydrogen needs extreme purification from oxygen before liquefaction. Purification can be arranged, but it is a particularly significant issue with electrolytically produced H2 with its inevitable initial oxygen content. This is much less of an issue with steam-methane reforming (SMR) H2, which is generally oxygen-free. Traces of oxygen present in hydrogen liquefaction can accumulate in lines and tanks as solid oxygen, and can lead to violent detonation.

 Accident Scenarios: In the event of a spill, LH2 does not disperse nearly as readily or quickly as H2 gas. This increases fire risks.

 Hydrogen Losses: Design can curtail but will not eliminate H2 losses from boil-off within the entire production and consumption chain, thereby increasing the operating cost.

 Extra Handling Risk: While fast vehicle-fill times could be easier with LH2, it is considered more prone to accidents than fuelling using the well-established technology for fuelling with CGH2. Overall, LH2 is a much less familiar fuel than CGH2. 4.1.4.2 Storage Tank Characteristics There is significant difference in the storage tank design in terms of materials, construction, and capital costs. The design is primarily driven by the storage pressure requirements. For the transition storage system, lower-pressure storage would save significant capital costs, as the volume of storage is at least three times larger than the upcoming refuelling storage system. There are at least two distinct types of tanks worth comparing (as summarized in Table 4-5) to provide a basis for the storage system design.

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TABLE 4-5 COMPARISON OF STEEL AND CARBON-FIBRE GAS STORAGE TANKS No. Parameter Steel or Metal Tanks Carbon-fibre Tanks 1 Storage pressure From 0.1 to 20 MPa From 10 to 100 MPa 2 Manufacturing process Established, rolled steel and welded end Established, carbon-fibre wound on steel covers liner with or without fibre-glass reinforcement 3 Supply chain Many local manufacturers available Few; no local manufacturers available 4 Raw material Carbon, stainless, or alloy steel Carbon fibre, steel liner, fibre-glass 5 Cost Lowest possible, due to low cost raw Currently higher than steel tanks due to materials material costs 6 Impact of storage Wall thickness increases, and diameter Wall thickness increases, and volume of pressure decreases as dictated by the pressure individual tanks decreases; thereby, limit increasing the total number of tanks needed 7 Lifetime 10 years 20 years 8 Risks from hydrogen Embrittlement over the lifetime of the tank The refill cycle impacts the stress retained by the fibres

4.1.5 Hydrogen Distribution Subsystem The hydrogen distribution subsystem connects the storage system with the refuelling system, and it differs based on gas or liquid phases of hydrogen. For the gas phase, distribution can be by either pipeline or trucks; but for liquid phase, only trucking is possible for longer distances (beyond 1 kilometre [km] in length). Although for shorter distances (less than 1 km in length), pipeline is feasible for the liquid phase. The distribution system comprises the following equipment, shown on Figure 4-6:  Blowers  Pressure regulator and gas distribution  Temperature control  Flow meters, valves, and sensors  Control system that distributes and manages electrical power and control signals to all the relevant equipment within the respective distribution system

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FIGURE 4-6 HYDROGEN DISTRIBUTION SUBSYSTEM

The parameters in Table 4-6 were used to design the hydrogen distribution subsystem, using a pipeline solution for the Hydrail System to support its long-term investment and operations. For gaseous distribution through pipeline, the fibre-reinforced polymer 81 is chosen as the default material. These are made by coating layers of polymer that has the lowest permeability for hydrogen on to solid substrate, such as steel or polyvinyl chloride (PVC) pipes, depending on the gas pressure.

TABLE 4-6 PIPELINE DISTRIBUTION SUBSYSTEM DESIGN PARAMETERS Parameter Description Significance Impacts Operating Pressure at which the pipeline can Medium, dictates the material and Capital cost pressure (MPa) safely operate dimensions needed for the pipeline Range: 2 to 10 design and construction, so higher pressures would lead to expensive construction Pipeline length Total length of the pipeline per GO rail High, currently specified as the total Capital, (km) corridor and the Hydrail System length of the GO rail network, not operating, and knowing exactly where the production maintenance and storage facilities would be costs located; any increase in length would increase costs Size, internal Internal diameter of the pipeline Low, with respect to the capital cost; Capital cost diameter (m) determined by the operating pressure the gas pressure drop varies with the Range: 0.1 to 0.0 and the volume of gas that needs to be diameter and the length of the transported pipeline

81 U.S. Department of Energy (DOE). 2008. "Section iii.E.3, Fiber-Reinforced Polymer Pipelines for Hydrogen Delivery." FY 2007 Annual Progress Report, DOE Hydrogen Program. Accessed October 2017. https://www.hydrogen.energy.gov/pdfs/progress07/iii_e_3_smith.pdf

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TABLE 4-6 PIPELINE DISTRIBUTION SUBSYSTEM DESIGN PARAMETERS Parameter Description Significance Impacts Capital cost factor Determines the capital cost of the High, might become a significant Capital cost ($/km) pipeline based on the length of the portion of the Hydrail infrastructure if pipeline infrastructure the pipeline length is substantial for a scenario where the production and storage are far away from the GO rail network Lifetime This is the lifetime of the pipeline Medium, usually approximately 10 or Replacement (years) material that allows continuous more years, but other factors could cost operation without impacting reliability impact this, especially the gas pressure, and implementation of joints and connections Notes: m = metre

The parameters in Table 4-7 helped to design the hydrogen distribution using road transportation trucks (tanker-trucks) for the Hydrail System to support its long-term investment and operations. The trucks are usually managed by the hydrogen supplier, so the cost of trucks would be complicated. For simplicity, we assume that the trucks would be owned and operated by Metrolinx.

TABLE 4-7 TRUCK-BASED DISTRIBUTION SUBSYSTEM DESIGN PARAMETERS Parameter Description Significance to the system Impacts Onboard storage Pressure at which the gas or liquid High, determines the type of tank Capital cost and pressure (MPa) hydrogen is stored onboard the truck, required, and the volume of gas or Hydrail legally allowed for transporting liquid that could be stored, so results operating cost hydrogen by road in the cost factor Storage volume Volume of gas or liquid that could be High, determines the number of trips Hydrail (kg or m3) stored per truck for transportation or number of trucks that are needed operating cost per day to transport hydrogen from and capital cost storage to the refuelling system Storage tank cost Cost for the design, materials, High, dictates the cost of the trucks if Capital or factor ($/kg) manufacturing, and testing of the tanks owned by the rail operator; if operating cost suitable for use to transport hydrogen contracted, this would affect the on trucks operating cost Storage phase, gas Phase at which hydrogen is stored in Medium, affects the volume of Capital cost the tank onboard the truck hydrogen that could be transported per truck Storage phase, Phase at which hydrogen is stored in Medium, denser than gaseous Hydrail liquid the tank onboard the truck hydrogen, so two to four times more operating cost hydrogen could be transported per truck Lifetime (years) Lifetime of the tanker truck, including Medium, differs based on the storage Replacement the tanks onboard pressure, phase, and number of refill cost cycle

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4.1.5.1 Pipeline and Truck based Distribution The distribution of hydrogen would only be required in the case of distributed production or combined central production for various corridors. The current industry practice for gaseous fuel distribution is either through pipeline or through tanker-trucks. They are chosen for few specific reasons based on the parameters listed in Table 4-8.

TABLE 4-8 COMPARISON OF PIPELINE AND TRUCK DISTRIBUTION No. Parameter Pipeline Tanker-truck 1 Demand for hydrogen If higher and long-term, pipeline is If smaller and short-term, trucks are cost-effective cost-effective 2 Distance from Economic, if shorter (less than 100 km Economic for longer distances, when production to refuelling per corridor) used as a backup supply (or short-term) 3 Accessibility Could support an entire array of Difficult to do this with one truck, as the additional users along the length of the pressure drop after each transfer pipeline by allowing access to tap into impacts on the transfer rate the pipeline for permanent use 4 Operating pressure Pipeline has limited operating Trucks could carry up to the pressure pressure, so the compressor power required by the refuelling and requirement at the refuelling system dispensing systems would increase 5 Operational risk Lower, especially if located along the Higher, irrespective of the ROW of the Ministry of Transportation transportation routes taken 6 Hydrogen phase Only useful for gaseous phase, Could be used to transport both gas especially for longer distances (>1 km) and liquid phases of hydrogen 7 Initial capital cost Higher Lower Notes: > = greater than

The pipeline option could be selected if the production and storage systems are within the lengths of the GO rail corridors to keep the capital costs at a reasonable level. Although the return on investment would take longer than for trucks, but other advantages, including the higher reliability and lower operational risk, strengthen the choice for the pipeline option. Additional information on pipelines is available elsewhere82. However, the reality of Hydrail implementation would occur in phases over a few years, so the first few trains could go into service even before the full implementation of the Hydrail infrastructure if the rail vehicles could be refuelled by trucks every day. The truck option has another advantage in that it may not require the refuelling and dispensing systems if the logistics of refuelling each train is planned accordingly. The trucks could be coordinated to refill a small number of tanks near the dispensing point at higher pressure using a compressor for the gaseous phase. If the trucks carry liquid hydrogen, they can be transferred to the train directly without buffer refill storage, provided the train is storing hydrogen onboard as liquid. But in real train

82 National Institute of Standards and Technology (NIST). 2015. NIST Calculates High Cost of Hydrogen Pipelines, Shows How to Reduce It. July 20. Accessed October 2017. https://www.nist.gov/news-events/news/2015/07/nist-calculates-high-cost-hydrogen-pipelines-shows- how-reduce-it

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT operational experience, this arrangement would not work due to increased chances for accidents (due to many numbers of moving pieces within the refuelling and maintenance facility) and impacts to the reliability of daily operation. This scenario of trucks refuelling the trains directly or through a small number of buffer tanks is not currently considered in this study, as there are unknowns that do not yield sufficient and confident information to assess the impact. There are two key unknowns: (1) the location of the refuelling system, and (2) the number of trains that can be refuelled in parallel at these refuelling locations. 4.1.6 Hydrogen Refuelling Subsystem The hydrogen refuelling subsystem is required to provide enough hydrogen for a full day of GO train service, so the storage tanks are sized such that they can store up to 24 hours of gas – the volume of gas required for 1 full day’s service for the RER Scenario 5 train service pattern. These tanks would be located within the dispensing or refuelling facility where each train gets the required volume of hydrogen for a full day’s service. The refuelling system consists of the following equipment, as shown on Figure 4-7:  Compressors in a cascaded arrangement  Pressure regulator and gas distribution  Temperature control  Flow meters, valves, and sensors  Control system that distributes and manages electrical power  Control signals to all relevant equipment within the refuelling system The temperature control is necessary during transfer of gaseous hydrogen onto refuelling tanks, as hydrogen could cool down or warm up, depending on the pressures, during transfer from the distribution system.

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FIGURE 4-7 HYDROGEN REFUELLING SUBSYSTEM

The design parameters for the refuelling system are similar to those for the storage system provided in Table 4-4. The main difference within the refuelling system is for the gaseous phase, which is stored at a higher-pressure range from 70 to 100 MPa. For the current Hydrail System, refuelling tanks are designed to store the compressed gas at a pressure of 85 MPa, based on similar experience on automotive refuelling system design83. This would provide enough pressure to fill the tanks onboard the rail vehicles, which are designed to be at 70 MPa. The liquid storage is done in the same fashion as it is done in the storage system. 4.1.7 Hydrogen Dispensing Subsystem The hydrogen dispensing subsystem comprises the following equipment, shown on Figure 4-8:  Nozzle  Temperature-controlled hose  Cooling system

83 National Renewable Energy Laboratory (NREL). 2014. Hydrogen Station Compression, Storage, and Dispensing Technical Status and Costs. Independent Review published for the U.S. Department of Energy Hydrogen and Fuel Cells Program. Technical Report NREL/BK- 6A10-58564. Contract No. DE-AC36 08GO28308. May. Accessed October 2014. https://www.nrel.gov/docs/fy14osti/58564.pdf

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 Flow meter, valves, and sensors  Control system that distributes and manages electrical power  Control signals to all relevant equipment within the dispensing system The refrigeration plant is necessary during the transfer of gaseous hydrogen onto the onboard tanks, as hydrogen warms up during its expansion from the higher pressure at the refuelling tanks into the lower pressure of the onboard tanks. For liquid hydrogen transfer between the refuelling tanks to the tank onboard the vehicle, the transfer lines have to be maintained with good insulation such that the boil-off is minimized.

FIGURE 4-8 HYDROGEN DISPENSING SYSTEM

The parameters in Table 4-9 were used to design the hydrogen dispensing subsystem for the Hydrail System to support its long-term investment and operations.

TABLE 4-9 HYDROGEN DISPENSING SYSTEM DESIGN PARAMETERS Parameter Description Significance Impacts Flow rate (kg/h) Flow rate required at the dispenser High, dictates how much hydrogen Operations of such that the tanks onboard the rail can be transferred from the refuelling the rail network vehicle are filled within a set time by tanks into the onboard tanks; the operators, usually 15 minutes of fill significantly faster flow rates are time required (please read the discussion after this table) Dispensing Applies mainly to gaseous hydrogen, High, enables faster transfer and Operating cost pressure (MPa) usually set higher than the allowed could trigger the requirement for a storage pressure onboard the rail booster compressor if the flow rates vehicle, and matches the pressure are not adequate delivered from the refuelling system

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TABLE 4-9 HYDROGEN DISPENSING SYSTEM DESIGN PARAMETERS Parameter Description Significance Impacts Dispenser cost Current form of the dispenser cost High, depends on the number of Capital cost factor ($M/unit) factor to account mainly for the costs dispensing units required; the real of the dispensing unit and the cooling cost factor would be the redesign system engineering cost of the existing dispensing units used for automotive or bus application Dispensing phase, Gaseous hydrogen that would be High, the flow rates are usually lower Operating cost gas dispensed either from the gas phase than the liquid phase transfers, so storage in the refuelling system or additional engineering design is vaporized liquid hydrogen into gas for needed to accomplish the flow rates the liquid-based refuelling system Dispensing phase, Direct transfer of liquid hydrogen from Medium, in a situation where liquid Operating cost liquid the refuelling system that would store hydrogen is still considered within the the liquid hydrogen in tanks Hydrail System, it has faster flow rates than gaseous hydrogen Lifetime (years) Lifetime of materials and equipment Medium, as the material degrades, Replacement involved in the dispensing system, the operational aspects change in cost including the nozzle, tubing, pipes, time hoses, and the cooling system (refrigeration plant for example) Notes: kg/h = kilogram per hour

To achieve 15-minute fill times for each train, the gas flow rate currently existing for the hydrogen vehicle application (at 432 kg/h or 7.2 kilograms per minute [kg/min]84) needs to be at least 4 to 5 times faster. This requires additional engineering design to split the flow into parallel manifolds. This is helped by the design of the gas phase storage tanks onboard the vehicle where there are several tanks. Simultaneous fill of multiple tanks using the parallel manifolds would enable faster fill rates required to meet the 15-minute timeframe. 4.1.8 Hydrogen Vehicle Subsystem The hydrogen propulsion subsystem is designed to fit within the two motor vehicle types that are planned for the RER Scenario 5: (1) high-power locomotive (with 3 to 6 MW of peak power), and (2) EMUs (with about 2 MW of peak power per EMU). Both of these vehicle platforms would be fitted with the following hydrogen-related equipment, shown on Figure 4-9, based on available space:  Storage tanks  Fuel cell  Power management  Electrical batteries

84 Elgowainy, Amgad, and Krishna Reddi. 2017. Hydrogen Refueling Analysis of Heavy-Duty Fuel Cell Vehicle Fleet. Presented at the 2017 DOE Hydrogen and Fuel Cells Program Annual Merit Review. Argonne National Laboratory. June 8. Accessed October 2017. https://www.hydrogen.energy.gov/pdfs/review17/pd014_elgowainy_2017_o.pdf

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 Cooling system  Ultracapacitors The vehicle itself would have the power control system, traction motors, regenerative braking, and head-end power (for HVAC, lights, braking power, and other accessories, including the air compressors or vacuum system for the brakes). There are two possible hydrogen storage options based on the physical phase: (1) gaseous hydrogen at a pressure of about 70 MPa (700 bar) with operational pressure ranging from -20 to 30°C, and (2) liquid hydrogen at atmospheric pressure and maintained at -253°C. The liquid hydrogen is twice as dense as the gaseous hydrogen at that pressure.

FIGURE 4-9 HYDROGEN VEHICLE SYSTEM

4.1.8.1 Hydrogen Rail Vehicle: Platform The powered vehicle (locomotive or powered EMU) design is at the core of the Hydrail System’s design, providing the total energy required with hydrogen as the primary energy source. There are three fundamental criteria that were used to design the Hydrail vehicle framework for this study: 1. Power Requirement: This dictates how much traction power is required for each powered vehicle (delivered through several motors and axles as part of the vehicle platform). There are two components of traction power: a) Peak power: Determined by the acceleration required from each of the trains leaving a station in the GO corridors. The acceleration requirement is not found in the IBC (Initial Business Case) documentation as a specific number, usually defined as a speed to be achieved in a short- duration (km/h per second or m/s2). So, the basis for the peak power chosen for Hydrail is to match the rated power of an equivalent electric locomotive or EMU considered for the IBC model. Figure 4-10 shows the peak power requirement per locomotive based on the intended acceleration. This shows that the faster acceleration requires significant peak power as well as being proportional to the train weight. b) Average or coasting power: Determined by the time allotted between each station as per the train service plan for RER Scenario 5. There are additional parameters that impact the time and the average power such as the number of signals; stops made along each journey; and number of stations. So, an average of coasting power for all corridors was estimated by

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analysing power profiles from simulation data for at least five GO corridors. This analysis helped determine the average power requirement per corridor. The average power for this study as a base-case was estimated at about 60 percent of the peak power. The peak and average powers determine the total fuel required per train per trip. These power parameters need to be estimated based on the actual requirement for GO RER Scenario 5, taking into consideration all the associated changes that would need to be done to accommodate the desired acceleration. For this study, the total hydrogen required is based on specified peak and average powers from a known vehicle design available from a rail vehicle manufacturer. Any subsequent study should pay attention to these two parameters as the starting point.

FIGURE 4-10 RELATIONSHIP BETWEEN PEAK POWER AND ACCELERATION 85 25 Train weight: 1 loco + 6 bi‐level coaches + passengers = 507 tonnes Train weight: 1 loco + 12 bi‐level coaches + passengers = 882 tonnes 20

5 Peak or acceleration power required (MW) 0 0.00 0.20 0.40 0.60 0.80 1.00 1.20 Acceleration (m/s2)

2. Weight Requirement: The peak power and the coasting or average power would also depend on the total weight of the locomotive or EMUs. This depends on the train consist configuration with the number of passenger bi-level coaches to be pulled at peak and off-peak hours. The difference in peak power required is shown in Figure 4-10 for two train consists: a) 1+6 consist: 1 locomotive (132 tonnes) with 6 bi-level coaches (294 tonnes) having passengers in all seats (81 tonnes) for a total of 507 tonnes b) 1+12 consist: 1 locomotive (132 tonnes) with 12 bi-level coaches (588 tonnes) having passengers in all seats (162 tonnes) for a total of 882 tonnes The train weight is directly related to the total energy required to move the train, so dictates the total amount of fuel required for the train per trip. As an example, the fuel requirement during acceleration for various train weights is shown in Figure 4-11 For proper comparison, all the fuel requirements

85 The data used in this chart is available in the model developed for this study: the “Hydrail Operational Simulation Model” (V1.85), in the “Results” tab.

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(diesel, hydrogen and electricity) are presented in terms of energy required expressed in kilowatt- hour (kWh). The respective engine efficiencies listed in Figure 4-11 are the typical fuel conversion efficiencies for each of the propulsion technologies currently available – diesel (35 percent)86, hydrogen (50 percent) and electricity (90 percent)87. Given the significance of the train weight, the fuel savings pertaining to the 1+6 consist during off- peak hours (like EMUs) should be considered when estimating the lifetime costs for operation, maintenance and replacement. In the current study, the fuel requirement is calculated based on peak and average powers applied to the start-stop pattern for each corridor. But savings based on changes in weights are not accounted due to the uncertainties involved, including the lack of a finalized vehicle design.

FIGURE 4-11 RELATIONSHIP BETWEEN TRAIN WEIGHT AND FUEL REQUIREMENT 85 400 Diesel required at 35% engine efficiency 350 Hydrogen required at 50% engine efficiency 300 Electricity requied at 90% engine efficiency

250

200

150

100

Respective fuel required to accelerate (kWh) 0 200 300 400 500 600 700 800 900 1000 Train weight (tonne)

3. Space Availability: To minimize the cost of redesign involved in a new rail vehicle platform, it was decided to use the existing design from either electric or diesel vehicle platforms available in the market. The available space onboard the vehicle platform was broken down into large blocks for key equipment or human space (passenger seating in EMUs or cabin for engineers in locomotives). Figure 4-12 shows the breakdown of space availability onboard the two vehicle types providing the basis for fitting hydrogen equipment on an existing vehicle platform.

86 S. Chandra, MM. Agarwal. Railway Engineering, Oxford University Press, New Delhi, 2007. 87 S. Frey. Railway Electrification Systems and Engineering, White Word Publishing, New Delhi, 2012.

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FIGURE 4-12 SPACE DISTRIBUTION ABOVE THE POWERED RAIL VEHICLE FLOOR AND TRUCKS 85 Fuel cell Batteries 3% 1% Batteries 2% Fuel cell Other Hydrogen 7% equipment tanks 20% 16%

Other equipment 35% Hydrogen Human space tanks 60% 36% Human space 20%

(a) EMU (b) Locomotive 4. Regenerative Brake Energy: Regenerative braking helps recover the resident motive energy when the vehicle is decelerating to respond to a slow/stop signal or to bring the train to a stop at a station. From practical evaluation of energy flows in European rail operation, the regenerated energy with respect to the total energy consumed is given in Table 4-10 in row 4 – “Energy returned to catenary”. Remember that all the data given in this table is for electric locomotives with overhead catenary system with the recovered energy directly fed into the grid.

88 TABLE 4-10 COMPARISON OF REGENERATIVE BRAKING ENERGY IN ELECTRIC LOCOMOTIVES Parameter UK Spain Sweden Energy consumed at PCC 100 percent 100 percent 100 percent Energy consumed at pantograph 88 percent 83.3 percent 91.2 percent Energy returned to catenary 7.2 percent 9.6 percent 8.3 percent Energy returned to grid 1.7 percent 2.6 percent 0 percent

The energy returned to grid as given in the table above suggests that there are energy losses incurred in returning the recovered energy back into the grid, since there is no onboard energy storage feature in these electric locomotives to use the recovered energy efficiently. The recovery can be improved if energy storage capabilities are available, either onboard like in hydrogen-powered locomotives and EMUs or wayside within the railway control. The recovered energy could be stored and optimized for later use, and up to 30 percent of energy reduction can be realized, depending on

88 I. González and E. Pilo. Regenerative braking and the different traction systems. Energy Recovery Workshop, Madrid, September 29, 2015. Available at: https://uic.org/forms/IMG/pdf/regenerative_braking_traction_systems.pdf

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT the vehicle speed, storage size and recuperation ratio89, 90. The efficiency of recovery (recuperation ratio) could be improved if smart onboard power management systems (combination of batteries, electronics and sophisticated software) are included in the vehicle design91. The hydrogen equipment onboard was designed by first breaking down the space occupied by each component from an existing locomotive or EMU design based on external dimensions from manufacturer data. This was done in a very general manner, as actual dimensions were not available for EMUs or for the right locomotive platform. Then the space available for the hydrogen propulsion equipment was estimated by assessing the primary components, such as fuel cells (includes power electronics and cooling system), batteries, and storage tanks. The fuel cell and batteries were then sized based on the average and peak power requirement of the vehicle platform (EMU or locomotive). The storage tanks are designed to fill all the remaining usable space available on the vehicle. Allowance is given to unusable space, including the corners, space between equipment, passageways, external dimension of tanks, and support structures. This design approach helped determine the actual number of trips that a train could provide, depending on the peak and average power of the vehicle. An onboard storage contingency is stipulated based on prior experience with diesel locomotives. Ten percent of additional hydrogen was included in the vehicle design, so that there is additional fuel onboard for unusual situations where a train would otherwise take longer to reach a station. This contingency affects both the Hydrail System design and the vehicle design:  The Hydrail System is only trivially impacted by the requirement to generate this additional hydrogen for initial fills and rare occasions when a train consumes this contingency hydrogen.  The vehicle design is affected via the additional space and weight required to carry this additional 10 of hydrogen each trip. An optimum contingency value should be estimated for design of the Hydrail System and hydrogen vehicle. 4.1.8.2 Hydrogen Rail Vehicle: Hydrogen Onboard Equipment Based on the peak and average power required per train per corridor, the hydrogen components onboard were designed to meet the power requirements. For example, batteries by themselves or combined with ultracapacitors could provide the peak power needed during acceleration towards the maximum allowable speed, so batteries were sized to provide the peak power required by the rail vehicle – locomotive or EMU. The batteries were designed to retain about 70 percent of the state of charge (SOC) to ensure recharging of the remaining 30 percent happens between stops per trip. Fuel cells could provide power directly to the motors via the power management system, or they could recharge the batteries on a continuous basis. In the latter, the batteries would then provide

89 U. Henning, et al. Innovative Integrated Energy Efficiency Solutions for Railway Rolling Stock, Infrastructure and Operation. Available at: https://uic.org/cdrom/2008/11_wcrr2008/pdf/R.3.4.3.1.pdf 90 Kent, Stephen, Dimantha Gunawardana, Tom Chicken, and Rob Ellis. 2016. Future Railway Powertrain Challenge Fuel Cell Electric Multiple Unit (FCEMU) Project. FCEMU Project - Phase 1 Report - Issue 1. University of Birmingham, Hitachi Rail, Fuel Cell Systems Limited. June. 91 M. Shimada et al. Energy Storage System for Effective Use of Regenerative Energy in Electrified Railways. Available at: http://www.hitachi.com/rev/pdf/2010/r2010_01_104.pdf

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT both peak and average power to the traction motors based on the demand during the trip. For this study, fuel cells were sized to match the average power requirement. The design parameters for the hydrogen equipment onboard the rail vehicle (both EMU and locomotive) are provided in Table 4-11, and were used to design the hydrogen vehicle system for the Hydrail system to support its long-term investment and operations.

TABLE 4-11 HYDRAIL VEHICLE SYSTEM (EMU AND LOCOMOTIVE) DESIGN PARAMETERS Parameter Description Significance Impacts Fuel cell size (MWe) Size of the fuel cell onboard the vehicle, High, determines the physical size of the Capital cost and Range: 0.5 to 2 determined to match the average fuel cell system and the space required onboard space power requirement onboard Fuel cell efficiency Volume of hydrogen required to High, affects the overall electrical energy Operating cost (kWh/kg) produce the electrical energy required of the Hydrail system by demanding that of Hydrail Range: 15 to 18 to provide the average power much more hydrogen system Fuel cell cost factor Determines the capital cost of the fuel High, affects the total fleet capital cost Capital cost ($/kWe) cell system, including the power electronics, cooling system, and other relevant equipment Fuel cell Discount on reusing certain Medium, determines the cost-savings Replacement refurbishment cost components within the fuel cell stack when replacing the fuel cell stack by cost (% of initial capital) refurbishing the depreciated parts Range: 40 to 60 Fuel cell lifetime Lifetime of fuel cell system and its High, the lifetime is also determined by Replacement (hours) components; represents the actual the performance (or efficiency), such that cost; Range: 25,000 to hours of operation, not the time since it if the volume of hydrogen required Operating cost 40,000 was commissioned suddenly increases, the operating aspects could mark the fuel cell to be removed from service for a refurbishment Storage tank Pressure at which the gaseous High, critical to conserve the space Capital cost; pressure (MPa) hydrogen is stored onboard the vehicle; onboard the vehicle to maximize the Onboard space Range: 70 to 85 also makes the tanks much more number of trips that the vehicle could complex and expensive to fabricate provide every day Storage tank cost Determines the cost of the storage tank High, since the pressure is at the upper Capital cost factor ($/kg) and the support structure onboard the limit of the design, this needs to be vehicle; a function of the storage lowered pressure Storage phase, gas Phase when hydrogen is stored in the Medium, affects the volume of hydrogen Capital cost; tanks onboard the vehicle that could be stored onboard, so the number of trips Storage phase, Phase when hydrogen is stored in the Medium, denser than gaseous Hydrail liquid tank onboard the vehicle hydrogen, so two to four times more operating cost hydrogen could be stored onboard, which helps increase the number of trips, but is energy intensive Storage tank volume Volume of hydrogen than can be stored Low, irrelevant to the cost, as other Onboard space (m3) per tank onboard the vehicle; depends parameters, such as pressure and on pressure or density storage phase, affects the cost; however, this helps in optimizing the space requirement and for parallel refilling of tanks

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TABLE 4-11 HYDRAIL VEHICLE SYSTEM (EMU AND LOCOMOTIVE) DESIGN PARAMETERS Parameter Description Significance Impacts Storage tank lifetime Lifetime of the storage tank onboard the High, the number of fills per day is Replacement (number of fills) vehicle represented in number of fills; if determined by the volume of hydrogen cost Range: 3,000 to the tanks are filled once a day, then that that can be carried onboard, which is 5,000 yields the number of years determined by the number of trips that could be provided by each vehicle Battery size (MWh) Indicates the battery size determined by High, determines the cost of the battery Capital cost; Range: 0.5 to 2 assessing the peak power requirement system, and the relevant space and Onboard space of the vehicle and the time needed to weight requirements that go with it deliver in one continuous instance Battery state of The amount of electrical charge stored High, this needs to be at a certain Capital cost; charge (%) in the battery at any given time. minimum level (70 to 90 percent) such Operating cost Range: 70 to 90 that there is sufficient time available to re-charge the batteries by the fuel cells while the train is at cruising speed. Batteries that have charge lower than this state would not be fully available to support the various electrical load onboard Battery efficiency (%) Efficiency of the battery to store and High, a reduction in efficiency would Operational Range: 60 to 80 discharge electricity; for Li-ion-based suggest that there is insufficient reliability; batteries, the efficiency is at the upper electricity supply onboard that could Replacement end affect vehicle acceleration and the hotel cost loads Battery cost factor Determines the cost of the battery High, affects the vehicle capital cost and Capital cost ($/kWh) system onboard based on the size would be impacted by alternate and required; Li-ion based batteries are cheaper battery material if performance currently expensive is not impacted Battery lifetime Lifetime of the battery material; since Medium, battery lifetime would be Replacement (years) batteries are made in modules, only the improved if devices such as cost Range: 5 to 10 affected modules could be replaced ultracapacitors are used Notes: Li = lithium MWe = megawatt-equivalent

4.1.8.3 Vehicle Fleet Mix Options The Hydrail vehicle fleet could include the same combination of the powered multiple units or one or two locomotives pulling the 12 bi-level coaches per RER Scenario 5. For Hydrail, a stronger case can be made for two locomotives pulling 12 bi-level coaches in a push-pull configuration, as follows:  Splitting the peak power required by a single locomotive into two half-powered locomotives enables storage of additional hydrogen onboard each of the two locomotives; thereby, increasing the number of trips that these trains could provide in a day  During off-peak periods, the 2 locomotives with 12 coaches (2+12 consist) could be split with 1 locomotive with 6 coaches (1+6 consist) to provide the service, reducing hydrogen use  If the 1+6 consist is economical compared to the 4- or 8-car EMU, then the entire fleet mix would only have locomotives, simplifying the O&M aspects of the GO rail network

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4.1.8.4 Options for train service plans The train service plan for RER Scenario 5 is one of the most important design bases for the Hydrail System. This dictates how much hydrogen is to be generated. The key design parameter that determines the total hydrogen required (in tonnes per day [tpd]) for the Hydrail System is the energy (in megajoules or MJ) used by each train for a given trip across each of the GO rail corridors. The energy required by each train in each of the GO rail corridors was assessed using the RER Scenario 5 train service pattern. The energy estimates were based on the start-stop pattern by linking the peak and average powers required by the rail vehicle with the journey time between each stop. This energy was then converted into the amount of hydrogen required based on the efficiencies of fuel cells onboard the vehicle and the electrolyzer within the hydrogen production subsystems. When this estimate was developed for all the trains over a day in each corridor, it helped in determining the total hydrogen required per corridor and for the entire GO rail network under Scenario 5. If the start-stop pattern changes per corridor, say, due to the addition of stations or other signal- related stops, the hydrogen required for each trip in that corridor would increase. The train service plan is critical to the Hydrail infrastructure and vehicle design. To show the difference of the effect of the service plan, the study compares the model results for two timeframes in the RER Scenario 5 deployment: (1) 2024 as the beginning of the Hydrail train service; and (2) 2044 as the completion of the deployment of the Hydrail train service with all the additional trains added since 2024. This would therefore require addition of hydrogen infrastructure to support the addition of trains in a modular fashion as discussed earlier in the production and storage subsystems design. Table 4-12 shows the impact of the difference in train service plans between the two timeframes in terms of locomotives required, hydrogen production, and electricity required.

TABLE 4-12 TRAIN SERVICE PLAN IMPACT FOR TWO TIMEFRAMES UNDER RER SCENARIO 5 Train Service Plan 2024 2044 Electric locomotives 35 44 Hydrail locomotives 70 88 EMU (4-car set) 84 84 Hydrogen required (tpd) 40 48 Electricity required (GWh) 2.2 2.5 Notes: EMU = electrical multiple unit GWh = gigawatt-hour Tpd = tonne per day

In the IBC, five RER scenarios were listed, of which Scenario 5 represents a partial electrification of the GO network. However, Scenario 4 within the RER program involves electrification of the entire GO network, assuming this could be done. This involves complete conversion of all diesel-powered vehicles in the GO network with the RER train service plan. When the design basis for the Hydrail System is applied to Scenario 4 using the service plan, the additional requirement for locomotives, hydrogen and electricity increased to that shown in Table 4-13.

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TABLE 4-13 TRAIN SERVICE PLAN IMPACT FOR TWO TIMEFRAMES UNDER RER SCENARIO 4 Train Service Plan 2024 2044 Electric locomotives 78 88 Hydrail locomotives 156 176 EMU (4-car set) 84 84 Hydrogen required (tpd) 59 71 Electricity required (GWh) 3.2 3.7 Notes: EMU = electrical multiple unit GWh = gigawatt-hour Tpd = tonne per day

Note that in both tables above, the number of locomotives for Hydrail is twice the number of electric locomotives. This is part of the Hydrail System vehicle design, where the peak power of the vehicle is halved to accommodate hydrogen in two locomotives of identical power. This provides both range and flexibility, the former ensuring enough hydrogen to provide a full day’s service, and the latter allowing for efficient fleet operation between peak and off-peak hours of the day.

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4.2 Hydrail System Operations and Maintenance The objective of this section is to present performance and economic outcome data from the simulated operation of the Hydrail System and its options. The Operational Simulation Model contains a definition of how the Hydrail System would operate as a functional railway. It then applies this functionality, in combination to the hydrogen technology subsystems, to a model of the Hydrail System. Both the railway model and the Hydrail System model are sufficiently flexible to accommodate new data and options but results from the current underpinning assumptions are presented in this section. The operational design and the subsystem sizing of the Hydrail System (discussed in Section 4.2.2.2) were developed using a spreadsheet model created specifically for this feasibility study by scientists from the hydrogen research group at CNL92. It is called the Hydrail Operational Simulation Model. It was used to generate hydrogen process results and feasibility level cost estimates for this report. The results from the Hydrail Operational Simulation Model were then fed into Metrolinx’s IBC of the RER Program. In this section, costs are reported before applying the financial model assumptions and conditions to distinguish the change in costs per the system design or cost scenarios discussed later, so, the costs here are different from those used in the Business Case modelling, described in Section 4.4. 4.2.1 Operating, Maintaining, and Renewing the Hydrail System 4.2.1.1 Static and Onboard Hydrogen Infrastructure Certain Hydrail system components (or equipment) have distinctive maintenance and renewal characteristics, such as fuel cells, electrolyzers, batteries, storage tanks, and compressors. They are usually associated with the lifetime of these components, as discussed in Section 4.2.2.2. A summary of the lifetimes of various fixed and mobile Hydrail infrastructure is presented in Table 4-14.

TABLE 4-14 LIFETIME OF HYDRAIL SYSTEM COMPONENTS No. Hydrail System Component – Fixed Lower Value Higher Value 1 Electrolyzer (PEM) 40,000 hours 50,000 hours 2 Electrolyzer (Alkaline) 55,000 hours 100,000 hours 3 Storage tanks (20 MPa) 10 years 15 years 4 Pipeline (10 MPa) 10 years 30 years 5 Refuelling tanks (85 MPa) 15 years 20 years 6 Dispensing units 10 years 15 years Hydrail System Component – Mobile 1 Fuel cells (PEM) 25,000 hours 60,000 hours 2 Batteries (lithium ion) 40,000 hours 50,000 hours 3 Storage tanks (70 MPa) 3,000 fills 5,000 fills Notes: MPa = megapascal No. = number PEM = proton-exchange membrane

92 Canadian Nuclear Laboratories. www.cnl.ca

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Fuel Cells and Electrolyzer Maintenance and Lifetime Extending the lifetime of PEM fuel cells has been a major objective of developers, and steady progress has been made, as suggested by the upward curves shown on Figure 4-13. This is representative of the PEM electrolyzers, as well, since they have similar internal components as fuel cells, so would follow similar lifetime expectancies.

FIGURE 4-13 FUEL CELL SYSTEM LIFETIME CHANGES 70,000

60,000

50,000

40,000

30,000

20,000

Fuel Cell Lifetime (hours) 2024 cost‐case 10,000 Future cost‐case 0 2015 2020 2025 2030 2035 2040 2045 2050 Currently, leading manufacturers of PEM fuel cells have demonstrated 30,000 hours of lifetime. To be conservative, this study assumes 25,000 hours for the base or 2024-cost case. For this study, “lifetime” is not to a point of failure, but the point when a gradual loss of conversion efficiency from hydrogen to electricity has reached a level that justifies taking the cell out of service and refurbishing it. The manufacturers confirm that lifetime should be calculated in terms of hours of full-power operation. For GO trains, it would be conservative to assume 18 hours per day of operation and half of that time equivalent to operation at full power (to discount periods of no acceleration, coasting, braking, and being stationary). So, 25,000 hours translates in real-time to an interval between refurbishment of: 25000 x 24/18 x 1/0.5/8760 = 9.1 years The relationship between fuel cell lifetime and operational life is summarized on Figure 4-14.

FIGURE 4-14 RELATIONSHIP BETWEEN FUEL CELL LIFETIME AND OPERATIONAL TIME 80

70 25,000 hours 50,000 hours 60

20 Fuel Cell Lifetime (years) 10

0 0 5 10 15 20 25 30 Operating time of fuel cell in a day (hours)

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Refurbishment consists of disassembly, replacement of the cell’s central membrane, and reassembly. Today, refurbishment is estimated to cost about 60 percent of the original cost, and this figure is used in this study. This is a conservative assumption, since future refurbishment costs will likely be less than 60 percent of today’s cost because of the continuing decline in original equipment manufacturer (OEM) costs for fuel cells. If alkaline electrolyzers are used, maintenance requirements are insignificant, since this type of cell operates for decades with an occasional need to remove accumulated carbonate sludge and makeup of caustic. If PEM cells are used, their technology is to PEM fuel cells, so it is reasonable to assume that they will match fuel cell characteristics and require refurbishment in the same way after 25,000 hours at the nameplate-power rating. For example, if 2.8 times more cell capacity were installed than needed for continuous hydrogen, and current density averaged 3.11 A/cm2 rather than a nameplate rating of 2.2 A/cm2, lifetime before refurbishment would be: 25,000 x 2.8 x 2.2/3.11 x 1/8,760 = 5.7 years The relationship between electrolyzer lifetime and operational life is summarized on Figure 4-15.

FIGURE 4-15 RELATIONSHIP BETWEEN ELECTROLYZER LIFETIME AND CURRENT DENSITY 30 25,000 hours 25 50,000 hours

Electrolyzer Lifetime (years) 5

0 0123456 Electrolyzer operating current density (A/cm2) Battery Maintenance and Lifetime The lifetime of lithium ion batteries (LIBs) is beyond the scope of a preliminary assessment because their lifetimes are impacted by numerous factors that can be mitigated through design. The effects include the following:  Pushing the battery to its limits at either the very-high or the very-low ends of its capacity shortens life. Systems are usually designed to avoid these zones or even to work in a comparatively narrow range, which could be thought of as a way of adding overcapacity.  High temperatures (above 30°C) shorten battery life, especially when the battery is fully charged. Charging at low temperatures (below 0°C) shortens their life.  High rates of charge tend to shorten life. This is why integrating them with ultracapacitors can be worthwhile, since the latter can accept very high rates of charge.

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Storage Tank Maintenance and Lifetime The 700-bar composite tanks for on-train storage of hydrogen have been assigned a lifetime of 5,500 pressure cycles in a study by Argonne National Laboratory93. While specifically for automotive applications, the critical factor is the diameter of storage cylinders, and this will be effectively similar for Hydrail. However, specifying 5,500 cycles is a very conservative assumption, since Comond et al.94 have shown that a tank can be designed to sustain 15,000 cycles. The lifetime of these tanks is determined by flexing of the steel liner. At 15,000 cycles and 1 cycle per day, the lifetime is 40-50 years and comparable to the expected life of the Hydrail locomotive. The same lifetime expectancy applies to the composite tank construction for the very high-pressure tanks used to store hydrogen at refuelling locations. Lower-pressure steel tanks for buffer storage to accommodate optimized operation of the electrolyzers will experience lesser stresses and have even longer lifetimes. In short, no provision for replacement of hydrogen tanks will be needed. Compressor Maintenance and Lifetime Compressors are rugged mechanical devices and should have indefinite lifetimes if properly maintained. Exactly what maintenance will be required is impossible to define without specifications of the equipment to be deployed. However, a detailed independent review for the U.S. National Renewable Energy Laboratory (NREL) 95 recommends that the cost of ongoing maintenance would be covered by adding one-third to the initial capital cost. 4.2.1.2 Railway Operations and Maintenance Maintaining railway system availability is crucial to providing an efficient and competitive rail operation. Availability can be defined as the probability that a system is operating properly when it is requested for use, or the probability that a system is not failed or undergoing a repair action when it needs to be used. Therefore, system reliability, which represents the probability of components, parts, and systems to perform their required functions for a desired period of time without failure in specified environments, is closely related to the availability of the same system. Reliability addresses the probability that a system is not failed, but because availability is also driven by the probability that a system is not undergoing a repair, it will also be a function of its maintainability. Operations The Hydrail system was designed to provide the same level of service (LOS), or same frequency of service, to the same number of passengers as presently considered in RER Scenario 5. The Hydrail service patterns considered are an exact match to the Electrification scenario, and the passenger capacity in each train consist has also been extracted and copied. The result is that from an operations

93 Hua, T.Q., R.K. Ahluwalia, J.-K. Peng, M. Kromer, S. Lasher, K. McKenney, K. Law, and J. Sinha. 2011. “Technical assessment of compressed hydrogen storage tank systems for automotive applications.”. International Journal of Hydrogen Energy. Volume 36, Issue 4, February. pp. 3037-3049. 94 Comond O, D. Perreux, F. Thiébaud, P. Delobelle, D. Chapelle, P. Robinet, M. Weber, and H. Barthelemy. 2009. Analysis of the fatigue life of hydrogen high pressure tanks. FEMTO-ST - Franche-Comté Électronique Mécanique, Thermique et Optique - Sciences et Technologies. Accessed November 2017. Translated at http://www.escm.eu.org/docs/eccm13/2618.pdf. 95 Parks, G. R. Boyd, J. Cornish, and R. Remick. 2014. Hydrogen Station Compression, Storage, and Dispensing Technical Status and Costs. Technical Report NREL/BK-6A 10-58564. Golden, Colorado: National Renewable Energy Laboratory. May. Accessed November 2017. https://www.nrel.gov/docs/fy14osti/58564.pdf

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT point of view, the number of trains per day to provide the service, and the distance in train-kilometres (km) travelled is exactly the same for both scenarios. The RER model is also increasing the revenue service train-km travelled by 9.3 percent to consider all nonrevenue train movements (including dispatching, rerouting trains for maintenance activities, and run-in to layover facilities) that are required for proper operation. A conservative 10 percent allocation has been considered in the Hydrail Simulation Operational Model, described in Section 4.2.2, to account for nonrevenue train movements. Mixed Fleet Operation RER Scenario 5 is currently considering a fleet mix of bi-level coaches pushed or pulled by either a diesel or an electric locomotive. For bidirectional operation, the last bi-level coach is a cab car, and to provide accessibility, an Americans with Disabilities Act (ADA) coach is inserted in the consist. Consists of 6, 8, or 12 coaches are considered to offer the required service patterns. Also considered in RER Scenario 5 is the introduction of a new fleet of EMU consists of four or eight coaches. Table 4-15 presents the composition of the fleet required to achieve the higher frequency and higher performance considered in RER Scenario 5. Note that the Union Pearson (UP) Express is not presented in this table because there is no modification of its actual service in the Electrification scenario 20-year horizon between 2025-2045.

TABLE 4-15 ROLLING STOCK EQUIPMENT CONSIDERED FOR EACH CORRIDOR Equipment EMU Electric Diesel Coach 4 8 12 6 8 12 Passengers 480 960 1,789 895 1,193 1,789 Lakeshore West YES YES YES - YES YES Lakeshore East YES YES YES - - - Milton - - - - - YES Kitchener YES YES YES - YES Barrie YES YES YES - - - Richmond Hill - - - - - YES Stouffville YES YES YES - - -

The Hydrail fleet mix can also be similar. Four and eight EMUs can find direct replacement with hydrogen multiple units (HMUs). Nonpowered HMUs will carry 150 passengers each, like a standard bi-level coach, while the powered HMUs passenger capacity has been reduced to 90 passengers to allow space for traction powers and HFC components. Since each multiple unit consist is powered at 50 percent, the passenger carrying capacity is the same in the EMU or HMU configuration. Each electric locomotive is replaced by 2 HFC locomotives; therefore, bi-level cab cars are no longer required in a 12-coach consist to offer bidirectional functionality. A standard coach could be used instead, which would offer slightly more seats for each consist. This difference in increased passenger capacity has not been considered in this analysis. For the alternative where diesel locomotives are also replaced with HFC locomotives, the same ratio is used for the replacement. A 6-car consist is pushed and pulled with 1 HFC locomotive, while a 12-car

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT consist is equipped with 2 locomotives. These configurations provide higher acceleration performance than the existing diesel configuration and also provide a better power to weight ratio. Service patterns will also need to be adapted in the Lakeshore West corridors where an eight-car consist is considered. A single HFC locomotive should be designed to efficiently move six coaches. Therefore, the existing 8-car trains could be replaced by a different combination of either 6 or 12 coaches to offer the same or very similar number of seats. As presented in Section 4.2.2.4, there is also an alternative where all EMUs have been replaced by new HFC locomotives pulling standard, nonpowered BL coaches. The proposed replacement was made on a passenger seats equivalent basis. Adaptation of the service patterns will be required to complete the evaluation of this alternative, which is outside the scope of the present study. EMUs could also be eliminated from the Electrification scenario and service offered with an electric locomotive with three, four, six, or seven standard coaches, depending on the number of seats required. The downside of this approach is that, since the locomotive was originally designed for 12-coach operation, it will be overpowered for a smaller consist. From that point of view, the HFC locomotive is better sized for those smaller consist operations. Although EMUs are more flexible to reconfigure from small to larger consist and offer better acceleration performance, they also introduce additional complexity from an O&M standpoint. Since diesel, electric, and EMUs will be operating on the same corridors, this better acceleration will somehow be lost when creating the service timetable. The passenger waiting for a train at any station should not have to remember that at a peak period, the train is an electric locomotive, while at other times of the day, the line could be serviced by a diesel locomotive or an EMU. The passenger is more interested in having a constant service, coming to his or her station every 15 minutes, for example, than the specific performance characteristics of a given type of railway car crossing the station. For that reason, although an EMU may be able to brake and accelerate faster from any station and recover time lost during the operation, it will be limited by the slowest equipment running on the same corridor. Normally, multiple units (MUs) are used to introduce a new service, where the ridership is lower and it is more cost-effective to have a distributed power approach than an over-powered locomotive pulling three or four passenger coaches. This explains why a DMU was the selected technology for the UP Express. With the increase of ridership, more coaches are added to provide the service and, eventually, it becomes more economical to pull those coaches with centralized power or a locomotive. The GO service has already been proven, and high ridership levels are a reality, making the MUs less attractive economically. The existing diesel and electric locomotives considered so far have been designed with the goal of pulling 12 coaches, somehow explaining why EMUs are also considered. The proposed approach of designing a Hydrail locomotive for six coaches also makes the EMUs less attractive. Fewer coaches simplifies the fleet mix and its O&M, and makes better use of the existing BL coaches. Dispatching The dispatching operation, consisting of trains coming out of the layover facilities to gradually feed the daily service activities, will be exactly the same for each scenario. Independently of the fleet mix considered, each train will be prepped for service in a similar manner. Preconditioning of the locomotives and passenger coaches will be performed using wayside power. Predeparture tests could be slightly different, depending of the motive power being used, but should have no significant effect on the dispatching timeline.

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Operating Range Since the service patterns are the same, the only remaining difference between the number of trains that need to be dispatched on any given day is the operating range associated with each technology. Electric locomotives and EMUs do not have any operating range limitations; as long as the power infrastructure operates normally, trains dispatched at the opening of the network could operate throughout the day and clock up to 20 hours of revenue service operation. Diesel locomotive daily hours of operation would be limited by their operating range, which is proportional to the operating power profile and fuel-carrying capacity. For the present operation, centered around a wave operating concept (all trains coming to Union station during AM peak period, and returning wave during PM peak period), the diesel locomotives need to go to layover facilities after the AM peak period until they are dispatched again in time for the PM peak periods. Based on the current LOS, there is sufficient time to refuel the trains during that period; therefore, every train is systematically refuelled every day, even if it only needs 1,500 litres (L) out of an 8,300-L tank. Diesel locomotives are operating an average of 7-8 hours per day, way below their potential operating range. By 2025, the RER program will replace this wave operating concept and will provide a core network that has a train every 15 minutes, all day, while outer parts of the network would be served every 30 or 60 minutes. The diesel trains operating under this new scenario will have extended operating hours every day and will not necessarily be fuelled in the middle of the day. Nevertheless, because a full tank of diesel provides close to 20 hours of normal operation, as long as all locomotives are fuelled every day, the 2025 and beyond proposed plan can be achieved with the existing diesel locomotive operating range. New Diesel-AC locomotives that will be purchased in the future should maintain this range. The HFC locomotives will likely have a shorter operating range than its diesel counterpart. A combination of additional fuelling points at terminal stations and additional rolling stock equipment may be required to erase the effect of this shorter operating range. Although additional rolling stock may need to be dispatched daily, it does not automatically imply a larger fleet. It could be addressed with fewer trains set aside for maintenance activities on any given day, which may be adequate given that the level of maintenance required on HFC-related subsystems is expected to be less than for the diesel equivalent. This could also me made possible by the potentially increased reliability level of HFC over diesel engines. Run-in Operations Run-in operations, consisting of the gradual removal of a train in service during or at the end of the day, when the LOS is reduced or the time to end the service, are also essentially the same for each scenario. This statement is true if the time to recondition the trains at the end of the day is similar for each motive power technology, there is enough time between removal of service until the next dispatch cycle to carry all daily maintenance activities, or both. The major daily maintenance activity that is different between each technology is the fuelling requirement, which is covered in the following subsection. Although each technology has a different cycle time for its fuelling activity, because it can be performed in parallel with other more time- consuming servicing activities that must be done during that period of the day, there should be no impact on the number of rolling stock required to prepare the trains for the next day.

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Degraded Modes of Operation Up to this point in the analysis, only the normal mode of operation has been considered. This section provides a high-level comparison between the electrification and HFC scenarios under a degraded mode of operation. From a system point of view, some elements are identical between both technologies. For example, the rail network and the train control and signalling system are the same, and potential failure of those elements will have the same effect on the rolling stock equipment and overall service delivery. Besides those elements, the rest of the systems are different. Although the reliability associated with the infrastructure (power stations, switching stations, transmission lines, overhead catenary system) essential to the proper operation of electric trains is high and offers some level of redundancy, it does introduce an additional potential for interruption of service. Notwithstanding the initial disruption effect to the existing system operation throughout the construction period (which also requires raising overpasses and station roofs, and possibly modification to the rail alignment), failure of any electrification infrastructure elements will create service disruptions on at least part of the electrified network. Some of the failure modes could introduce performance limitations to electric locomotives and EMUs, or completely stop the service in the affected section of the rail network. Another element that needs to be considered is the additional activities required to maintain this mainline infrastructure. Although some of those activities may be done at night when the system is not operational, some activities will need to be performed during the day and will impose speed restrictions on the portion of the network where the maintenance is carried out. Hydrail also has an infrastructure that needs to be operational and needs to be maintained to produce, store, and distribute the hydrogen required for the trains to operate. Those elements are also subject to some malfunctions or maintenance activities that will limit their operation. The main difference is that the complete system is designed to offer at least 3 days’ of hydrogen storage for the complete fleet of trains, providing more than enough time to perform the necessary system investigation and repairs. Also, independently of the infrastructure design, it will always be possible, although less practical, to proceed with a direct truck to train fuelling scheme, bypassing the complete hydrogen-producing infrastructure if required. Therefore, from an infrastructure point of view and considering the potential impact to the train operation, Hydrail has an overall advantage over electrification. Can this infrastructure benefit also be extended to the rolling stock equipment? To answer this question, the first element to consider is the overall reliability comparison between diesel, electric, and Hydrail locomotives. In recent locomotive design, the main difference within the locomotive propulsion system is the main electricity source, since all locomotives use this primary source to power AC propulsion drive systems. A diesel locomotive will have a diesel engine, cooling system, fuel tank and fuel delivery system, exhaust system, alternator, and associated controls to produce the primary power source. For an electric locomotive, the power source is external; but it needs a pantograph, a transformer, and high- voltage switchgear to harness this external power to the drive system. The equipment required in an electric locomotive is much simpler than its diesel counterpart, is inherently more reliable, and provides a higher power to weigh ratio, leading to better performance. For a Hydrail locomotive, fuel cells, cooling system, hydrogen tank and delivery system, batteries, and associated controls make up the subsystems required to produce the primary source of energy. Although a Hydrail locomotive has

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT yet to be designed, manufactured, and tested, based on the maturity level of all components required to make such a locomotive, its reliability is also expected to be better than that of a diesel locomotive and comparable to electric locomotive reliability. Because it needs to carry its own fuel, similar to a diesel locomotive, a Hydrail locomotive will also not be as powerful as electric locomotive. Nevertheless, besides its intrinsic reliability level, from a degraded mode operation point of view, the Hydrail approach has two major advantages over competing technologies: (1) its redundancy when operating a 12-coach consist because it has 2 locomotives instead of 1; and (2) its leap home functionality, made possible from the onboard batteries. The introduction of EMUs in the fleet mix will decrease the overall reliability of the passenger coaches. At the same reliability level as the locomotive, because of the multiplication of systems in any given consist, up to four propulsion systems in an eight-car EMU or HMU, the overall reliability will be lower. This will be largely compensated by the inherent redundancy of this distributed power approach. For example, losing one propulsion package in an 8-car EMU still maintains 75 percent of the traction capability, reducing the normal operational characteristics, but also limiting the impact on overall system performance. The Hydrail system will also need to address a potential degraded mode of operation. Considering that the rolling stock reliability should be similar to the electric option and better than the diesel option, that it is not directly affected by power generation infrastructure potential failure modes, offers some level of redundancy and leap home capability, it should offer a more reliable system. Extending this approach and eventually replacing all diesel locomotives and eliminating the need for EMU, Hydrail also represents a level of operational simplification that cannot be achieved with the Electrification scenario. Emergency and Rescue Operations Although each system may have a different reliability level, a degraded mode of operation can eventually require emergency or rescue operations to remove the nonworking rolling stock equipment from the rail network. If the electrification infrastructure fails, then rescue can only be achieved using compatible equipment that is not electric. Depending on the extent of the infrastructure failure, more than one train could need rescue from a diesel locomotive. The service could also be temporarily replaced by remaining diesel equipment. The LOS and performance would then be slightly affected. For the most likely equipment-related failures, compatibility between electric and diesel locomotives should allow for appropriate emergency and rescue operation on the electrified portion of the network, which would remain as it is today for the rest of the network. Hot standby trains will need to be considered at strategic layover facilities in the network to provide proper operation during recovery mode. An extra level of complexity will be introduced with the fleet of MUs in the system. Because of the different physical characteristics between locomotives and MUs, it is less likely that compatibility can be achieved between those equipment types. Hot standby trains remain the appropriate response, but this also means the need for two types of train on standby for rescue operations. This will need to be evaluated considering the reliability of each equipment type. The same concept should be used for Hydrail. Similar to the degraded mode of operation presented in the previous section, based on Hydrail’s foreseen reliability level, redundancy, leap mode, and

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT equipment type rationalization, should reduce the frequency of emergency operations and simplify the deployment of hot standby trains. Maintenance The maintenance of the rolling stock equipment can be associated to four main categories: 1. Daily 2. Progressive 3. Corrective 4. Overhaul The first category includes all activities required daily to service each train coming back through run-in operations to be ready for the next dispatching cycle. Cleaning of all passenger coaches, water and waste management, cab cars and power car servicing (including top-up windshield wiper fluid, sand, diesel fuel, and diesel fluid additive for Tier IV engines), and running predeparture tests are likely daily maintenance activities. Progressive maintenance activities are normally established around a 90-day cycle, when the equipment needs to go into a maintenance facility to perform systematic inspection, detection, and correction of emergent failures either before they occur or before they develop into major defects. Based on equipment manufacturer recommendations, the progressive maintenance plan is generally designed to preserve and restore equipment reliability by replacing worn components before they fail. Some activities need to be repeated every 90 days, while others may only need to be done at 180- or 270-day intervals or on a yearly basis; therefore, every 90-day inspection is slightly different but normally requires that the equipment, locomotives, and passenger coaches be removed from revenue service for 3 days. The ideal progressive maintenance program would prevent all equipment failure before it occurs. In practice, this cannot be achieved; therefore, there is always some unplanned maintenance activities or corrective maintenance that need to be performed. The last maintenance category that covers the heavy maintenance activities and overhaul is also a planned maintenance activity. This time, the equipment is removed from service for an extended period, where major subsystems maintenance is addressed. Heating, ventilation, and air conditioning (HVAC); truck; diesel engine reconditioning; and mid-life interior component; replacements are a few examples of activities performed as part of this category. With the introduction of any new equipment or technology, the maintenance plan needs to be revised to include this new equipment. As a result of this review, the cycle time, amount of materials and human resources, required training, procedures, tools, and maintenance facilities will need to be adjusted. Hydrail will not be an exception to this reality. One of the important modifications to the daily maintenance activities is related to the fuelling, which is covered in the next section. The other daily activities will remain essentially the same and are not expected to modify the existing timeline. The progressive maintenance will also be modified and simplified due to ending diesel-related subsystem maintenance. It is too early to determine if this maintenance category for Hydrail trains could be shorter than the existing downtime for diesel trains. Since this cycle is also driven by the passenger coach maintenance cycle, it may not be possible to reduce the progressive maintenance cycle even if Hydrail locomotive maintenance activities take less time. This will be reviewed more closely as part of the pilot locomotive design.

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Based on Hydrail’s expected reliability level, corrective maintenance activities should be positively affected, especially after the technology has been proven in revenue service. Nevertheless, this category of maintenance will still be required. The heavy maintenance or overhaul activities will also be revised and are expected to be simplified. The selection of the Hydrail system components will dictate the overhaul cycle. Fuel cell reconditioning and batteries replacement will be covered in this maintenance category. It is expected that it will take less time to perform those activities than for existing technology, but frequency may be higher. The fuel cell meantime between overhaul is currently around 20,000 to 25,000 hours of operation, which is probably around 3 years of operation, relatively short compared to diesel- and electric-based technology. Batteries replacement will also drive the overhaul timeline. Proper sizing of batteries during the design stage as a compromise between performance, weight, and state of charge will influence this replacement activity. The future development of both fuel cells and batteries should also improve the time between overhaul. Infrastructure and Organizational Modifications Required Table 4-16 presents the expected state of layover and maintenance facilities by the end of 2020. All the sites presented in this table also allows for minor cleaning activities and minor defect repairs, supported by local material and parts storage, except for Oshawa and Milton that do not have that storage capacity. Based on an equivalent LOS, this study considers that the number of tracks at layover and maintenance facilities will be the same between the electrification and Hydrail systems. The capability at each facility is presently under review to verify it will also be adequate to support the expand LOS in 2025. The results of this analysis will also need to be considered for Hydrail. Once Hydrail is introduced, maintenance yard and layover facilities will not need to be modified to include the overhead catenary system currently provisioned for in the Electrification scenario. Although the current height of the maintenance facilities is sufficient to incorporate an overhead catenary system, for safety reasons, the current plan did not include this building modification. Instead, electric trains and EMUs will be pushed in and out of the maintenance facilities by an external source, creating additional operation and limiting the throughput of the maintenance line. Existing interior maintenance tracks are equipped with sensors and extraction fans to remove exhaust from diesel locomotives. The same approach will be used for Hydrail locomotives. Different sensors will be required to detect potential hydrogen leaks, which will trigger extraction fans. The size of the fan should be sufficient but will need to be confirmed. Wayside power is available is all maintenance facilities and most of the layover locations, per Table 4-16. The Union Pearson (UP) Express service track and Oshawa station should be modified to also offer wayside power. This is important to limit the hydrogen consumption during network operation. For the same reasons, any side tracks at maintenance facilities, where the trains will pre- heated or preconditioned before revenue service, should be equipped with wayside power. The maintenance facilities’ existing workforce will need to go through a new training program to work around Hydrail and especially hydrogen-related components. There is already a specific certification program that exists for this technology in Ontario, developed for other industries, that could easily be adapted to the rail industry. During the transition period, until the Hydrail system is fully deployed, it may beneficial to create a specific organization within Metrolinx to concentrate their effort on the successful introduction and maintenance of the specific Hydrail installation and workforce requirement.

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TABLE 4-16 LAYOVER AND MAINTENANCE FACILITIES INSTALLATION Fuelling Sanding Fuel /DEF Direct Truck Fixed Storage for Consist Wayside Storage & Locomotive Storage & Mobile Name No. Tracks Capacity Power Dispensing Access Toilet Servicing Dispensing Dispensing

Barrie 5 8 Yes Yes Yes Yes No No Bradford Station Barrie 2 2 Yes No Yes No No No (temp) Bradford /Barrie 8 8 Yes No Yes Yes No Yes Heritage 8 8 Yes No Yes Yes No Yes Georgetown Station 4 3 Yes No No No No No Kitchener (Temporary) 2 2 Yes No Yes No No No Kitchener Kitchener (Shirley Ave) 4 4 Yes No Yes Yes No No UP Express Service 1 0 No No Yes No No No Track Oshawa Station 2 2 No No Yes No No No Lakeshore East Don Yard 10 10 Yes No Yes Yes No Yes Henry Street 2 2 Yes No Yes No No No

Bathurst North 6 6 Yes No No No No No

Mimico 3 6 Yes Yes Yes Yes Yes No Lakeshore West Hamilton 2 4 Yes No Yes No No No

Lewis Road 8 8 Yes No Yes Yes No Yes

Milton 6 10 Yes No Yes Yes No No Milton Milton Station 2 2 Yes No Yes No No No

Richmond Hill Bethesda 8 8 Yes No Yes Yes No Yes

Stouffville Lincolnville Station 7 7 Yes Yes Yes No Yes Yes

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Fuelling Diesel locomotives presently operating on the network are fuelled every day at one of the three permanent exterior fuelling facilities in Barrie, Mimico, and Lincolnville. In the case of Mimico, all trains coming through the site are first directed to stop at the fuelling station regardless of the tank fuel level. The diesel locomotives operating on the GO network have a fuel tank that can carry up to 2,200 United States gallons (USG), or approximatively 8,330 L of fuel. Based on a witnessed fill rate at the Mimico fuel station of 375 L/min, it would take less than 23 minutes to fill an empty tank. Assuming that this operational process is appropriate to apply to the Hydrail System, we consider that a target fuelling time for a new Hydrail locomotive should be between 20 and 25 minutes. Detailed assessment of modifications required to the existing maintenance facilities and additional review of the maintenance plan will be needed to properly evaluate the impact on Hydrail’s O&M cycle. The revised maintenance approach can also provide opportunities to further optimize the new hydrogen dispensing system. For example, fuelling stations can be designed to fill from both sides of the locomotives at the same time, or maintenance activities like sand refilling, water and waste management, and daily service cleaning could also be done in parallel to either maintain or reduce the existing maintenance cycle time. The existing direct truck to locomotive access points available at most stations on the network could continue to be used for the Hydrail System primarily for emergency situations. 4.2.2 Hydrail System Operation Modelling This study is a preliminary assessment and is subject to some uncertainties in moving the RER network from diesel to electric propulsion, either using track electrification or Hydrail. There are several scenarios for how the RER network will be deployed. This study focusses on RER Scenario 5 and the assumptions of Metrolinx’s published IBC for electrification. It is decidedly a preliminary assessment that deals only with major cost items. One source of uncertainty comes from the make-up of the train consists. With the agreement of Metrolinx, for locomotive-pulled consists, the Hydrail configuration uses a 2-locomotive, 12-coach configuration. This was primarily chosen to provide sufficient space for on-board hydrogen storage for a full-day’s operation without refuelling96. Moreover, this configuration also offers operational flexibility of deploying half-sized trains for off-peak service97. RER Scenario 5 also includes self-propelled double-deck EMUs, and the cost comparison for this situation is less straightforward, since fuel storage and fuel cells would replace electrification- associated power equipment. Fuel cells are notably compact, but hydrogen fuel storage is bulky. As for most other gas-fuelled passenger-transport vehicles, single-deck EMUs can use the space above the carriage roofs for fuel storage, but the limitation of overhead clearance constrains this option with double-deck EMUs. So, the precise effect of fitting Hydrail into double-deck EMUs has still to be determined and could reduce passenger-carrying capacity. This introduces some uncertainty into the cost comparison.

96 A single locomotive design that has sufficient space for the required hydrogen storage remains a possibility, but identifying such a design is a subject for subsequent study. 97 Hoffrichter, Andreas, Stuart Hillmansen, and Clive Roberts. 2015. Conceptual propulsion system design for a hydrogen-powered regional train. Accepted on April 11, 2015. Edgbaston, Birmingham: Birmingham Centre for Railway Research and Education, University of Birmingham.

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With the Hydrail System, the unprecedented scale of fuel-cell power that would be deployed on individual trains brings some cost uncertainty, even for this modular technology. However, that uncertainty has to be seen in the context of steadily declining costs for the key equipment components, a trend expected to continue. Operating cost estimates are also subject to uncertainty, since they depend on forecasting electricity prices over the medium and long terms. Unlike track electrification’s electricity costs, which have no scope for optimization, the Hydrail System can respond to an electricity price structure that is different from today’s because of its intrinsic ability to switch its demand for electrical energy, to take advantage of the lowest prices of electricity each day. 4.2.2.1 Electricity Supply and Costs At the centre of the case for Hydrail and its costs is the supply and price of electricity, either from the Ontario electricity grid or from electrical generating stations without the market price structure. Ontario Electrical Grid Current Energy Supply 98 Ontario’s electricity supply is predominantly carbon dioxide (CO2)-emissions-free (or green energy) . Here, green energy refers to various energy and electricity conversion processes that rely on energy sources in nature that do not contribute to the emission of CO2 from fossilized carbon-based fuels, such as coal, natural gas, and crude oil. Ontario’s electricity demand fluctuates both daily and seasonally, as shown on Figure 4-16.

FIGURE 4-16 MONTHLY AVERAGE ELECTRICITY IN MW FROM WIND AND SOLAR INSTALLATIONS IN ONTARIO FOR 2016 1600 70

1400 60 1200 50 1000 40 800 30 600 20 400 200 10 0 0

Average electricity generated (MW) WIND SOLAR

98 Independent Electricity System Operator (IESO). 2017b. “Generator Output and Capability (GOC) Tables.” Data Directory. Accessed October 2017. http://ieso.ca/en/power-data/data-directory

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Supply has difficulty in matching demand, which is illustrated as follows:  Nuclear plant output is broadly constant.  Wind output is variable (Figure 4-16) both:  Over short intervals  Seasonally99, the IESO’s Hourly Ontario Energy Price (HOEP) values show that winter monthly averages exceed summer averages by about a factor of 2100.  Solar output is variable (Figure 4-16) both:  Over short intervals  Seasonally, when monthly averages vary from a spring peak to a fall low by about a factor of 2.5 101. In recent years, the proportion of wind and solar generation in Ontario has been increasing, and the proportion of time when the Ontario grid has excess electricity has been rising. The proportion of time when HOEP has negative or zero value over the last 6 years is shown on Figure 4-17. This reflects a rising surplus of generating capacity from nuclear and renewable sources that cannot readily be curtailed. The grid is burdened with an unwanted supply of electricity of no value that it still has to pay the suppliers for.

FIGURE 4-17 TREND OF ONTARIO GRID HOEP

14%

12% Neg. HOEP % Zero HOEP %

10%

0% 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

The IESO HOEP data show that the price of electricity tends to follow demand, and experiences morning and evening peaks.

99 Independent Electricity System Operator (IESO). 2017c. “HOEP_2002-2016 table.” Data Directory. Accessed October 2017. http://ieso.ca/en/power-data/data-directory, average of the three longest-established wind farms 100 Independent Electricity System Operator (IESO). 2017c. “HOEP_2002-2016 table.” Data Directory. Accessed October 2017. http://ieso.ca/en/power-data/data-directory 101 Natural Resources Canada (NRC). 2017. Photovoltaic and solar resource maps. (Note that high tilt minimizes seasonal variation.) March 20. Accessed October 10. http://www.nrcan.gc.ca/18366

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Electricity Price Estimates for the Hydrail System

The IESO data (Figure 4-18) show that Ontario’s grid FIGURE 4-18 AVERAGE CONTRIBUTION TO is supplied by generating processes that are ONTARIO ELECTRICITY SUPPLY IN 2016 BY distinctively unusual in two ways: SOURCE TYPE 1. Over 90 percent of actual generation is produced Biomass, Gas‐fired, 0.1% 9.9% by green (non-GHG-emitting) sources Solar, 0.3% 2. Much of this green capacity is not controllable (wind or solar), or is slow and expensive to adjust Hydraulic, (nuclear) 23.5% Nuclear, Not unique to Ontario but of similar importance: 60.0% Wind,  Variability of demand exists on almost every time 6.2% scale from night and day to seasonal. Adding together these three factors, the Ontario grid experiences very substantial surpluses of green electricity every day. The cost of this unwanted electricity is recovered by the Global Adjustment (GA). The cost of electricity for either Hydrail or track electrification is crucially important to the choice between the two technologies. The entire premise of Hydrail is that hydrogen will be generated by accessing this unwanted electricity. In storing electricity as hydrogen, it will time-shift energy demand by tapping into the unwanted surplus. Consequently, it is our understanding that electricity for Hydrail would not be subject to the GA. In contrast, the power required for the Overhead Contact System (OCS) does not alleviate the supply- demand imbalance and would, therefore, likely be subject to GA. After discussion with IESO102, we have costed the operational cost of the Hydrail System based on IESO’s actual hourly HOEP figures for 2016, plus the additional charges for distribution and regulation. Our estimates of electricity costs to produce hydrogen are based on selecting times with the lowest electricity values for hydrogen production. The results of this analysis are shown in Table 4-17, in the row identified as IESO set.

TABLE 4-17 HYDRAIL CAPITAL AND OPERATING COST IMPACT ON UNIT COST OF HYDROGEN Storage Electrolyzer Capital Electricity Total Elec. Price Cost Cost Cost Cost Cost H2 Cost percent $/MWh $m $m $/d $/d $/d $/kg Change

Expand 20 24.0 165.1 62,154 70,253 132,407 3.310 90.1 32.53 percent IESO set 34.29 25.6 187.5 70,047 76,961 147,009 3.675 100.0 Compress 20 25.6 165.1 62,680 89,945 152,626 3.816 103.8 41.64 percent Notes: $/MWh = dollar per megawatt hour $/d = dollar per day $/kg = dollar per kilogram

102 Fox, Conrad, IESO, Planner, Resource Integration. 2017a. Personal communication (email) with Nirmal Gnanapragasam Canadian Nuclear Laboratories. September 22.

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However, whether 2016 prices will precisely reflect electricity prices from 2024 on Table 4-18, to a large extent, uncertain because, on the generating supply side, there are planned additions of capacity and, on the demand side, there is the potential for growth in time-sensitive demand from vehicles powered either by electric batteries or hydrogen. A report by Strategic Policy Economics103 argues the case for hydrogen storage in a seasonal timeframe and concludes that: “The Hydrogen Economy can provide capacity and reliability benefits to the electricity system … to smooth the seasonal differences …”. The basic premise of this report is that the imbalances are going to persist. The Hydrail approach takes this principle further by smoothing the imbalances over days rather than seasonally. One variable that might bear on the cost of hydrogen for Hydrail would be a future compression or spread of the variation of hourly electricity costs around the mean. To examine this, the 2024 base case was re-optimized with the same average electricity cost but with all HOEP values moved either 20 percent closer to the mean or 20 percent away from the mean. The results are also provided in Table 4-17. The difference between the 2016 spread in HOEP prices and those projected for 2024 by IESO is about 25 percent compression, so the range in Table 4-17 is well within the bounds of possibility. The contrast between the cases with the 20 percent expansion and the 20 percent compression of prices shows that effects of compression are diminishing, and further compression would be unimportant. 4.2.2.2 Hydrail System Costs and Scenarios Hydrogen Handling Phases: Gas or Liquid For both capital and operating costs, the form in which hydrogen is stored—either as liquid hydrogen (LH2) or CGH2)—has bearing on this uncertainty because liquid hydrogen is 80 percent denser than gas at 700 atmospheres. The disadvantages of using LH2 are discussed in Section 4.1.4.1, but its use has been retained as an option for costing. Cost estimates for four hydrogen delivery configurations for Hydrail have been prepared as follows:  Central production with pipeline delivery as gas throughout the RER network  Central production with delivery by truck as gas

 Central production with delivery by truck as LH2  Distributed onsite production as gas Producing and Costing Hydrogen Hydrogen requirements are estimated for RER Scenario 5’s planned train service pattern. The cost of producing hydrogen is based on the hourly costs of HOEP (plus fixed electricity charges), the cost of electrolysis installations ($655/ kilowatt [kW]104 at a nominal 2.2 A/cm2 of current density), and the cost of hydrogen storage ($1,397/kg105). A minimum of these cost inputs is found by varying storage and electrolysis capacity, and a complex set of conditions to determine when hydrogen will be produced and at what rate (varied by changing the current density, which modulates the cell

103 Brouillette, Marc. 2016b. Ontario’s Emissions and the Long-Term Energy Plan; Phase 2 Meeting the Challenge. Strategic Policy Economics. December. Accessed October 2017. https://www.generationenergy.ca/images/documents/Strapolec percent20- percent20Ontarios_Emissions_and_the_LTEP_-_Ph_2_Report_Final_December_2016.pdf 104 Cargnelli, Joseph, Chief Technology Officer, Hydrogenics. 2017. Personal communication (via teleconference) with Nirmal Gnanapragasam Canadian Nuclear Laboratories. August 16. 105 Compiled from data sent by Hexagon Composites, email dated September 16, 2017.

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TABLE 4-18 LARGE INDUSTRIAL PRICE FORECAST VALUES FROM IESO MODULE 4 All $/MWh 2016 2024 2032 HOEP 28 56 67 Transmission 12 14 16 Regulatory 7 7 8 DRC 7 - - GA 43 35 32 Notes: - = not applicable DRC =Distribution and Regulatory Charges

The newer IESO set was used for this assessment. The DRC for either 2024 or 2032 were added to IESO’s projected HOEP. GA costs have been excluded based on the understanding that they will not be applied to applications of RER’s nature. The DRC cost element in electricity charges ceases after 2018. Water requirements to produce hydrogen are for direct conversion plus evaporative losses to dissipate heat through a cooling tower; details of the cooling tower have not been assessed, but this is a minor item of equipment. Hydrogen Use Hydrogen produced by electrolysis will move to Hydrail-powered trains in the form either of compressed gas or LH2. For the main deployment of storage, compressed gas would be stored at 200 to 300 bar in conventional, high-pressure steel tanks, and LH2 in double-walled vacuum vessels. Four options have been costed: 1. As gas with production at a central site remote from the refuelling points and then delivered to the train refuelling points by a pipeline. 2. Same as 1., but with gas delivered by tube-trailer-carrying trucks. 3. Same as 1., but with liquid hydrogen delivered by truck; in this case, the costs of liquefaction have been added. A liquefaction plant would run continuously, and the additional electricity is costed at the average electricity price, including GA. 4. As gas produced by electrolysis close to the train refuelling points. (Because electrolysis is intrinsically modular, production could be divided between several sites with little impact on cost.)

106 Cargnelli, Joseph, Chief Technology Officer, Hydrogenics. 2017. Personal communication (via teleconference) with Nirmal Gnanapragasam Canadian Nuclear Laboratories. August 16. 107 Fox, Conrad, Planner, Resource Integration, IESO. 2017b. Personal communication with Nirmal Gnanapragasam Canadian Nuclear Laboratories. October 8.

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In either gas or liquid form, storage capacity (as days of RER Hydrail demand) is determined by the hydrogen production optimization. Storage for an additional 1 day of demand is added to provide overnight refuelling of the RER fleet. The land areas for these hydrogen-supply options have been estimated and costed. These costs are preliminary, as the actual location of the generation, storage, and dispensing facilities are unknown. Hydrail Operational Scenarios – Description There are several operational scenarios being considered for Hydrail, taking advantage of flexibilities that hydrogen technology must offer for the rail application. To simplify discussions, the Hydrail operational scenarios are grouped in various ways: 1. Infrastructure Configuration Scenario: The Hydrail system as shown on Figure 4-13 comprises various subsystems that may or may not be required, depending on the nature of hydrogen required (gaseous vs. liquid) and the option of producing hydrogen locally or remotely. 2. 2024-Cost Case: This is the high-cost scenario where all the Hydrail infrastructure and vehicle components assume the start of the RER Scenario 5 (2024) costs—though these are projected to decline as the volume of production of these components grows. 3. Future-Cost Case: This is a low-cost case where the component costs presume projected future costs reflecting both design advances and increasing volume of production as demand from other applications of hydrogen technology grow. The other applications are discussed in Section 3.3, all increasing production of similar components for hydrogen-fuelled cars, buses, transport trucks, ships, and forklifts. Demand from stationary applications for the electrical grid and for renewable energy storage, CHP, and back-up power has already been expanding. 4. Low-Power Case: The base-case assumption uses a locomotive peak power of 7,500 horsepower (hp) (5,593 kW). This requirement is derived from the initial acceleration required for a full train consist. It may be too large, so a low-power case was included at 6,500 hp (4,847 kW) to show the sensitivity to this variable. 5. Fleet Mix Scenario: Since Hydrail would use 2 locomotives for every 12 bi-level coaches, this allows an option of splitting the train consist into two 1+6 (as discussed in Section 4.1.8.3), resulting in the same economy of operation as EMUs. There are two fleet-mix options: (1) combination of locomotives and EMUs in the fleet; and (2) only locomotives in the fleet. 6. RER Scenario 4108: RER Scenario 5 deploys Hydrail exclusively on Lakeshore East, and a mix of Hydrail and diesel on Lakeshore West, Barrie, Stouffville, and Kitchener. Whereas, RER Scenario 4 is a more extensive deployment with Hydrail exclusively on all GO corridors. Equipment Capital Cost Sensitivities Costs for various equipment and subsystems within the Hydrail system is estimated based on cost factors available from hydrogen technical literature and from market relevant data obtained via stakeholder engagements. These factors for the two cost cases described earlier for key equipment are provided in Table 4-19.

108 Metrolinx. 2015. GO RER Initial Business Case. Accessed October 2017. http://www.metrolinx.com/en/regionalplanning/projectevaluation/benefitscases/GO_RER_Initial_Business_Case_EN.pdf

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TABLE 4-19 EQUIPMENT CAPITAL COST FACTORS FOR 2024 AND FUTURE-COST CASES Fixed Infrastructure Equipment Costs Vehicle Equipment Costs Dispenser 700-bar Capital Cost Sensitivity Electrolyzer 200-bar 850-bar + Cooling Fuel cell Batteries tank of Principal Equipment ($/kWe) tank ($/kg) tank ($/kg) ($m/unit) ($/kWe) ($/kWh) ($/kg) 2024-cost case 823 266 1396 1.09 1197 845 1087 Future-cost case 655 160 1117 0.87 720 676 870 Reduction (%) 20 40 20 20 40 20 20

A main attraction of Hydrail is that it is an assembly of components from a suite of relatively young technologies whose costs have been falling steadily over time and are expected to continue to fall. This is particularly true of the PEM technology (for both the electrolysis and fuel cell equipment) where Ballard109 has supplied the projections for fuel cell costs, as shown on Figure 4-19.

FIGURE 4-19 FUEL CELL SYSTEM COST CHANGES 2,500 2024 cost‐case

2,000 Future cost‐case

1,500

1,000

Fuel Cell Cost ($/kWe) 500

0 2015 2020 2025 2030 2035 2040 2045 2050

For the 2024-case, this study used 1197 $/kWe, as provided in Table 4-19. While that looks somewhat high for 2024, the Ballard numbers could themselves not fully reflect the economies of scale in fuel- cell production. In 2015, the U.S. Department of Energy (DOE) estimated110 current costs for manufacture of PEM fuel cells in very large numbers ranging from:  US$280/kWe for 20,000 units  US$60/kWe for 100,000 units  US$53/kWe for 500,000 While those numbers look highly optimistic, they indicate the likely trend of prices as production of PEM fuel cells expands to support other transportation applications using hydrogen.

109 Campbell, R., Chief Commercial Officer, Ballard Power. 2017. Personal communication with Nirmal Gnanapragasam Canadian Nuclear Laboratories. October 27. 110 Marcinkoski, Jason, Jacob Spendelow, Adria Wilson, and Dimitrios Papageorgopoulos Fuel Cell System Cost - 2015. DOE Hydrogen and Fuel Cells Program Record 15015. September 30. Accessed November 2017. https://www.hydrogen.energy.gov/pdfs/15015_fuel_cell_system_cost_2015.pdf.

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Broadly, the assumptions made in costing the main components of the Hydrail system seem likely to be conservative. Hydrail Vehicle Cost Breakdown There are two types of Hydrail vehicles similar to the rail vehicles in existence: locomotives and EMUs. The costs of various vehicle types in the IBC are provided in Table 4-20.

TABLE 4-20 COST OF VEHICLE TYPES111 Costs Vehicle Type ($m) Diesel locomotive 3.5 Discount for nondiesel locomotive platform (Hydrail) 1 Electric locomotive 6.0 Bi-level coach 3.2 EMU 5.5 Discount for nonelectric EMU platform (Hydrail) 0.5 Hydrail locomotive 6.4 HMU 6.8 Notes: HMU = hydrogen multiple unit

The diesel locomotive is used as the reference for the Hydrail locomotive in the table. Based on discussions with rail vehicle experts, the cost for electric locomotives listed in the IBC at $6 million is quite low. To address this deficiency and enable a like-for-like comparison to the Hydrail locomotive, the cost of diesel is reduced by half from $ 7 to 3.5 million, as per Table 4-20. From the above table, the cost of a Hydrail locomotive is the result of: 3.5-1+3.86 = $6.4 million. Note here that 3.86 is the cost of the hydrogen equipment onboard the locomotive, as shown on Figure 4-20.

111 Metrolinx. 2015. GO RER Initial Business Case. Accessed October 2017. http://www.metrolinx.com/en/regionalplanning/projectevaluation/benefitscases/GO_RER_Initial_Business_Case_EN.pdf

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FIGURE 4-20 VEHICLE COST BREAKDOWN OF LOCOMOTIVE HYDROGEN COMPONENTS

3.8 M$

28% Hydrogen Fuel Cell System per Vehicle Battery System per Vehicle 52% Hydrogen Storage System per 20% Vehicle

From the same table, the cost of an HMU, or the Hydrail equivalent of an EMU, is the result of 5.5-0.5+1.75 = $6.8 million. Here, $1.75 million is the cost of the hydrogen equipment onboard the HMU, as shown on Figure 4-21.

FIGURE 4-21 VEHICLE COST BREAKDOWN OF HMU HYDROGEN COMPONENTS

20% 1.75 M$

Hydrogen Fuel Cell System per Vehicle Battery System per Vehicle 57% 23% Hydrogen Storage System per Vehicle

4.2.2.3 Hydrail Operational Simulation Model: Design and Characteristics The Hydrail operational model is designed based on techno-economic assessment capabilities for the individual subsystems, as shown on Figure 4-13. The design of the Hydrail Operational Simulation Model is summarized by the flowchart shown on Figure 4-22.

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FIGURE 4-22 HYDRAIL OPERATIONAL SIMULATION MODEL DESIGN

Key Model Setup for Electricity Price Optimization This section explains how the CNL Hydrail Model operates to minimize the cost of electricity. It gives a sense of the level of details involved in the techno-economic estimates for the GO Hydrail System. The objective of the optimization process is to produce hydrogen at the lowest possible cost, taking into consideration both the price of electricity (the HOEP set by the IESO) and the amortized cost of capital. Actual HOEP values for 2016 are the basis used for this optimization. Other cost factors, such as the levies for distribution and administrative costs, can be added to the HOEP: HOEP+. These HOEP+ values are deployed in an Excel spreadsheet with one row for each hour of the year.

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At the two extremes:  One could deploy a massive installation of capital equipment to produce a year’s supply of hydrogen in the single hour of lowest HOEP+ and store it for the entire year’s consumption.  One could produce hydrogen continuously with a minimum of capital equipment and only enough storage capacity to provide for a concentrated daily period of train refuelling. The optimized solution lies between those two extremes, deploying enough electrolysis cell and storage capacity to produce hydrogen intermittently to take advantage of periods with low HOEP+. Because HOEP follows a highly erratic pattern, there is no smooth function to determine the optimum. Instead, the optimizing model allows the user to search for an optimum between the two extremes by varying the sizes of the electrolysis equipment and storage capacity. The user also has a series of operating variables that are set to determine whether hydrogen should be produced depending on HOEP+ and the level of hydrogen in storage. A final variable allows operation of the electrolysis equipment at a higher current density up to a specified maximum; this is intended to allow the system to leverage its advantage when HOEP+ is notably low, even though higher current density raises the electricity consumption to produce a unit of hydrogen. The model tracks the quantity of hydrogen in storage (expressed in hours of average demand) and uses this to determine the minimum current HOEP+ value that will be accepted for hydrogen production. For an acceptable solution, the quantity of hydrogen in storage must always meet refuelling demand; refuelling is assumed to occur uniformly between midnight and 6 a.m. Hydrogen production is curtailed so that the storage capacity is never exceeded. On the assumption that hydrogen production will not change electricity prices, the cost of producing hydrogen by electrolysis is assumed to be indifferent to how much needs to be produced; any desired quantity is obtained by linear scaling. Optimization of parameters listed and referenced in this section allows the user to set two physical variables: (1) the quantities of electrolysis equipment, and (2) the hydrogen storage capacity. The other parameters determine when the electrolyzers will draw power. Basically, there are three bands of electricity price: (3) is a basic low price; (4) is a higher price if the storage level (5) is running low; and (6) is a storage level that is considered so low that production of hydrogen will occur at any HOEP+. (7) allows the cell current density to be raised to up to three times the nominal density. This produces hydrogen in proportion to the current density, but the voltage rises with current density according to a formula supplied by Hydrogenics; power used is current density multiplied by voltage. An optimization set is indicated and disqualified if, at any point in the year, the hydrogen in storage drops to zero. Production is curtailed or switched off when storage is full. The parameters on the System tab of the Hydrail Model are: 1. Available quantity of electrolysis equipment (a multiple of the requirement for 24 hours per day, 7 days per week [24/7] continuous production) 2. Available quantity of hydrogen storage (in hours of average demand) 3. A threshold electricity price below which hydrogen can always be produced ($/kWh), subject to space in storage being available 4. A higher threshold electricity price below which hydrogen can be produced ($/kWh) if … 5. … hydrogen storage is less than specified percentage of storage capacity 6. An extreme low level of storage (in hours), below which electricity at any price will be accepted

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7. A threshold electricity price below which the cell current density can be raised from its standard level of 2.2 A/cm2 for a PEM electrolyzer to as high as ... 8. … a (higher) current density level with the power consumption adjusted according to PEM electrolyzer characteristics supplied by Hydrogenics. Variables 3 to 8 determined the rate at which hydrogen should be produced in any hour-long period at a rate that reflected available storage space and current HOEP+. The rate ranged from zero (when the electricity price was high and storage levels acceptable), to a standard rate (when considerations of electricity price and storage justify production), to an augmented rate with a higher current density (when the electricity price was acceptably low). The variables were adjusted manually to search for the best result. Any optimization unable at any time to meet fuelling demand is alarmed and rejected. The eight variables are adjusted manually, usually (but not necessarily) to produce the lowest overall cost of electricity plus capital recovery. As an example, the average daily distribution of the hydrogen production for Hydrail in the year 2024 would look something like that shown in Figure 4-23.

FIGURE 4-23 DAILY HYDROGEN PRODUCTION REFLECTING THE USE OF CHEAPER ELECTRICITY PRICE PERIODS STARTING IN 2024 16%

14%

12%

10%

Percentage of Daily Production 2%

0% 1 2 3 4 5 6 7 8 9 101112131415161718192021222324

Hour of the day

4.2.2.4 Hydrail Operational Scenarios – Results Results from the Hydrail Operational Simulation Model were generated for the scenarios discussed earlier. Here, the costs provided do not include any financial assumptions and conditions, so they are direct costs (without any discounting for future time periods), mainly based on equipment cost factors and electricity pricing. These are presented here to highlight the difference between various options that are available within the Hydrail infrastructure for both fixed and mobile assets. Infrastructure Configuration Scenario The Hydrail System configuration involves locating and grouping fixed subsystems that take advantage of some characteristics of hydrogen and relevant equipment that handles hydrogen. Table 4-21 shows the results of four configuration scenarios for the 2024-cost case.

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The hydrogen and water requirement shown in the table are the same for all scenarios. The water consumed by the Hydrail system would be equivalent to about 0.04 percent of the daily water consumption by the City of Toronto. Most of this water would return to Ontario and the Great Lakes region via rainfall as the trains operate on the GO network every day using the hydrogen produced from this water.

TABLE 4-21 COMPARISON OF INFRASTRUCTURE CONFIGURATION OPTIONS Infrastructure Configuration Scenarios, 2024-cost Case Central production + Central Production + Truck Onsite Parameters Unit Pipeline distribution Distribution Production

Hydrogen phase Gas Gas Liquid Gas Hydrogen required tpd 40 40 40 40 Water required tpd 402 402 402 402 Electricity required GWh/d 2.2 2.2 2.7 2.2 Electricity cost $K/d 90.3 91 127 91 Hydrogen cost $/kg 4.2 3.8 5.1 3.5 Total operating cost $m/y 33 37 47 34 Pipeline length, total km 367 0 0 0 No. of tanker-trucks No. 0 83 13 0 Electrolyzer size (total) MW 250 250 250 250 Land area required m2 23721 15048 4686 16166 Production equipment $m 211 211 211 211 Production storage $m 59 58 227 58 Hydrogen distribution $m 205 24 14 0 Refuelling storage $m 73 68 73 68 Dispensing equipment $m 48 48 54 48 Notes: $K/d = thousand dollars per day $m/y = million dollars per year GWh/d = gigawatt hour per day m2 = square metre tpd = tonne per day

The results for the four configuration scenarios are distinct, and some aspects are discussed here: 1. Central production with pipeline distribution: There is about 367 km of pipeline, representing the physical length of the GO corridors within the RER Scenario 5, on the assumption that hydrogen could be made available anywhere on the entire network. In reality, this number would be different, as we would determine more details on the location of production as the next step. The land area for this scenario is larger than others due to the lower pressure of hydrogen that the pipeline could accommodate; thereby, increasing the number of storage tanks.

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2. Central production with truck distribution for gaseous hydrogen: There are about 83 trucks (each carrying about 800 kg of hydrogen) required each day to transport the 40 tonnes of hydrogen produced to the various refuelling locations. While this is cheaper than the pipeline option for gas, having these many trucks on the road every day increases the risk for supply disruption. 3. Central production with truck distribution for liquid hydrogen: The number of trucks is down to 13 in this scenario, as each liquid hydrogen truck could carry about 4,200 kg of hydrogen. But this option puts a huge penalty on the Hydrail system energy requirements from 2.2 to 2.7 GWh/d, an increase of 18 percent of daily electricity consumption. The storage tanks are also specialized, which increases the cost of storage by 74 percent. However, this option requires the lowest land area due to the higher density of storage. 4. Onsite production: This has the lowest cost of the four scenarios, as the cost for distribution is discounted. If the land area required (16,166 m2) is available at or near the site of the refuelling or dispensing facilities, then this could be the preferred option for Hydrail infrastructure. Cost and Timeframe Scenarios: 2024 and Future Cost Cases As discussed earlier in Section 4.2.2.2, the capital cost of hydrogen equipment used in various Hydrail subsystems is changing with time due to the evolution in the technology and the volume of production of this equipment. Using the two cost cases in the Hydrail model, the reduced costs for the future-cost case are provided in Table 4-22 for the onsite production scenario. Note that the deployment of the vehicles in the fleet would continue until 2044 (based on train service pattern), so a comparison is provided for the two cost cases to that timeframe, as well.

TABLE 4-22 COMPARISON OF TIME-BOUND COSTS Cost and Timeframe Scenarios (Configuration: Onsite Production, Gas phase) 2024, 2044, 2024, 2044, Parameters Unit 2024-cost 2024-cost Future-cost Future-cost Hydrogen required tpd 40 48 40 48 Water required tpd 402 484 402 484 Electricity required GWh/d 2.2 2.5 2.2 2.5 Electricity market price $/MWh 34.2 48.4 34.2 48.4 Electricity cost $K/d 90.9 122.5 90.9 122.5 Water cost $K/kg 1.2 1.5 1.2 1.5 Hydrogen cost $/kg 3.5 3.5 3.3 3.3 Total operating cost $m/y 34 41 34 41 No. of locomotives No. 70 88 70 88 No. of powered EMUs No. 42 42 42 42 Land area required m2 16166 19467 16166 19467 Production equipment $m 211 254 168 203 Production storage $m 58 70 45 54 Refuelling storage $m 68 97 57 81 Dispensing equipment $m 48 65 38 52

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Between the 2024-cost and future-cost cases (columns 3 and 5 in Table 4-22), the production subsystem cost is reduced by 20 percent; production storage by 23 percent; refuelling storage by 16 percent; and dispensing equipment by 20 percent. There is approximately a 16 percent reduction in costs for the powered vehicle fleet – Hydrail locomotives and drive EMUs (not shown in the table). These reductions would only be realized for equipment purchased after the initial Hydrail infrastructure, which is set at the 2024 costs. The reduction would affect the additional infrastructure required to support the progressive increase in vehicle fleet by 2044 and any replacements made during this time and beyond. The fleet addition reflected for the 2044 case, with 18 additional locomotives, is presented in the IBC report112. It is also important to remember that the number of HFC locomotives is twice the number of electric locomotives in the IBC report. However, the additional requirement for hydrogen of about 8 tpd for 2044 is reflective of the train service pattern for each corridor, which could be indicative of a higher number of trains being added to the corridors. Based on the service pattern used in the Hydrail Operational Simulation Model, the addition of trains extends beyond 2030, up to 2044 in some corridors. In this respect, the Hydrail estimates are higher than the electrification (OCS) ones beyond the 2030 timeframe, which requires careful consideration when a comparison of lifetime costs is made. Peak Power Scenario The hydrogen requirement and every other aspect of the Hydrail system was deduced based on the peak and average power requirements for the locomotives and EMUs. When the peak power is adjusted without much sacrifice on the acceleration of the entire train, the change in the system and cost parameters are highlighted in Table 4-23. A 20 percent reduction in peak power between the two cases: 7500 and 6000 hp, respectively, shows a significant reduction in costs and energy requirements, for a 11 percent reduction in the acceleration of the train.

TABLE 4-23 COMPARISON OF PARAMETERS FOR PEAK POWER CHANGE IN POWERED VEHICLES Peak Power Scenarios (Onsite Production, Gas Phase, 2024, 2024-cost) Parameters Unit 7500 hp 6000 hp Reduction (%) Hydrogen required tpd 40 32 20 Water required tpd 402 322 20 Electricity required GWh/d 2.2 1.8 20 Electricity market price $/MWh 34.2 34.2 0 Electricity cost $K/d 90.9 72.8 20 Water cost $K/kg 1.2 1.0 20 Hydrogen cost $/kg 3.5 3.5 0.5 Total operating cost $m/year 34 27 20 No. of locomotives No. 70 70 0 No. of powered EMUs No. 42 42 0 Peak Velocity kph 70 63 11 Acceleration m/s2 0.33 0.29 11 Land area required m2 16166 12941 20

112 Metrolinx. 2015. GO RER Initial Business Case. Accessed October 2017. http://www.metrolinx.com/en/regionalplanning/projectevaluation/benefitscases/GO_RER_Initial_Business_Case_EN.pdf

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TABLE 4-23 COMPARISON OF PARAMETERS FOR PEAK POWER CHANGE IN POWERED VEHICLES Peak Power Scenarios (Onsite Production, Gas Phase, 2024, 2024-cost) Parameters Unit 7500 hp 6000 hp Reduction (%) Production equipment $m 211 169 20 Production storage $m 58 47 19 Refuelling storage $m 68 55 19 Dispensing equipment $m 48 32 33 Fuel cell size, locomotive MW 1.68 1.34 20 percent Fuel cell size, EMU MW 0.84 0.67 20 percent Notes: kph = kilometre per hour m/s2 = metre per square second

The train consist considered for this scenario is made up of 2 locomotives pulling 12 bi-level coaches with all seats occupied by passengers, with a total of 882 tonnes of gross weight. The time to accelerate was set at 60 seconds. If the time savings to passengers is calculated and weighed against the cost savings to the Hydrail System for a slightly slower commute, then the peak power comparison should be scrutinized further. Note that the acceleration numbers chosen here are arbitrary just to show the impact of peak power on the acceleration and the entire system. Fleet Mix Scenario The Hydrail fleet mix is included as a scenario and follows the discussions in Section 4.1.8.3, where having 2 locomotives with 12 bi-level coaches (2+12 consist) was flexible enough to be used as 1+6 consist during off-peak times of rail operations within the GO corridors. Table 4-24 provides a comparison between the fleet with a mix of locomotives and EMUs versus a fleet with only locomotives.

TABLE 4-24 COMPARISON OF FLEET MIX SCENARIOS, LOCOMOTIVES, AND EMUS Fleet Mix Scenarios (Onsite Production, Gas Phase, 2024, 2024-cost) Locomotives and Parameters Unit EMUs Locomotives Only Change (%) Hydrogen required tpd 40 40 0 Water required Tonne/day 402 402 0 Electricity required GWh/d 2.2 2.2 0 Electricity market price $/MWh 34.2 34.2 0 Electricity cost $K/d 90.9 90.9 0 Water cost $K/kg 1.2 1.2 0 Hydrogen cost $/kg 3.5 3.5 0.0 Total operating cost $m/y 34 34 0

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TABLE 4-24 COMPARISON OF FLEET MIX SCENARIOS, LOCOMOTIVES, AND EMUS Fleet Mix Scenarios (Onsite Production, Gas Phase, 2024, 2024-cost) Locomotives and Parameters Unit EMUs Locomotives Only Change (%) No. of locomotives No. 70 81 -16 No. of powered EMUs No. 42 0 100 Land area required m2 16166 16166 0 Production equipment $m 211 211 0 Production storage $m 58 58 0 Refuelling storage $m 68 68 0 Dispensing equipment $m 48 48 0 Powered vehicles $m 960 515 46

The biggest change is in the powered vehicles’ cost, with the locomotives-only option providing a saving of 46 percent when compared to the initial capital cost of the Hydrail system at the 2024 timeframe using the 2024-costs. The significance highlighted here is an indication to scrutinize this option of having only locomotives for the Hydrail system, provided the locomotives could achieve a similar time savings as purported to be achieved using EMUs. RER Scenario 4 Option RER Scenario 4 assumes that the entire GO network in the current layout would be electrified and in 2024 timeframe and would have a mix of existing diesel-powered vehicles and hydrogen- or electric- powered vehicles in the fleet. The comparison of results between Scenarios 4 and 5 are provided in Table 4-25. The addition in the hydrogen, energy, water, and operating requirements for Scenario 4 implies the scope of the full GO network electrification. The additional capital required for the fixed infrastructure is also significant. Due to the modular nature of the technologies involved, Hydrail would be implemented in stages while taking advantage of lessons learned while implementing Hydrail subsystems in the GO corridors initially, so these numbers should be used only for the relative difference between the scenarios compared.

TABLE 4-25 COMPARISON OF RER SCENARIOS 4 AND 5 RER Scenarios 4 and 5 (Onsite production, gas phase, 7500 HP, 2024, 2024-cost, Locomotives+EMUs) Parameters Unit RER Scenario 4 RER Scenario 5 Change (%) Hydrogen required tpd 59 40 32 Water required tpd 594 402 32 Electricity required GWh/d 3.2 2.2 31 Electricity market price $/MWh 34.2 34.2 0 Electricity cost $K/d 129 91 30 Water cost $K/kg 1.8 1.2 32 Hydrogen cost $/kg 3.4 3.5 -3.4 Total operating cost $m/y 48 34 30

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TABLE 4-25 COMPARISON OF RER SCENARIOS 4 AND 5 RER Scenarios 4 and 5 (Onsite production, gas phase, 7500 HP, 2024, 2024-cost, Locomotives+EMUs) Parameters Unit RER Scenario 4 RER Scenario 5 Change (%) No. of locomotives No. 156 70 55 No. of powered EMUs No. 42 42 0 Land area required m2 23692 16166 32 Production equipment $m 311 211 32 Production storage $m 86 58 32 Refuelling storage $m 101 68 32 Dispensing equipment $m 64 48 25 Powered vehicles $m 1506 960 36

4.2.2.5 Summary of the Hydrail Operational Model Findings The Hydrail operational model and the maintenance assessment has revealed the following information:  The model is capable of estimating operational parameters and costs with sufficient rigor that the improvement in the inputs and assumptions would narrow the error margin.  The costs and cost factors used in this section are for indicative and comparison purposes only. The actual costs are presented in Section 4.4, along with the BCR.

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4.3 Electricity Policy and Pricing Electricity is the flow of electrons from a negatively charged body to a positively charged body113. Electricity is commonly used in everyday life as a source of energy for a wide range of applications, including lighting, heating, and powering appliances or other motorized equipment. Power is the rate (energy amount per time period) at which energy converted (Figure 4-24). The scientific unit of power is the watt (W), which is equal to one joule (energy amount) per second (time period)114.

FIGURE 4-24 ELECTRIC POWER MEASURES

The amount of electricity that is generated or used over a period of time is typically measured in kWh115. A watthour is equal to the energy of 1 watt steadily generated or supplied over 1 hour (Figure 4-25).

FIGURE 4-25 WATT-HOUR MEASURES

Ontario has seen a net increase in electricity production from 2005 to 2015, with production growing from 156TWh to 160TWh. The growth in production has however, not been met by increased demand. Changing economic conditions and conservation programs have resulted in non-weather- corrected grid demand116 within the province declining by approximately 10 percent from 151TWh in 2006 to 137TWh in 2015. Accordingly, Ontario currently generates significant surplus electricity, estimated at 9 percent of Ontario’s net demand in 2016, a major change from the deficits that existed in the early 2000s.

113 Natural Resources Canada (NRC). 2016. About Electricity. Accessed October 2017. http://www.nrcan.gc.ca/energy/electricity- infrastructure/about-electricity/7359. 114 “Power – Scientific Definition.” UQ.edu.au. The University of Queensland, Australia, n.d. Web. 02 Nov 2017. 114 “Power – Scientific Definition.” UQ.edu.au. The University of Queensland, Australia, n.d. Web. 02 Nov 2017. 115 “Measuring Electricity – Energy Explained, Your Guide To Understanding Energy – Energy Information Administration.” EIA.gov. U.S. Department of Energy, 10 Feb 2017. Web. 24 Sep. 2017. 116 Non-weather-corrected grid demand has not been adjusted for variations in weather patterns that may impact demand for electricity.

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As the province seeks to improve efficiencies, plans through to 2035 focussed on improvement in the alignment between demand and supply of electricity, and continuing conservation initiatives and demand response programs. The following sections will describe the governance and policy framework that guide strategic planning for Ontario’s electricity needs; Ontario’s electricity system and generation capacity; and electricity demand forecasts as well as plans to balance the electricity system, while limiting investment in additional infrastructure. 4.3.1 Governance, Regulatory, and Management Framework 4.3.1.1 The Ministry of Energy117 The Ministry of Energy (the Ministry) facilitates the development of Ontario’s electricity generation, transmission and other energy related facilities. One of the Ministry’s top priorities is ensuring that Ontario’s energy needs are met in a sustainable manner. The mandate letter from the Premier to the Ontario Minister of Energy (the Minister), dated 23 September 2016, outlines the Minister’s priorities, including:  Taking further action to mitigate the impact of electricity prices on consumers and businesses, partly through expanding eligibility for the Industrial Conservation Initiative (ICI).  Promoting energy conservation and the adoption of renewable energy.  Supporting the growth of the low-carbon economy and reductions in GHG emissions.  Driving efficiencies and maximizing return on investment from the electricity sector. If successful, these actions will drive efficiencies, lead to an increasing reliance on renewable energy and encourage greater levels of energy conservation, thereby reducing electricity demand in lieu of increasing supply. 4.3.1.2 The Ontario Energy Board118 The Ontario Energy Board (OEB) is Ontario’s independent energy regulator, whose goal is to ensure the energy system remains sustainable and reliable, and that the energy rights of Ontarians are protected. The OEB’s mandate and authority come from the Ontario Energy Board Act, 1998; the Electricity Act, 1998; and other provincial statutes, including the Energy Consumer Protection Act, 2010. The OEB:  Sets rules for energy companies operating in Ontario  Establishes energy rates  Licenses energy companies  Monitors the wholesale electricity market and energy companies  Develops new energy policies in partnership with the Ministry  Advises the Government of Ontario on energy policy

117 “About the Ministry”. Web. 10 Oct. 2017.Energy.gov.on.ca, 26 Sep. 2016. 118 05 Oct. 2017. “About Us”. OEB.ca. Ontario Energy Board, n.d. Web.

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The OEB assisted the government in the development of the regulatory framework for Ontario’s cap and trade program, and is also in the process of implementing a five-point plan to redesign electricity prices (OEB, 2012-2017a). 4.3.1.3 The National Energy Board119 The National Energy Board (NEB) is a federal body that, amongst other things, regulates the construction and operation of international and designated interprovincial power lines, as well as the import of electricity. The NEB also authorizes and regulates energy trade through long-term licences, permits, and short-term orders. The amount of electricity exported cannot exceed limits approved by the NEB. In performing its duties, the NEB considers the impact of exports on adjacent provinces and fair market access for Canadians. The NEB reports to Parliament through the Minister of Natural Resources. 4.3.1.4 The Independent Electricity System Operator120 The Independent Electricity System Operator (IESO) manages Ontario’s electricity system, forecasts the demand and supply of electricity to plan for the province’s future energy needs, promotes conservation, and operates the wholesale electricity market. The IESO was established through the Electricity Act in 1998 as a not-for-profit corporate entity. Through amendments to the Electricity Act on January 1, 2015, the IESO was merged with the Ontario Power Authority. Through legislation, the Ministry oversees the IESO, which is governed by a Board of Directors that is appointed by the Province of Ontario. The IESO operates independently of all other participants in the electricity market. The IESO forecasts the Ontario’s current, short-term and long-term energy needs, and assesses the adequacy and reliability of the integrated power system to ensure Ontarians have sustainable solutions to meet energy needs now and in the future. 4.3.2 Ontario’s Electricity System Ontario’s electricity system is made up by a network of generation, distribution and transmission systems that supply electricity across the province (Figure 4-26). The network is part of a larger North American system, through which Ontario’s network is connected to neighbouring provinces and states.

119 “NEB – Who we are”. 03 Oct. 2017NEB-one.gc.ca. Government of Canada, 01 Dec. 2016. Web.120 Independent Electricity System Operator (IESO). 2017a. “What We Do.” About the ISEO. Accessed October 5, 2017. http://ieso.ca/en/learn/about-the-ieso/what-we-do.121 “Electricity – Energy Explained, Your Guide To Understanding Energy – Energy Information Administration.” EIA.gov. U.S. Department of Energy, 21 Nov. 2016. Web. 24 Sep. 2017. 120 Independent Electricity System Operator (IESO). 2017a. “What We Do.” About the ISEO. Accessed October 5, 2017. http://ieso.ca/en/learn/about-the-ieso/what-we-do.121 “Electricity – Energy Explained, Your Guide To Understanding Energy – Energy Information Administration.” EIA.gov. U.S. Department of Energy, 21 Nov. 2016. Web. 24 Sep. 2017.

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FIGURE 4-26 ELECTRICITY INDUSTRY STRUCTURE IN ONTARIO

(Source: Adapted, with permission, from the Hydro One Limited 2016 Annual Report) The electricity system is described in further detail in the sections that follow. 4.3.2.1 Generation Electricity is the flow of electrical power or charge produced by converting energy into electrical power. Energy sources may be renewable or non-renewable. The main sources of renewable energy include solar, hydro, and wind energy.121 Non-renewable sources include fossil energy sources, such as coal, oil, and natural gas. Nuclear energy, generated from uranium, is a nonrenewable, nonfossil energy source. Historically, Ontario relied heavily on coal-fired generation. From 2005 to FIGURE 4-27 ONTARIO’S 2015 ENERGY PRODUCTION 2015, the province significantly reduced the level of GHG emissions from the electricity sector, as installed coal-fired capacity was wound-down and replaced with renewable and natural gas-fired capacity. Ontario’s electricity is presently generated from wind, solar, bioenergy, hydro, nuclear and natural gas-fired resources, with approximately 90 percent of the electricity being generated from nonfossil sources. The province’s electricity needs can vary by as much as 10,000 MW in any given day. The province’s diverse energy supply mix allows for the management of different resources to perform different roles to meet its varying electricity needs. Baseload refers to the minimum amount of electric power delivered or required over a given period of time at a steady rate. A baseload plant is normally operated to take all or part of the minimum load of a system, and consequently produces electricity at an effectively constant rate, and runs continuously122. Nuclear power plants and “run-of-the-river” hydro facilities produce a constant and steady output of electricity

121 “Electricity – Energy Explained, Your Guide To Understanding Energy – Energy Information Administration.” EIA.gov. U.S. Department of Energy, 21 Nov. 2016. Web. 24 Sep. 2017. 122 “Glossary.” EIA.gov. U.S. Energy Information Administration, n.d. Web. 02 Nov 2017.

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT and are considered baseload generation. Natural gas facilities and hydro generators with reservoirs for storage allow for variable output, as needed. Peaking generators are relied upon to meet the peaks on the highest demand days, while intermediate generators work throughout the day, with output adjusted as demand varies. Wind and solar facilities generate variable output, based on weather conditions. They are highly flexible in respect of the ability to adjust output, subject to energy availability, allowing for variable but controlled generation. A key difference between traditional and variable generators is that traditional generators store their primary energy source (for example, uranium, water or natural gas) onsite and convert it to energy as needed. Variable generators on the other hand, can only produce energy when the primary source (for example, wind or sunlight) is available. As such, the principle challenge with variable energy sources is that they can regularly drive a mismatch between demand and supply.

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Installed capacity refers to the maximum possible output of electricity generators FIGURE 4-28 ONTARIO’S 2016 INSTALLED CAPACITY installed within the province’s electricity system. Actual electricity production may vary based on the availability of energy sources and direction from the IESO to adjust output to efficiently meet energy needs. There is currently over 37,000 MW of installed capacity within Ontario’s transmission system and an additional 3,600 MW of generation capacity within local distribution systems. Nuclear and renewable sources represent approximately 74 percent of the installed capacity and natural gas sources account for the remaining 26 percent. Actual production levels are discussed in the section that follow. Energy Sources Nuclear Nuclear energy, generated by splitting uranium atoms, is a non-renewable source of energy. Nuclear generation is, however, considered sustainable, given significant uranium resources relative to the rate of use, and the low environmental impact of its use. Nuclear power accounts for approximately 58 percent of the province’s electricity production. There are three nuclear plants, Bruce, Darlington and Pickering, with 18 generating units in operation within the province. Hydroelectric Hydroelectric (or hydro) energy is generated by converting the kinetic or potential energy of water into electrical energy. Hydro generation is an important component of Ontario’s baseload and peaking energy mix. Hydro currently accounts for roughly 23 percent of the province’s electricity production, and is therefore the most significant source of renewable energy. Given the ability to predict the level of hydro generation throughout any given day and across seasons, hydro is a stable source of renewable energy. Natural Gas and Oil Thermal generating plants generate electricity by burning natural gas. They can quickly adjust output based on changes in demand, thereby easily meeting peak demand needs or providing back up for more volatile wind or solar generation. Natural gas is a fossil fuel, and generates GHGs as a by- product of energy production. The volume of emissions is however, significantly lower than coal-fired resources. Natural gas and oil now account for roughly 10 percent of the province’s electricity production. Wind, Solar, and Bioenergy Wind, solar and bioenergy now accounts for roughly 9 percent of the province’s electricity production. The contribution levels are largely attributed to wind energy, as significant government incentives along with improvements in technology have resulted in greater output and lower unit costs. Wind energy generating potential is greatest in the winter and at night. Wind energy generators can quickly adjust output in response to system requirements. Solar generation is important to Ontario’s

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT energy mix, with high production levels during the summer peaking hours. Bio energy is produced either by combusting organic fuel (biomass) or by allowing organic matter to decompose, producing CH4, which is then combusted to produce electricity. In Ontario, there are abundant sources of organic matter as a by-product of forestry, agricultural and livestock, and food processing operations, as well as from municipal waste. The key challenge to the establishment of bioenergy plants is however, the high capital cost. 4.3.2.2 Transmission Electricity is produced from generation plants and transmitted across Ontario’s transmission system at high voltage before being stepped down to lower voltage for delivery to end-users. The province’s high voltage transmission system consists of a network of transmission lines that are equal to or greater than 50 kilovolts (kV). The stability of Ontario’s electricity system depends on supply constantly meeting demand. The IESO directs the flow of electricity across the grid, balancing demand and supply to ensure stability. Over the past decade, the Province has focussed on maximizing the use of the existing transmission system. Accordingly, significant renewable energy resources have been added without any major expansion of the transmission network. The network is, however, nearing capacity, and now has limited ability to accommodate additional generation. Further constraints are presented when resource potential is not located within proximity to the grid, as is the case for many of the Province’s untapped renewable energy sources. Significant new transmission additions typically require a lead time of 7 to 9 years; therefore, the management of the transmission system requires careful planning. Capacity constraints lead to congestion in some areas. System congestion refers to instances during the operation of the power system when there is not enough transmission capacity available to accommodate scheduled generation. Over the long-term, transmission facilities are efficiently used where there is a manageable level of congestion. In Ontario, as the use of existing assets is being maximized, many parts of the system are frequently congested. Current Grid Capacity Ontario’s power transmission system is broken down into 10 zones, as reflected in Figure 4-29.

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FIGURE 4-29 GEOGRAPHICAL ZONES IN ONTARIO’S POWER TRANSMISSION SYSTEM

Supply and demand characteristics vary across each zone. As Table 4-26 demonstrates, in three zones, Essa, Toronto and Ottawa, total resources tend to be lower than peak demand. In contrast, supply in the Bruce and Niagara zones significantly exceed peak demand, largely due to the presence of the Bruce nuclear generating plant and the Niagara Falls hydro facilities, respectively. In the remaining zones, total resources either exceed or are balanced with peak demand.

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TABLE 4-26 RESOURCES IN RELATION TO DEMAND ACROSS THE GEOGRAPHICAL ZONES IN ONTARIO'S POWER TRANSMISSION SYSTEM123 Zone Primary Energy Source Bruce Nuclear, with some wind Resources significantly exceed peak demand Niagara Hydro, with some natural gas Resources significantly exceed peak demand East Hydro, oil, and natural gas, with some wind and solar Resources exceed peak demand Northeast Hydro, with some cogeneration, wind, solar, and biofuel Resources exceed peak demand Northwest Hydro and biofuel, with some wind and natural gas Resources generally exceed peak demand West Natural gas and wind, with some solar Resources generally exceed peak demand Southwest Wind and natural gas, with some solar Resources generally equal peak demand Toronto Nuclear, with some natural gas Resources are less than peak demand Essa Hydro, with some natural gas Resources are much less than peak demand Ottawa Cogeneration Resources are much less than peak demand

The East and Southwest zones are not generally congested. The transmission systems in these zones operate well below capacity, allowing for the transfer of power to the Toronto and Ottawa zones in addition to supplying local demand. The Toronto, Ottawa, and Essa zones are load congested. These zones rely on transfers from other zones to meet zonal peak demand, and the transmission network within the zones operates at or near capacity during peak load periods. The Bruce, Niagara, and Northwest zones are generation congested. Installed generation capacity in the zones is equal to or greater than the combination of demand within the zones and the ability to transfer electricity out of the zone. This results in the zonal transmission systems operating at or near capacity whenever zonal generation peaks. The Northeast and West zones have some transfer capability available. In the Northeast zone, congestion is more likely than in the West given that it is tied to lower-cost baseload and peaking hydro generators. In the west zone, capability is limited when natural gas-fired generators are online. 4.3.2.3 Distribution While some large industrial consumers are directly connected to the transmission grid and purchase electricity from the Ontario electricity market, most industrial customers and smaller consumers, including residential consumers, are served by local distribution companies (LDCs). LDCs own and operate infrastructure to convert high-voltage electricity to a lower voltage, and deliver electricity to end-users. There are currently 78124 licensed electricity distributors operating in Ontario. In addition to delivering electricity to end-users, LDCs perform billing functions reflecting distribution charges and other charges, as described in Section 4.3.1.4.

123 Independent Electricity System Operator (IESO). 2016c. IESO Report: Energy Storage. March. Accessed October 2017. http://www.ieso.ca/-/media/files/ieso/document-library/energy-storage/ieso-energy-storage-report_march-2016.pdf 124 “Licensed companies and licensing information.” 05 Oct. 2017.OEB.ca. Ontario Energy Board, n.d. Web.

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4.3.2.4 Electricity Exports Ontario is part of North America’s large, 125 interconnected electricity system, allowing for FIGURE 4-30 ONTARIO NET EXPORTS, 2007-2016 added ability to manage generation surpluses and shortfalls. Ontario currently has interconnections with Quebec and Manitoba in Canada, and Minnesota, Michigan, and New York in the United States (U.S.); and can import and export electricity on a continual basis to balance the province’s electricity system. Ontario’s interconnection with neighbouring jurisdictions allows for the efficient import and export of electricity based on the province’s supply and demand levels, as well as that of its neighbours. This allows for operational and planning flexibility, and enhances the reliability and cost-effectiveness of the electricity system. Ontario is a net exporter of electricity, given surplus generation in the province. Net exports have trended up from 2007 through to 2015, from 5.1TWh to 16.8TWh, but declined to 13.9TWh in 2016, a trend that is expected to continue based on forecasts for the demand and supply of electricity as outlined in the ensuing sections. Electricity exports are priced on the wholesale market, at the HOEP. As discussed in Section 4.3.1.4, the cost of generating and transmitting electricity is reflected in other charges paid by Ontario consumers. Therefore, while generating some revenue, exports do not allow for recovery of the full cost of supplying the electricity exported. 4.3.3 Electricity Forecasts With the combination of economic and population growth, and improved energy efficiency across homes and business, all taken within the context of climate change and environmental considerations, demand and supply profiles have changed over time. This has given rise to the need for a long-term planning approach to meeting the Province’s energy needs. The LTEP is produced by the Ministry and is the tool by which the province plans for long-term energy needs and sets out long term energy policies. The planning process that LTEP follows balances cost- effectiveness, reliability, clean energy, community engagement, and places emphasis on conservation and demand management before building new generation. Ontario’s first LTEP was released in 2010 and was updated in 2013 and again in 2017. The 2017 LTEP, released in Fall 2017, covers the 2017-2035 planning horizon.

125 Independent Electricity System Operator (IESO). 2016a. Ontario Planning Outlook. September 1. Accessed October 2017. http://www.ieso.ca/sector-participants/planning-and-forecasting/ontario-planning-outlook.

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4.3.3.1 Ontario’s Long-term Energy Plan The Province’s plans, as outlined in the 2013 LTEP, include:  Encouraging conservation, which will drive planning, approval and procurement processes;  Retracting on previous plans to construct two new nuclear reactors, while moving forward with plans to decommission the Pickering Generating Station;  Increasing the installed capacity of renewable energy;  Using natural gas-fired generation to allow for flexible response to changes in demand and supply;  Considering opportunities for clean energy imports from other jurisdictions; and  Exploring opportunities for the use of energy storage technologies. The 2017 LTEP builds on the plans as previously outlined, with key initiatives including:  Ensuring affordable energy, with projections for the cost of electricity for large industrial customers to, on average, increase in line with inflation over the forecast period.  Spreading the cost of existing electricity infrastructure over a longer period by refinancing a portion of the Global Adjustment.  Supporting expanded access to natural gas.  Ensuring a flexible energy system, with a Market Renewal initiative being launched.  Maximizing use of Ontario’s existing electricity infrastructure to limit future increases in the cost of electricity.  Removing barriers to the deployment of cost-effective energy storage.  Continued commitment to energy conservation. Based on the LTEP, the expectation is that, by 2025, there will be a significant reduction in surplus baseload generation (SBG), with demand response strategies addressing peak demand needs. 4.3.3.2 Ontario Planning Outlook The Ontario Planning Outlook (OPO) was prepared by the IESO in response to the Minister’s request for a technical report on the adequacy and reliability of Ontario’s electricity resources to support development of the 2017 LTEP. The report reflects the IESO’s planning outlook for 2016 through to 2035 (IESO, 2017). The OPO provides an overview of Ontario’s current electricity system, including:  A demand outlook  Potential for resources to meet that demand  Risks associated with various resources  Costs of the electricity system  An emissions outlook for the electricity system While Ontario currently generates excess electricity, an excess is never planned. Based on the projection included in the OPO, the expectation is that, by 2025, there will be a significant reduction in surplus baseload generation (SBG), as discussed further in Section 4.3.3.6, with demand response strategies addressing peak demand needs.

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4.3.3.3 Electricity Demand Forecast The OPO considers a range of electricity demand levels in Ontario in 2035, from 133 TWh to 197 TWh, under four scenarios:  Outlook A explores lower electricity demand  Outlook B explores a level of demand that roughly matches current demand levels  Outlooks C and D explore higher demand driven by policy choices stemming from Ontario’s Climate Change Action Plan, including assumptions around the adoption of electric vehicles and planned electrified transit projects The scenarios include varying assumptions regarding the level of conservation, more stringent building codes, and higher equipment standards. Through the LTEP, the Province is planning for a flat demand scenario as reflected in Outlook B, while allowing for flexibility to adjust to changes in demand. Additionally, conservation and demand response programs are expected to have a significant impact on reducing total and peak demand. Demand Expectations FIGURE 4-31 ONTARIO NET ENERGY DEMAND ACROSS Under a flat demand outlook DEMAND OUTLOOKS126 (Outlook B), total electricity demand is expected to marginally increase, at a compounded annual growth rate of 0.16 percent, from 143.4 TWh in 2016 to 147.8 TWh in 2035 (Figure 4-31). The stable demand outlook largely assumes that population and economic growth that would otherwise increase demand are counterbalanced by conservation measures. The outlook assumes an uptick in electricity requirements for electric vehicles and planned electrified transit projects, including RER and light rail projects as approved at the date of the report. Taken together, these initiatives are projected to account for a total of 4 TWh in 2035, of which approximately 0.55 TWh is attributed to transit projects. Peak demand is expected to be relatively unchanged from 2016 to 2025, ranging from 23.9 to 24.1 MW, and then increasing to 24.8 MW by 2035. Transportation is expected to account for 2 percent of peak demand in 2035 (IESO, 2016). Under a higher demand outlook (Outlook D), in 2035 the total electricity demanded is projected to be 197 TWh. This assumes an increase in residential and commercial electricity demand due to increased electrical space and water heating, accounting for a total increase in electricity demand of 30 TWh. Outlook D also assumes a shift to electricity based energy generation in the industrial sector, an increased number of electric vehicles (2.4 million by 2035), and electrification of transit, accounting for approximately 9 TWh and 0.65 TWh, respectively. Peak demand is expected to grow to 35.4 MW by 2035 (IESO, 2016).

126 Independent Electricity System Operator (IESO). 2016a. Ontario Planning Outlook. September 1. Accessed October 2017. http://www.ieso.ca/sector-participants/planning-and-forecasting/ontario-planning-outlook.

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The difference between summer and winter peak varies across demand outlooks and across FIGURE 4-32 NET SUMMER PEAK MINUS NET 127 the forecast period. There is currently a WINTER PEAK difference of approximately 1,800 MW between summer and winter peak demand (Figure 4-32). Over the forecast period, under a stable demand outlook, the variance is expected to increase to 2,369 MW in 2036. Under higher demand outlooks, Ontario is expected to become a winter peaking province; if this occurs, the variance between summer and winter peak demand is significantly reduced by 2025, and winter peak demand is projected to exceed summer peak demand by as much as 6,900 MW in Outlook D128. Conservation and Demand Response Programs A significant percentage of the forecasted growth in electricity demand is expected to be offset by conservation programs and improved codes and standards. The LTEP includes a long-term conservation target of 30 TWh in 2032. Demand response programs provide a variety of incentives to encourage end-users to reduce electricity use during peak hours. Demand response initiatives led to a reduction in peak demand of approximately 1.8 gigawatt (GW) in 2015 and are expected to reduce peak demand by 10 percent, or approximately 2.5 GW by 2025. 4.3.3.4 Electricity Supply Forecast Supply assumptions are based on existing resources that have been procured but are not FIGURE 4-33 INSTALLED CAPACITY AND CAPACITY yet in service, and resources that have neither CONTRIBUTIONS129 been procured nor acquired as of the date of the OPO, but have been directed to meet provincial policy objectives. Assuming that all current resources continue until contract expiration and all nuclear refurbishments, as well as committed and directed resources, come into service as scheduled, total installed capacity is expected to slowly increase from 39.6 GW in 2016 to 42.6 GW in 2035, 7 percent growth over the period. While the installed capacity increases, Source: (IESO, 2016) there will be an increasing reliance on renewable energy sources, which are, in the case of solar and wind, more variable. Accordingly, while installed capacity generally increases, except for a decline in the late 2020s, the capacity contribution of resources is generally unchanged over the forecast period.

127 Independent Electricity System Operator (IESO). 2016a. Ontario Planning Outlook. September 1. Accessed October 2017. http://www.ieso.ca/sector-participants/planning-and-forecasting/ontario-planning-outlook. 128 ibid. 129 ibid.

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Expectations for each source of electricity, based on current resources as well as committed and directed resources, are described in the following paragraphs. Nuclear While previous forecasts indicated the need for additional nuclear generating capacity, based on the current outlook, and given revised demand forecasts, additional capacity is not necessary. Accordingly, the Province is not planning to move ahead with plans to build additional nuclear plants and will proceed with plans to decommission the Pickering plant, which currently has six units in operation and an installed capacity of 3,100 MW. Two units will be retired at the end of 2022 and four units at the end of 2024. Nuclear energy is expected to account for 48 percent of Ontario’s electricity production in 2035 The Province retains the option to build additional nuclear capacity if future needs dictate. It is the Ministry’s intention to maintain the licence granted by the Canadian Nuclear Safety Commission for the construction of new nuclear units. Hydro Ontario has significant additional hydro potential; however, most of the potential exists in relatively remote northern communities, and would, therefore, be developed at a relatively high cost. Hydro power is expected to account for 27 percent of total electricity production in 2035. Natural Gas The natural gas fleet allows for flexibility to respond to variability in renewable energy sources. This relatively low-carbon source is, therefore, an important part of Ontario’s supply mix. Natural gas production is expected to account for 9 percent of total electricity production in 2035. Wind, Solar and Bioenergy Wind, solar and bioenergy are expected to make more significant contributions to Ontario’s energy mix in 2025 and beyond. Collectively, these non-water renewables are expected to account for 16 percent of electricity production in 2035, largely due to the expansion of wind electricity production. 4.3.3.5 Forecasted Demand Relative to Supply The IESO’s assessment is that there are sufficient resources to meet flat demand levels (Outlooks B), with relatively low surplus generation during peak demand periods. The higher demand scenarios would, however, present challenges of scale and integration, requiring the deployment of multiple low-carbon options and significant investments in transmission and distribution systems. The OPO, however, underscores the need for more conservation, rather than investment in additional generating capacity, to meet the higher demand under those scenarios. The Province will be able to adapt to a lower demand scenario by choosing not to renew existing contracts for generation upon expiration, if the energy is not needed. The capacity contribution (that is, maximum output) of installed capacity relative to peak demand (including a planning reserve) under Outlook B is outlined below (Figure 4-34).

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FIGURE 4-34 CAPACITY CONTRIBUTION VS. DEMAND Summer Capacity Contribution vs Demand Winter Capacity Contribution vs Demand 45,000 45,000

40,000 40,000

35,000 35,000

30,000 30,000

25,000 25,000

20,000 20,000

Outlook A Outlook D Summer Capacity Contribution Outlook A Outlook D Winter Capacity Contribution

Source: (IESO, 2016)130

The forecast suggests that under a stable demand scenario, Ontario will generate sufficient electricity to meet peak demand. In a higher demand outlook such as Outlook D, the province is expected to have sufficient resources to meet demand through to 2022 however additional resources would be required to meet demand beyond 2022. It is however noted that demand and supply forecasts are based on a variety of assumptions, including median weather conditions and consumer preferences such as actual adoption of electric vehicles and use of electricity for home heating, to name a few. Extreme weather events or significant changes in consumer preferences can therefore have a significant impact on forecasts. 4.3.3.6 Surplus Baseload Generation SBG refers to baseload generation in excess of provincial demand plus net exports. SBG is managed through exports, by diverting water from hydro turbines, by curtailing wind and solar generation, and by managing units at the Bruce Nuclear Generating Station. In FYE 2016, as shown on Figure 4-35, SBG amounted to approximately 9 percent of FIGURE 4-35 SURPLUS BASELOAD GENERATION AS Ontario net demand. The OPO indicates that A PERCENTAGE OF NET DEMAND SBG is expected to decline through to 2035, largely due to the decommissioning of the Pickering Nuclear Generating Station and, from 2020-2028, as units at the Darlington and Bruce Nuclear Generating Stations are being brought out-of-service for refurbishment in the 2020s. Periods of SBG will be further impacted by:  Variability in seasonal demand and supply patterns, with period of SBG being more prevalent in the spring and fall months  Shifting demand patterns brought on by demand response programs that seek to reduce peak energy usage, thereby shifting demand to traditionally off-peak periods

130 Independent Electricity System Operator (IESO). 2016a. Ontario Planning Outlook. September 1. Accessed October 2017. http://www.ieso.ca/sector-participants/planning-and-forecasting/ontario-planning-outlook.

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 Increased uptake of electric vehicles, leading to increased demand for electricity overnight  Increased use of electricity for heating homes  Energy storage programs that will seek to store energy during periods of SBG, thereby limiting the availability of surplus electricity 4.3.3.7 Forecasted Grid Capacity Capacity of the transmission network has implications for the location, size, and number of hydrogen generation facilities proposed to support Hydrail. Consideration would need to be given to forecasted capacity and congestion levels within each zone of the electricity system, which will have to be weighed against the cost associated with larger hydrogen generation and storage facilities, ability of the supplier to exercise flexibility in the timing of hydrogen production, and the cost of hydrogen transportation. While congestion in the system is currently manageable, future changes in demand and supply can be expected to increase congestion challenges as more variable and distributed energy resources come into service. Additionally, the retirement of the Pickering Nuclear Generating Station may increase flows from southwestern Ontario, resulting in higher congestion in the Southwest and Toronto zones. As Figure 4-36 shows, generation capacity in the Toronto and Bruce zones are expected to FIGURE 4-36 ZONE GENERATION CAPACITY decline by 2020, due to a reduction in nuclear generation. Assuming flat demand, it can be expected that load congestion in the Toronto zone will be magnified, while generation congestion in the Bruce zone is expected to be somewhat alleviated, but not eliminated. Generation capacity in the East, West, and Southwest zones is expected to increase. However, as noted in Section 4.3.2.2, these zones are currently uncongested, with some transfer capability.

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4.3.4 Electricity Pricing Electricity prices in Ontario primarily comprise the HOEP and the GA. Transmission, FIGURE 4-37 HOEP VS. GA distribution, regulatory, and other charges combined may also account for roughly 20-30 percent of prices, and vary depending on location within the transmission grid. The HOEP is the wholesale price of electricity and is determined in a real-time market, operated by the IESO. The HOEP changes hourly, based on demand and supply of electricity. It is significantly impacted by time of day, day of week, weather factors, and economic conditions. Every day, the IESO forecasts electricity demand for the days and weeks ahead. Generators and electricity importers submit offers to supply electricity and indicate the prices they are willing to accept. Large customers and exporters submit bids for electricity purchases at specified prices. The IESO accepts the lowest cost offers to supply electricity to meet demand. A new market clearing price is set every 5 minutes. The HOEP is the average of the 12 market clearing prices set in each hour. The impact of demand and supply forces on the electricity market results in a higher HOEP during peak demand periods and a lower HOEP during periods of excess supply (SBG). The GA is paid by all Ontario electricity customers, and reflects the net cost of electricity generation and the cost of delivering conservation programs. The GA varies monthly, adjusting for the difference between the HOEP and the cost of regulated and contracted generation. The main components of the GA are:  GA-OEFC-NUG (M$) – Contracts administered by the Ontario Electricity Financial Corporation with existing generation facilities  GA-OPG (M$) – Ontario Power Generation nuclear and baseload hydro generating stations  GA-OPA (M$) – Contracts with the IESO (and with the former Ontario Power Authority) for new gas-fired generation, renewable facilities, energy from waste and biomass, nuclear refurbishments, as well as conservation programs. 4.3.4.1 Electricity Pricing for Large Businesses Industrial customers with an average peak demand of over 1 MW and targeted manufacturing and industrial customers with peak demand of over 500 KW and under 1MW (collectively, Class A customers) are eligible for participation in the Industrial Conservation Initiative (ICI), which was introduced in 2010. Through the ICI the GA attributed to participating customers is calculated based on the customer’s percentage contribution to the top five peak Ontario demand hours, over a 12-month base period. The ICI, therefore, allows participating customers to manage their GA costs by reducing demand during peak periods, and allows the province to defer building new electricity infrastructure to meet peak demand. It is estimated that in 2016, the ICI helped to reduce peak electricity demand by approximately 1.3 GW.

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The peak demand factor (PDF) is calculated by taking the sum of the customer’s demand during the top five peak Ontario demand hours in the base period (May 1 to April 30), and dividing it by the total system consumption during those hours. The calculated ratio is the customer’s peak demand factor. The customer’s monthly GA cost is calculated by multiplying the PDF by the provincial GA cost in each of the ensuing 12 months (July 1 to June 30). A participating customer can manage their GA costs by reducing electricity use during forecasted peak hours. The IESO provides tools to track current and projected demand, along with a forecast of system conditions. Peak periods generally coincide with:  Heat waves in the summer or cold snaps in the winter  Weekday afternoons in the summer  Early weekday evenings during the winter A customer who can significantly reduce electricity usage during peak hours will have relatively minimal GA costs. It is however noted, as discussed in sections 4.3.3.5 and 4.3.3.6, that a variety of factors can impact demand patterns and that demand patterns are expected to the change in the future. An important consideration for Hydrail is that peak demand hours may be more difficult to predict than they are presently. 4.3.4.2 Policy Initiatives Impact on Electricity Prices in Ontario Electricity prices are driven by decisions of the past and those decisions impact prices long into the future. Policy initiatives or pricing regimes may either shift the cost of investments from one user group to another or defer costs to future generations, based on economic or social factors at play at the time of consideration. As history has shown in Ontario, electricity policy and investment priorities change over time and likely will continue to evolve as market conditions and government policy priorities evolve. The ICI is a policy initiative of the Government of Ontario that was designed to reduce peak demand and to support Ontario’s industrial sector. While the ICI has effectively achieved its objective to date, the policy could be challenged on merit, as it may be argued that the ability to shift consumption of electricity away from peak hours should not absolve a company of its obligation to share in the costs that the GA is designed to recover. Notwithstanding, it is noted that electricity pricing in Ontario is generally expected to move to more of a market-driven model. Under such a model, consumption during hours of high demand should ultimately result in higher electricity costs, with the reverse also applying. Accordingly, while the ICI may be terminated or decline in significance in the future, the principle upon which it is based will likely still apply. Other recent policy initiatives of the Province have led to an average 25 percent reduction in electricity prices for residential and small business customers in 2017 under the Fair Hydro Act, 2017. Initiatives under the Fair Hydro Act 2017 include refinancing of a portion of the GA to spread the cost of electricity investments over a longer time period, thereby reflecting the longer lifecycle of existing facilities, and sharing the costs with future generations. As outlined in the 2017 LTEP, the government is also considering measures to provide electricity rate assistance to non-Class A mid-sized customers (Class B customers). One such consideration is a change to the way the GA is charged to these customers, who currently pay the same GA charges regardless of time of use. It is not yet known whether these measures will impact the way GA costs are charged to other customers.

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4.3.4.3 Market Renewal Market Renewal is a set of initiatives intended to redesign Ontario’s electricity market, leading to reduced supply costs and increased flexibility. These initiatives will:  Improve the way Ontario acquires supply to meet medium- and long-term needs;  Enable the IESO to more cost-effectively schedule and dispatch electricity to meet demand as it changes from hour-to-hour and minute-to-minute; and  Increase flexibility, enabling the IESO to more efficiently manage unexpected short-term changes to the system, like those that can be caused by variable generation such as wind and solar. Market renewal is expected to result in cost savings, given more efficient use of existing assets, which is consistent with the province’s long-term plans. It will also lead to greater market competition and a more flexible procurement process that is better aligned with system needs. 4.3.4.4 Pricing Outlook Under Outlook B, the IESO expects that the average unit cost of operating the electricity system will gradually increase to $152/MWh by 2025, relative to $144/MWh in 2016. Thereafter, the cost is expected to generally decline to $131/MWh by 2035. The decline is based on the renewal of existing generating contracts at lower rates, as existing generators continue to operate at costs below existing contract rates, and given reduced investment in electricity resources. Under Outlook D, the cost of electricity in FIGURE 4-38 CLASS A ELECTRICITY PRICE FORECAST 2025 is expected to range from $155/MWh to $160/MWh, given the need to invest in additional resources to meet higher demand, while keeping emissions low. The average unit cost is expected to generally decline, ranging from $137/MWh to $142/MWh by 2035, as existing contracts are renewed at lower rates and higher volumes reduce the average cost of operation. The projection for the price of electricity for a typical large industrial customer, as presented in the 2017 LTEP is outlined in Figure 4-38. The all-in price of electricity, reflecting the HOEP, transmission, regulatory and other costs, and the GA, is expected to range from $102/MWh in 2025 to $116/MWh in 2035. 4.3.5 Implications for Hydrail 4.3.5.1 Provincial Policy Objectives Electrification of transportation, both by means of overhead electrification and using HFC technology, is consistent with policy objectives as set out in the Premier’s mandate letter to the Minister of Energy. The use of HFC technology presents the added benefit of supporting the growth of the low-carbon economy and the reduction of GHG emissions, by potentially allowing for a broader replacement of diesel trains on the GO network with electric trains than would be possible through overhead electrification. Further to this, Hydrail could allow for load-shifting, by consuming electricity when there is SBG, versus adding to peak demand as would be the case with overhead electrification.

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Hydrail, therefore, also could support the Province’s goal of driving efficiencies and limiting expenditure on new electricity infrastructure. 4.3.5.2 Capturing SBG The assessment shows that, while the level of SBG is expected to decline, electricity production is expected to exceed Ontario net demand by 1-4 percent from 2024 to 2035. There are however seasonal variations in the level of SBG and, particularly given the increasing reliance on renewable energy in the province’s energy supply mix, weather related factors can further impact electricity generation, and therefore SBG. SBG is often available over short periods of time and to fully capture it would require an infrastructure build-out that would allow for the production and storage of hydrogen over short periods of time, which would be idle outside of these periods. The ability to harness SBG to produce hydrogen is a function of the scale of hydrogen production (current density) and storage (volume) infrastructure, relative to when the SBG is available. Using hydrogen production and storage assumptions from the Hydrail simulation model, along with demand projections as presented in the 2016 OPO, modelling work shows that only approximately 14-35 percent of the annual amount of hydrogen required to support Hydrail can be produced from electricity supplied during periods of SBG over the 2025-2035 time frame. Furthermore, the same analysis shows that only 6-23 percent of operating days over the forecast period could be fully supplied by SBG. A further consideration is the province’s plans to incorporate energy storage technologies in managing the electricity system. The use of such technologies will lead to a further reduction in excess supply, as surpluses would be at least partially captured and stored by the province, thereby reducing the amount supplied to the market. The use of energy storage technologies would limit the ability of market participants to capture surplus baseload generation. Therefore, it is unlikely that the Hydrail System will be able to operate solely on electricity produced during periods of SBG. Accordingly, while the system would be able to avoid Ontario peak demand hours, therefore producing during off-peak hours, the system as currently designed, will not be able to consistently minimize the price of electricity, as it will be limited by the density of the hydrogen production facilities and the capacity of the hydrogen storage facilities. 4.3.5.3 Electricity Pricing As noted in the preceding sections, the HOEP is market driven, with lower prices during periods where the supply of electricity exceeds demand. Further to this, based on the current pricing structure and government policy initiatives, the ability to consume electricity outside of peak provincial demand hours can allow for the elimination of GA costs. On this basis, assuming the current pricing and policy regimes remain in effect, Hydrail presents certain benefits in respect of the unit cost of electricity relative to overhead electrification. These benefits are derived from the flexibility to schedule hydrogen production outside of Ontario peak demand hours, thereby minimizing or avoiding GA charges, and at times of lower HOEP thereby realizing lower electricity costs. This benefit must be weighed against the increased rate of consumption of electricity (for traction) in the case of Hydrail relative to overhead electrification, which could somewhat negate the unit cost advantage of Hydrail when considering the total overall cost of electricity. A further consideration is the potential shift in provincial demand patterns and the impact this will have on the peak/off-peak variance in the HOEP. The production of hydrogen will result in an increase in demand for electricity during periods of hydrogen production, which, given the significant load it will represent, could cause upward pressure on prices during that period. Additionally, as the

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT province encourages the electrification of transit and demand response programmes, both of which shift demand away from peak periods, it can be expected that there will be increased demand for electricity during traditional off-peak periods, which could in-turn increase the HOEP during these periods. This will likely result in a reduction of the variance in HOEP, and therefore also a reduction in cost advantage for consumption during traditional off-peak periods. Should this be the case, the unit cost advantage of Hydrail relative to overhead electrification will be partially eroded. The government’s ICI program is intended to help flatten out the daily energy consumption profile by shifting demand to off peak periods. The success of these programs can be viewed as a risk to the Hydrail business case, especially considering the significant electricity requirements to produce hydrogen at the required scale for the rail network. 4.3.5.4 Location of Hydrogen Generation Facilities As noted in Section 4.3.2.2, there are load and generation constraints in some zones across the Ontario electricity system. At present, decentralized hydrogen production to support Hydrail is being considered. Relative to centralized production, decentralized production would allow for smaller loads being drawn across different zones of the grid, from production facilities located along each line of the GO network. There are pros and cons to decentralized production, depending on the capacity constraints within the zones being contemplated and the location of potential hydrogen generation facilities relative to the GO network. Such matters would be resolved through detailed planning and procurement activities. The GO network extends across the East, Essa, Toronto and Southwest zones. In the East and Southwest zones, generation either exceeds or meets peak demand, with generation capacity expected to increase by 2020. Both zones are generally uncongested, and should therefore allow for additional loads. The Lakeshore East line extends into the East zone, while the Lakeshore West and Kitchener lines extends into the Southwest zone. In the Toronto and Essa zones, resources are less than peak demand, and both zones are load congested. The situation within the Toronto zone is expected to be magnified by the anticipated decommissioning of the Pickering nuclear generating plant by 2024. All GO lines run through the Toronto zone, however there may be locational challenges within the zone (space, property zoning, environmental, price), which may be compounded by limited public acceptance, particularly given the urban setting, as discussed in Section 4.8. The Barrie, Stouffville and Richmond Hill lines all run through the Essa zone. A decentralized approach to hydrogen production (described in Section 4.1) would involve the establishment of generation facilities along each line of GO network, crossing each of the four zones discussed. The significant advantage of decentralized generation is the cost advantage of smaller facilities along each line of the GO network. Based on the foregoing, there may however, be other challenges associated with this approach. One significant challenge is the limited capacity within Toronto, a situation that is expected to persist for the foreseeable future. A similar challenge would also be faced in the Essa zone. Further to this, consideration should also be given to the competing demands of electric vehicles, the continued adoption of which the 2017 LTEP acknowledges could have a significant impact on the province’s distribution network. Should hydrogen generation facilities be established within these zones, careful planning would be required to ensure hydrogen generation does not inadvertently stress local grids. Centralized hydrogen production facilities could be placed within the East zone, along the Lakeshore East line. In a semi-centralized scenario, hydrogen generation facilities could be located in the East and Southwest zones, along the Lakeshore East, Lakeshore West and Kitchener Lines.

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4.3.6 Electricity Pricing Forecast for Hydrail Electricity prices for RER under Hydrail have been projected based on forecasted electricity prices in Ontario and the Hydrail production simulation model. The electricity price assumptions are outlined in Table 4-27.

TABLE 4-27 ELECTRICITY PRICE ASSUMPTIONS Price Component Assumptions Hourly Ontario The forward looking HOEP was estimated by IESO using the following logic: Electricity Price  Historical HOEP pattern for each year was developed by dividing each hourly HOEP by the (HOEP) annual average to get the yearly mean-normal pattern.  The most representative historical HOEP pattern was selected for each of the projected years (2017-2035)  Historical HOEP patterns were scaled to the appropriate annual average marginal cost using numbers in-line with the 2017 LTEP. Global Adjustment The forward-looking GA charges are based on the forecast presented in the 2013 LTEP for a typical industrial customer. It is noted that, with the introduction of Hydrail, projected GA charges may be impacted, as discussed in Section 4.3.4. An assessment of the impact of same is, however, not within the scope of this study, and accordingly no adjustments have been made to the forecasts presented in the LTEP. Regulatory and The forward looking regulatory and transmission charges are based on the forecast presented in Transmission charges the 2013 LTEP.

The Hydrail Operational Simulation Model (described in Section 4.4.1) includes an algorithm that uses the HOEP price and the amount of hydrogen required for the Hydrail System to create a hydrogen production schedule that minimizes the cost of electricity, subject to the capacity of the hydrogen production and storage facilities. Given the optimized production schedule as described above, no electricity would be consumed during Ontario peak hours and therefore, under the ICI, the system would not be subject to GA. The ICI is however, a policy initiative and therefore subject to changes as discussed in section 4.3.4.1. On this basis, two pricing scenarios were developed based on whether the system is subject to GA charges. In the low case, the electricity price is estimated based on the assumption that the system operator pays no GA charge. In the high case, it is assumed that the ICI is discontinued and therefore, the operator pays full GA charges. The electricity pricing scenarios for Hydrail are presented in Table 4-28.

TABLE 4-28 ELECTRICITY PRICE FORECAST FOR HYDRAIL BASED ON ONTARIO’S 2017 LTEP 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 Low Case ($/MWh) 34.2 35.6 41.2 39.3 40.3 41.5 42.6 43.8 44.4 45.2 46.4 48.4 High Case ($/MWh) 68.7 61.7 77.1 73.9 74.6 73.8 72.7 72.9 74.2 75.2 76.1 77.9

The 10-year average electricity price for Hydrail is estimated at $46 /MWh and $76 /MWh without and with GA, respectively.

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4.3.7 Summary of Key Findings The foregoing assessment of the Ontario electricity system, pricing and policies indicates that in considering electrification of the GO network with Hydrail, electricity pricing assumptions must consider:  The possibility of being unable to consistently capture SBG due to an increase in demand for electricity, combined with relatively stable supply, increased use of energy storage technologies and reducing the occurrence of SBG. Due to these factors as well as the limitations of the production and storage facilities, conservative assumptions should be made about capturing SBG and the electricity prices associated with off-peak energy usage.  A change in electricity pricing policy negatively impacting on electricity pricing. As noted in Section 4.3.4, the current pricing regime may change such that the ability to avoid GA charges does not persist in the future. This will have a significant impact on the overall cost of electricity and will reduce the unit price advantage that would be afforded to Hydrail under the current regime.  A shift in demand profiles leading to a smaller differential in peak and off-peak pricing peak. The load presented by Hydrail is significant; therefore, it will impact provincial electricity, given the shift in the demand profile during off-peak periods. This will reduce the differential between peak and off-peak hours, thereby reducing the unit price advantage of Hydrail relative to overhead electrification.  The impact of the added load required by Hydrail on overall electricity prices (given an increase in demand). In addition to impacting electricity pricing during off-periods, the load introduced by Hydrail will increase overall demand for electricity, also driving an overall increase in the price of electricity, given the expectation for supply to remain relatively constant. A further consideration is the impact on the GA, as an increased load consuming what would otherwise be surplus electricity, should result in a general reduction in the GA charges applied across all customers. Further to this, in determining whether to take a centralized or decentralized approach to hydrogen generation, careful consideration should be given to load constraints within different zones of the electricity system, and the implication for the ability to operate electrolyzers without any destabilizing effects on the electricity grid.

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4.4 Costs and Benefits One of the primary goals of the feasibility study is to analyze the anticipated financial impact of Hydrail on the RER program. To perform this analysis in a way that will allow for a comparison of Hydrail and the currently contemplated electrification scenarios, models that are in use by Metrolinx were used as the starting point for the analysis presented in this section. The financial impact was analyzed by following six steps: 1. The GO RER network was modelled by CNL (the “Hydrail Operational Simulation Model”) to determine the requirements of a Hydrail System (quantity of hydrogen needed, infrastructure requirements, fuelling). 2. The IBC model from 2014 was analyzed to gain an understanding of how the BCR was developed and to identify the key items that would change under a Hydrail scenario. 3. Relevant cost inputs from the Hydrail simulation model were used to update the IBC model. An interface sheet was developed to capture capital, capital replacement, operating, and maintenance costs for Hydrail. 4. Low- and high-cost scenarios were developed for key input variables (for example, cost of electricity, capital costs of Hydrail components and life cycle of assets). These assumptions were used to develop a range of costs for the Hydrail System. 5. A sensitivity analysis was then performed to determine which cost inputs have the most significant impact on total cost. Those costs were then further scrutinized. 6. Based on the results of the sensitivity analysis, Low- and high-cost ranges were finalized to allow for comparison with overhead electrification. The financial modelling process is shown in Figure 4-39. Each step in the modelling process will be reviewed in more details in the sections that follows.

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FIGURE 4-39 HYDRAIL MODELLING PROCESS Modeling Stage Incremental Benefits of RER ÷ Incremental Costs of RER BCR

Review of RER • New & existing transit user time Operating Costs: Capital Costs: Benefit‐Cost savings • Crew, fuel costs • Infrastructure, fleet, car • Peak & off‐peak road user time savings • Rolling stock, infrastructure parking, maintenance facility, Ratio (BCR) • Automobile operating cost reduction maintenance property costs 3.07 • Safety benefits • Electrification OPEX • Union station costs • Other • Electrification CAPEX • Other

Hydrail System Incremental Costs of RER Hydrail Modeling Hydrail simulation including updates to costs associated with electrification, Unchanged including high/low estimations for: • CAPEX • OPEX • Maintenance

Comparative IBC Unchanged Updated to include incremental Costs of RER hydrail 2.65 – 3.01 Analysis

Sensitivity Identify three cost inputs which explain variability in capital Analysis and operating costs Unchanged Hydrial CAPEX, OPEX and Maintenance cost most sensitive to: • Price of fuel cells ($/kW) • Lifetime of fuel cells (hours) • Cost of electricity ($/MWh) Notes: CAPEX = capital expense OPEX = operating expense

4.4.1 Review of RER Benefit to Cost Ratio Development The model used for purposes of the feasibility study is the IBC for RER. The IBC model was developed by a team of Metrolinx staff and consultants in April 2014 in response to the commitment made by the Province of Ontario to implement RER within a 10-year period. The IBC model outlines the business case to support RER. Outputs include net benefits, system costs and BCRs. Net benefits explain whether a scheme is actually worthwhile as a whole, and if it is, by how much. For instance, time savings to existing and new transit users is a benefit of RER. A complete list of benefits is provided in the ensuing sections. The BCR also shows how much confidence is required in the accuracy of the cost and revenue estimates. System costs include capital costs and operating costs, which will be discussed in detail in the following sections. The IBC model includes virtually every aspect of the GO rail system and models the impact of converting the system from a diesel-powered commuter railway to an electric regional express system that will provide faster, more frequent and all-day services across the Greater Toronto and Hamilton Area (GTHA). The model includes a financial case (i.e., estimation of capital costs, overheads, revenues, other income), an economic case (i.e., estimation of benefits), and a deliverability and operations case (i.e., Union Station, maintenance facilities, and operating and maintenance cost

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT estimates). The IBC model evaluates benefits and costs associated with five different build-out and operating scenarios131, including:  Scenario 1: Do Minimum - Peak-focussed limited capital with no electrification.  Scenario 2: Two-Way All-Day - Enhanced diesel service on all corridors with no electrification.  Scenario 3: 10-Year Plan - Frequent service on most inner corridors with limited electrification.  Scenario 4: Full Build (Beyond 10-Year Plan) - Frequent service on all inner corridors with full electrification.  Scenario 5: Optimized (10-Year Plan Optimized) - Frequent service on most inner corridors with significant electrification will be achieved under this scenario. The IBC model evaluates each scenario over 60 years, from January 1, 2015 to December 31, 2074. All monetary values are in 2014 Canadian dollars. Except where otherwise indicated, future values are presented as net present value (NPV), using a real discount rate of 3.5 percent per year. The model has provision for escalation of many costs and for some other key assumptions, including train crew wage rates, diesel fuel, traction electricity, cost of driving, value of time (VOT) and average GO rail fares. Automobile operating costs are assumed to rise at 0.7 percent per year in real values, while VOT is assumed to increase at 1.6 percent per year in real values. All benefit and cost figures are calculated as incremental to the Do Minimum scenario, which forms the base case. Examples of variables included in the IBC model include project timing, rolling stock and fleet configurations, train services, network infrastructure and connectivity, track ownership, station and maintenance facilities, fares, ridership/demand, economic benefits, bus operations, parking, and others to enable monitoring of economic attractiveness. Figure 4-40 illustrates the modular construction of the model.

131 GO RER Initial Business Case http://www.metrolinx.com/en/regionalplanning/projectevaluation/benefitscases/GO_RER_Initial_Business_Case_EN.pdf

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FIGURE 4-40 MODULAR CONSTRUCTION OF THE IBC MODEL

To the extent possible, the IBC model reflects the structure of costs and understanding of passenger behaviour. Unit rates and total rates of growth, including costs, revenues and productivity factors, have been calibrated against actual experience, either by GO or by comparable operators. Infrastructure capital costs are based on recent GO project costs. The IBC model can be used to test different service options, assumptions and policies. Table 4-29 includes key economic, cost, and policy assumptions included in the IBC model.

TABLE 4-29 KEY ASSUMPTIONS INCLUDED IN THE IBC MODEL Item Assumption Project Life 60 years Discount Rate 3.5% percent Implementation All new services commence 2024 Underlying Demand Growth 2.3% per year on average (varies by route) to 2044; in all scenarios, peak capacity is added to maintain current average train loads Fares No changes to 2015 fare structures; no real increases in fares (i.e., no fare increases ever) Other Charges Other charges are assumed, represented by a potential parking charge implemented before the end of the RER program Costs No real increase in train crew labour, diesel fuel or electricity costs

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TABLE 4-29 KEY ASSUMPTIONS INCLUDED IN THE IBC MODEL Item Assumption Auto Operating Costs $0.63 per kilometre, increasing at 0.7% per year to 2044 Environmental Assessment, Engineering and Design 15% percent of base capital costs Infrastructure (Corridors) Contingency – 50% of base capital costs Productivity and resource factor – 25% of base capital costs Infrastructure (System-wide components) Contingency – 50% of base capital costs

Costs in the IBC Model The IBC model includes capital and operating costs as categorized in Table 4-30.

TABLE 4-30 CATEGORIZATION OF COSTS IN THE IBC Capital Costs Infrastructure (stations, tracks, retaining walls) Electrification capital costs Property Car parking Fleet Union Station capital costs CN and CP Accommodation CBTC signalling system PTC Electrification of Willowbrook EMU Maintenance Facility Other Operating Costs Crew Fuel Electricity for Traction Rolling Stock Maintenance Infrastructure Maintenance User Charges - Plant and Roadway Other Notes: CN = Canadian National Railway CP = Canadian Pacific Railway PTC = positive train control

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IBC Model: Capital Costs Capital cost estimates were completed in 2014 based, wherever possible, on GO’s most recent project experience. This is the case mostly with track, stations, civil infrastructure (such as bridges), retaining walls, noise walls, road-rail and rail-rail grade separations, conventional signalling, diesel locomotives, unpowered bi-level cars and property acquisition. Electrification, electric rolling stock, and advanced train control prices were based on a range of industry sources, both published and confidential. Infrastructure costs include engineering costs and contingencies. As part of RER, many existing stations will require new platforms and, therefore, additional access tunnels and shelters may be required. In some cases, stations will undergo significant change due to additional track or realignment for bus interchanges. Passenger pick-up will also require modification to support increased ridership. Additional property may be required at many station locations. The model also accounted for increased parking requirements at expanded stations. For RER, additional tracks are required at various locations on each corridor. Typically, hourly two-way service requires a passing track, while a full second track is required where trains operate every 15 minutes. A third or fourth track is required where there are express services or where tracks are shared between two or more services, which may include inter-city rail services and freight services. In all scenarios, costs to install Positive Train Control (PTC132) signalling systems on new track were included. PTC is a set of highly advanced safety technologies designed automatically stop a train before certain types of accidents occur. It was also noted that, although not yet a legal requirement in Canada, systems similar to PTC are installed on many RER systems, and were required on passenger rail routes in the U.S. at the time of publishing the report. Union Station is the heart of the GO network, and will continue to be the main destination for peak commuters from across the GTHA. It is anticipated it will also become a significant interchange point within the GO rail network and attract greater inbound flows of boarding passengers than is the case today. Also, there is the potential to attract more trips connecting places on either side of Union Station, which could be a benefit of running more trains through the station as opposed to terminating many train routes at Union Station, as is common practice today. Improvements to the tracks on either side of Union Station and to platform infrastructure will enable the number of trains RER will schedule to pass through and serve Union Station. IBC Model: Operating Costs Operating cost rates were calculated in 2014, mostly from existing GO costs, as determined from analysis of GO general ledger documents. Costs were calculated based on the service levels as defined, driven by train crew hours, train kilometres, route kilometres, or vehicle kilometres as appropriate. Diesel fuel and traction electricity consumption and costs were estimated based on data presented in the 2010 GO electrification study and actual GO experience. As with diesel prices, no long-term change was assumed in electricity prices. Other operating costs in the IBC include payments to the CN and the CP for track use and dispatching costs that are calculated from existing charges, adjusted for train-kilometres; rolling stock maintenance costs that are based on Canadian and U.K. experience, including GO’s existing contract

132 Positive Train Control is a system of functional requirements for monitoring and controlling train movements and is a type of train protection system.

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT for the operation of diesel trains; and infrastructure maintenance that includes costs related to track maintenance, signalling infrastructure, and other fixed infrastructure costs. IBC Model: Benefits Most of the benefits were estimated based on the ridership that was forecast on RER. Note that increments were for future years, with and without RER. In other words, the comparison was between what the system would look like under Scenario 1 – Do Minimum and the contemplated system expansion scenarios. Benefits quantified in the IBC model are transport-related benefits that are categorized as follows:  Time savings to existing and new transit users.  Auto cost savings to drivers switching to transit.  Quality benefits such as improved comfort, convenience and reliability for transit users.  Safety benefits, primarily reduced accident costs.  Crowding benefits to transit users.  Road-user benefits, cost and time savings to motorists from reduced congestion. The IBC also considered wider economic and environmental benefits, but these were not captured by the modelling exercise so were not included in the calculation of the BCRs. IBC Model: Benefit to Cost Ratios The BCRs provided information to decision makers regarding how the overall benefits compare to the overall costs. A ratio greater than one (for example, 2:1) means that the net benefits outweigh the costs. A ratio less than one (for example, 1:3) means that the costs outweigh the benefits. In the IBC model, the ratios were calculated by dividing the incremental benefits of a given scenario by the incremental costs of a given scenario. The magnitude of the result also communicated important information about the confidence that decision makers can have in the result. If the BCR is, for example, 3:1, then decision makers can have a high level of confidence that a scenario is beneficial. The actual costs would have to be three times higher, or revenues or other benefits one-third of what is expected, before the scenario would prove not to be beneficial. If the estimated BCR is close to 1:1, then any cost overrun or ridership shortfall could bring the result below 1:1, making the scenario as proposed not worthwhile. IBC Model: Cost Factors As outlined previously inTable 4-29, the IBC applied several cost factors and contingencies to the capital costs for overhead electrification. These cost factors include:  A cost factor for Environmental Assessment, Engineering and Design that is 15 percent of base capital costs.  A construction contingency for the on-corridor infrastructure that is 50 percent of base capital costs.  A productivity and resource cost factor that is 25 percent of base capital costs for on-corridor infrastructure.  A construction contingency on system-wide infrastructure components of 50 percent of base capital costs

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Result of the IBC The analysis of BCRs in the IBC resulted in the recommendation that Metrolinx proceed with Scenario 5. Scenario 5 was subsequently adopted by the Province as the plan for RER. Under Scenario 5, GO would operate all-day services every 15 minutes to Aldershot, Mount Pleasant, Aurora, Unionville and Oshawa and introduce electrification to Bramalea, Barrie, Stouffville and Pearson Airport. Electric trains would replace diesels on some or all of the Lakeshore East and West, Kitchener, Barrie, and Stouffville lines. Under this scenario, the Milton and Richmond Hill lines would continue to operate at peak times only, using diesel locomotives. 4.4.2 Hydrail System Modelling Key Characteristics of Cost Estimation According to the cost estimating and assessment guide published by the United States Government Accountability Office (GAO), a cost estimate should have certain basic characteristics as listed in Table 4-31.

TABLE 4-31 BASIC CHARACTERISTICS OF COST ESTIMATES133 Characteristic Description Clear identification of task  Estimator must be provided with the system description, ground rules and assumptions, and technical and performance characteristics  Estimate's constraints and conditions must be clearly identified to ensure the preparation of a well-documented estimate Broad participation in  All stakeholders should be involved in deciding mission need and requirements and in preparing estimates defining system parameters and other characteristics  Data should be independently verified for accuracy, completeness, and reliability Availability of valid data  Numerous sources of suitable, relevant, and available data should be used  Relevant, historical data should be used from similar systems to project costs of new systems; these data should be directly related to the system's performance characteristics Standardized structure for  A standard work breakdown structure (WBS), as detailed as possible, should be used, the estimate refining it as the cost estimate matures and the system becomes more defined  The work breakdown structure ensures that no portions of the estimate are omitted and makes it easier to make comparisons to similar systems and programs Provision for program risk  Uncertainties should be identified and allowance developed to cover the cost effect and uncertainty  Known costs should be included and unknown costs should be allowed for Recognition of inflation  The estimator should ensure that economic changes, such as inflation, are properly and realistically reflected in the life-cycle cost estimate  Recognition of excluded costs  All costs associated with a system should be included; any excluded costs should be disclosed and given a rationale Independent review of  Conducting an independent review of an estimate is crucial to establishing confidence estimates in the estimate; the independent reviewer should verify, modify, and correct an estimate to ensure realism, completeness, and consistency Revision of estimates for  Estimates should be updated to reflect changes in a system’s design requirements. significant program changes Large changes that affect costs can significantly influence program decisions

133 US GAO Cost Estimating and Assessment Guide, 2009

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The Cost Estimating Process At the feasibility stage of project evaluation, it is important to understand how a cost estimate is developed to understand the level of certainty associated with that estimate; this process is illustrated on Figure 4-41.

FIGURE 4-41 THE COST ESTIMATING PROCESS

3. Define 4. Determine 5. Identify the the estimating ground rules & program structure assumptions 1. Define 2. Develop 9. Conduct a the the 8. Conduct risk and estimate’s estimating sensitivity uncertainty purpose plan 7. Develop the point estimate and analysis 6. Obtain compare it to an independent cost the data estimate

The first step involved in cost estimating is defining the estimate’s purpose. At this stage, the project team will also define the required level of detail and the overall scope of the costing exercise. Cost estimates have two general purposes: (1) to assist in the evaluation of affordability of a project or program and to inform the selection of alternative systems and solutions, and (2) to support the budget process by providing estimates of the funding required to execute a program134. In the case of the Hydrail feasibility study, the cost estimate serves both purposes; it is designed primarily to assist in the evaluation of alternative solutions but will also contribute to an understanding of the potential budget implications of a Hydrail System over the life of the service. All costs directly related to electrification with Hydrail were modelled and updated in the IBC model. All other costs, including station improvements, were excluded from the Hydrail costing exercise. The second step involved in the estimating process is the development of an estimating plan. For Hydrail, this involved the use of specialist teams to develop cost estimates for the hydrogen related components of the system. These estimates were then incorporated into IBC model. The next five steps (steps three through seven) are the beginning of an iterative process that leads to a point estimate of the program cost. The details of these steps are described in Table 4-32.

134 US GAO Cost Estimating and Assessment Guide, 2009, pg. 47

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TABLE 4-32 DESCRIPTION OF STEPS INVOLVED IN DEVELOPING A POINT COST ESTIMATE135 Step Description 3. Define program  Identify the program's purpose and its system and performance characteristics and all characteristics system configurations;  Any technology implications;  Its relationship to other existing systems;  System quantities for development, test, and production;  Deployment and maintenance plans 4. Determine estimating  Define a work breakdown structure (WBS) and describe each element in a WBS dictionary; structure  Choose the best estimating method for each WBS element;  Identify potential cross-checks for likely cost and schedule drivers;  Develop a cost estimating checklist. 5. Identify ground rules  Clearly define what the estimate includes and excludes; and assumptions  Identify global and program-specific assumptions, such as the estimate's base year, including time-phasing and life cycle;  Identify program schedule information by phase and program acquisition strategy;  Identify any schedule or budget constraints, inflation assumptions, and travel costs;  Specify equipment the government is to furnish as well as the use of existing facilities or new modification or development;  Identify prime contractor and major subcontractors;  Determine technology refresh cycles, technology assumptions, and new technology to be developed;  Define commonality with legacy systems and assumed heritage savings;  Describe effects of new ways of doing business. 6. Obtain data  Create a data collection plan with emphasis on collecting current and relevant technical, programmatic, cost, and risk data;  Investigate possible data sources;  Collect data and normalize them for cost accounting, inflation, learning, and quantity adjustments;  Analyze the data for cost drivers, trends, and outliers and compare results against rules of thumb and standard factors derived from historical data;  Interview data sources and document all pertinent information, including an assessment of data reliability and accuracy;  Store data for future estimates. 7. Develop point  Develop the cost model, estimating each WBS element, using the best methodology from estimate and compare it the data collected, and including all estimating assumptions; to an independent cost  Express costs in constant year dollars; estimate  Time-phase the results by spreading costs in the years they are expected to occur, based on the program schedule;  Sum the WBS elements to develop the overall point estimate;  Validate the estimate by looking for errors like double counting and omitted costs;  Compare estimate against the independent cost estimate and examine where and why there are differences;  Perform cross-checks on cost drivers to see if results are similar;  Update the model as more data become available or as changes occur and compare results against previous estimates.

135 Adapted from GAO Cost Estimating and Assessment Guide, 2009

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The eighth step in the estimating process involves a sensitivity analysis. The sensitivity analysis is designed to reveal how the cost estimate is affected by a change in a single assumption. The cost estimator must examine the effect of changing one assumption or cost driver at a time while holding all other variables constant. By doing so, it is easier to understand which variable most affects the cost estimate. In some cases, a sensitivity analysis can be conducted to examine the effect of multiple assumptions changing in relation to a specific scenario. Regardless of whether the analysis is performed on only one cost driver or several within a single scenario, the difference between sensitivity analysis and risk or uncertainty analysis is that sensitivity analysis tries to isolate the effects of changing one variable at a time, while risk or uncertainty analysis examines the effects of many variables changing all at once. The sensitivity analysis can be useful for identifying areas where more design research could result in less production cost or where increased performance could be implemented without substantially increasing cost.136 For Hydrail, sensitivity analysis was used to narrow focus on the variables that had the largest impact on the cost of the Hydrail program; these variables were subsequently reviewed in further detail to refine the estimate of the cost input. The final step in the estimating process is the risk and uncertainty analysis. Because cost estimates are a prediction of future program costs, uncertainty is always associated with them. For example, data from the past may not always be relevant in the future, because new manufacturing processes may change a learning curve slope or new composite materials may change the relationship between weight and cost. Regulatory conditions can also impact costs. Moreover, a cost estimate is usually composed of many lower-level WBS elements, each of which comes with its own source of error. Once these elements are added together, the resulting cost estimate can contain a great deal of uncertainty.137 This step of the estimating process involves evaluating the risk and uncertainty associated with a project and incorporating the potential cost of this risk and uncertainty into the total cost estimate. Risk and uncertainty reflect the fact that, because a cost estimate is a forecast, there is always a chance that the actual cost will differ from the estimate. Lack of knowledge about the future is only one possible reason for the difference. Another equally important reason is the error resulting from historical data inconsistencies, assumptions, cost estimating equations, and factors typically used to develop an estimate.138 In the early phases of any program, knowledge about how well technology will perform, whether the estimates are unbiased, and how external events may affect the program is imperfect. To enable good decision making, the program estimate must reflect the degree of uncertainty.139 Estimates are more uncertain at the beginning of a project because less is known about the detailed requirements and the opportunity for change is great. As the project progresses, requirements become better defined and risk better understood. As this happens, costs become more certain. In many cases, costs also increase as project development progresses due to a better understanding of additional requirements translating into previously unforeseen costs. This progression is illustrated in Figure 4-42.

136 US GAO Cost Estimating and Assessment Guide, 2009, pg. 147-148 137 ibid., pg. 153 138 ibid. 139 ibid., pg. 154

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FIGURE 4-42 CHANGES IN COST ESTIMATE UNCERTAINTY ACROSS THE PROJECT DEVELOPMENT LIFECYCLE140

It is typical to use four classes to represent the level of design, and associated uncertainty, at different project stages. These classes are defined as follows:  Class A (Detailed Design - 100 percent design) estimates are pre-tender estimates, based on completed construction drawings and detailed specifications contained in tender documents. The expected precision of the estimate ranges from -5 percent to +10 percent of the actual contract price.  Class B (Design Development - 67 percent design) estimates are design estimates based on an advanced project design. They are based on design drawings, project specifications and include detail on the design of electrical, mechanical and IT systems, as well as site requirements. The expected precision of the estimate ranges from -10 percent to +15 percent of the actual contract price.  Class C (Schematic Design - 33 percent design) is a planning level estimate usually based on a Schematic Design and presented in Elemental Format (a budget setting format/technique which considers the major elements of a project and provides an order of cost estimate based on an Elemental Cost Analysis of a building project). These estimates establish a preliminary budget estimate and a baseline against which project costs will be assessed at future project development milestones. The expected precision of the estimate ranges from -15 percent to +20 percent of the actual contract price.  Class D (Conceptual Design) estimates are conceptual estimates based on the project scope (the work that needs to be accomplished to deliver the project) and functional requirements (the output specifications/deliverables of a project), and are usually presented in unit cost analysis format (applying a monetary rate to an element, subelement or component per unit of measurement). The expected precision of the estimate ranges from -20 percent to +30 percent of the actual contract price.141

140 US Government Accountability Office Cost Estimating and Assessment Guide, 2009 141 PPP Canada Schematic Design Estimate Guide, April 2014.

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The current simulation model could be considered a Class D estimate, with an expected accuracy that ranges from -20 percent to +30 percent of the actual costs. It is expected that the accuracy of the estimate would improve should the feasibility study for Hydrail lead to a decision to move the project to the next stage of development. The technology development process that is proceeding in parallel to this study will further improve the accuracy and reduce the uncertainty of estimate. Estimating accuracy improves significantly and the uncertainty in cost estimation reduces to a few percentage points of the actual costs by the time the detail design is complete and the project is ready for procurement and implementation. It is important to continually update cost estimates so that decision makers have has the best information available for making informed decisions. These processes are illustrated in what is commonly called the Cone of Uncertainty shown on Figure 4-43.

FIGURE 4-43 CONE OF UNCERTAINTY

Development of Contingencies Contingencies for infrastructure projects represent a mark-up applied to the base construction cost to account for uncertainties in quantities, and unit costs. Contingencies are also included to capture risk events during construction.142 At various stages of the estimating process it is possible to represent the uncertainty implications of various cost estimates using a cumulative probability distribution curve or an S-curve as illustrated in Figure 4-44.

142 Cost Estimating Manual for WSDOT Projects, March 2008.

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FIGURE 4-44 SAMPLE CUMULATIVE DISTRIBUTION CURVE FOR A PROJECT ESTIMATE (FROM THE US GOVERNMENT ACCOUNTABILITY OFFICE COST ESTIMATING AND ASSESSMENT GUIDE, 2009)

The contingency then is the difference between the estimated cost and the budget to achieve a certain confidence interval. This concept is illustrated in the following example: The cumulative probability distribution curve provided in Figure 4-44 considers a hypothetical project with an estimated cost of $825,000. The uncertainty analysis has revealed that this estimate represents the 40th percentile meaning that there is a 60 percent chance that costs will be greater than the estimate. Based on this analysis, a decision could be made to increase the project budget to achieve greater certainty that the project cost will fall within the budgeted amount. For example, if the budget for this project was increased from $825,000 to $1,096,000 then there would be a 70 percent probability that project costs would fall within the budgeted amount. The $271,000 difference between the estimated cost and the budgeted $1,096,000 represents the construction contingency in this example.143 The level of confidence used to develop the contingency reflects organizational decisions on the level of risk that is acceptable.

143 US GAO Cost Estimating and Assessment Guide, 2009, pg. 157

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Limitations Given the relatively short time frame for the Hydrail analysis, there are some elements of the cost estimate that have not been completed to the level of detail that could be completed with further study. These elements of the cost estimate that have not been addressed in the Hydrail simulation model are outlined as follows: 1. Work Breakdown Structure (WBS): A WBS defines in detail the components necessary to accomplish a program’s objectives. A WBS can be thought of as an illustration of which tasks will be accomplished and which components will be delivered to satisfy a program’s requirements. The WBS diagrams the effort in small, discrete pieces, or elements, to show how each one relates to the others and to the program as a whole. The number of levels for a WBS varies from program to program and depends on a program’s complexity and risk. WBSs need to be expanded to a level of detail sufficient for planning and successfully managing the full scope of work. However, each WBS should, at the very least, include three levels:  The first level represents the program as a whole so contains only one element—the program’s name.  The second level contains the major program segments.  Level three contains the lower-level components or subsystems for each segment. A sample WBS for a process plant construction144 is shown in Table 4-33 for illustration.

TABLE 4-33 LIST OF SAMPLE WBS ELEMENTS Level 2 Element Level 3 Element 1.1 Plant system design 1.1.1 Business requirements 1.1.2 Process models 1.2 Construction 1.2.1 Site development 1.2.2 Civil structure 1.2.3 Thermal systems 1.2.4 Flow systems 1.2.5 Storage systems 1.2.6 Electrical systems 1.2.7 Mechanical systems 1.2.8 Instrument and control systems 1.2.9 Environmental systems 1.2.10 Temporary structure 1.2.11 Auxiliary systems 1.2.12 Safety systems

144 Source: Project Management Institute, Practice Standards for Work Breakdown Structures, project Management Institute, Inc. (2006).

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TABLE 4-33 LIST OF SAMPLE WBS ELEMENTS Level 2 Element Level 3 Element 1.3 Legal and regulatory 1.3.1 Licensing (nongovernment)/permitting (government) 1.3.2 Environmental impact 1.3.3 Labor agreements 1.3.4 Land acquisition 1.4 Testing 1.4.1 System test 1.4.2 Acceptance test 1.5 Start-up 1.6 Project management

Although a detailed WBS has not been developed for this study, different elements of the Hydrail System have been discussed, and individual components have been identified for costing. The WBS example does, however, provide some insight into additional costs not currently covered by the Hydrail simulation, such as legal and regulatory expenses, testing, startup, and project management expenses. These costs are known elements of a construction project, and although they may not be accurately modelled in the feasibility study stage, they should be recognized in the model, and carefully considered when making a decision based on the findings of the analysis. These cost elements should not be captured under contingencies. By definition, contingency is an allowance for unknown factors that may result in higher project costs, so it should not include cost elements that are known but are absent in the cost estimate. 2. Risk analysis: The methodology for developing construction contingencies discussed involves the use of probabilistic analysis of risk and uncertainty (that is, the contingency represents a markup applied to the base construction cost to account for uncertainties in quantities and unit costs, and is defined as the difference between the base cost estimate and the budget to achieve a certain confidence interval). The confidence interval also depends on decision-makers’ risk appetites. At this stage in the modelling exercise, contingency amounts have been based on the IBC and on the technical expertise of the modelling team. At later stages of the exercise, a quantitative risk assessment will result in a more refined contingency that can be carried into construction and operations phases of the program. 4.4.3 Comparative Cost/Benefit Assessment of the Simulation Scenarios 4.4.3.1 Hydrail Analysis For purposes of this study, the first stage of the financial analysis involved comparing the anticipated costs associated with Hydrail to those for overhead electrification, using the IBC model. Costs that are common to both technologies (for example, track and station improvements) were held constant. Key assumptions (for example, discount rate) were also held constant where reasonable, and adjusted where necessary. As an example, assumptions regarding service patterns—the key driver behind revenues and benefits of RER—were assumed to be equal under both technologies. As such, this part of the study is predicated on an assumption that a Hydrail System would deliver the same level of service as overhead electrification, as is discussed in Section 4.2.2. Inputs that would change (for example, a new cost associated with the production of hydrogen and removal of capital costs associated with overhead electrification) were the focus of the analysis. This allows for a like-for-like

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT analysis of Hydrail relative to Scenario 5 electrification, and mimics going back in time and adding Hydrail as an additional scenario for RER in the 2014 analysis. However, as will be shown in this section, a true like-for-like analysis requires updating certain IBC assumptions to reflect those used for Hydrail. As service levels are assumed to be the same, net benefits of the program as captured in the IBC model do not change under a Hydrail scenario for RER. For purposes of the BCR, benefits are driven by ridership of the RER system and because ridership is assumed to be the same for Hydrail the benefits remain constant. There are numerous potential benefits and risks associated with both overhead electrification and Hydrail that are not captured in the first stage of the IBC analysis. Some are, however, discussed later in this section and in Section 4.7 where the broader social, economic and environmental benefits are discussed. Later in this section, the financial analysis will further examine the impact of Hydrail on capital and operating costs over the lifespan of the RER program, including sensitivity analysis and potential fiscal impacts to the province. It should be noted that within the cost items that were considered common to both technologies there are certain elements that are likely to change between the Hydrail and overhead electric systems. One example is the cost of property purchases currently considered in the IBC. Part of this line item represents the cost to purchase land to develop substations that would be required for an overhead contact system. Such costs would not, however, be required for Hydrail. Conversely, additional land may be required to service Hydrail vehicles (for example, to replace hydrogen tanks at specified service intervals) and may have an impact on land requirements within maintenance yards. However, because the breakdown of cost items like this are not fully understood they have been carried forward in the Hydrail simulation. Should the feasibility study lead to a decision to continue to examine Hydrail, more detailed analysis of these costs would be required to provide a full picture of the cost of each system. The outputs from the Hydrail System simulation described previously were used to develop a schedule of Hydrail costs for incorporation into the IBC model. The key cost drivers for the Hydrail simulation were reviewed and highest and lowest values for these variables were developed. The ranges for these variables are presented in Table 4-34.

TABLE 4-34 KEY COST DRIVERS FOR HYDRAIL Highest Value Lowest Value Unit Cost of electricity 76 46 $/MWh Price of Electrolyzer 823 655 $/kW Price of Storage 266 141 $/kg Price of Refuelling 1,396 1,257 $/kg Price of Dispensing 1.09 0.87 million $/unit Price of Fuel Cell 1,000 450 $/kW Lifetime of Electrolyzer 40,000 50,000 hours Lifetime of Fuel Cell 25,000 40,000 hours

These highest and lowest case values were used to develop a high-cost scenario (where all the variables were set at worst case levels) and a low-cost scenario (where all the variables were set at best case levels) for Hydrail. These labels are not intended to apply any judgment of one technology over another. The values were then used to develop new costs for electrification-related capital cost items,

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT electrification-related operating cost items, and fleets costs. All other costs described above (for example, station expansions, signalling) are held constant. All real costs used in the analysis are in 2014 dollars. The high end and low end for electricity price is estimated using IESO data and an optimized hydrogen production schedule developed by the technical team. For further details, please refer to Section 4.3. 4.4.3.2 Application of Cost Factors in the Hydrail Model As discussed above, contingencies are a key part of the IBC model and, taken together, represent 90 percent of total capital costs. For Hydrail, the approach followed was to carry forward contingencies and make adjustments based on several factors. First, the cost factor for Environmental Assessment, Engineering and Design was increased from 15 percent to 30 percent for Hydrail. The application of HFC technology in the rail industry is still relatively untested (as discussed elsewhere in this report). As such it is reasonable to assume that the percentage of capital costs applied for engineering and design should be higher than what was used to model a traditional overhead electric system through the IBC model. This contingency only applies to initial capital investment and falls to 0 percent as Hydrail assets need to be replaced or refurbished, reflecting the fact that expertise and experience will have grown to a point where such events are highly predictable in terms of costs and risks. Construction contingencies in the IBC model account for uncertainty associated with the cost of the development and construction of a complex electrified rail system. In the IBC model, the construction cost contingency for overhead electrification was 50 percent of estimated capital costs. This contingency has been applied to all civil infrastructure and electrification base costs within the IBC model. For purposes of this financial analysis, construction cost contingencies used in the IBC model have been carried forward for Hydrail without change. A 50 percent contingency is reasonable for capital undertakings where an organization has little experience, in this case signalling, for electrification, and for the development of hydrogen-powered vehicles. Furthermore, the risk associated with deploying a new application of a technology at the scale that would be required for Hydrail, including establishing an entirely new supply chain for the production, transportation and dispensing of hydrogen, further justifies inclusion of this contingency. Additionally, the contingency is meant to capture costs that are currently not well understood for both the overhead and electrification costs – these costs include things like financing costs, operator profit, taxes, and permitting fees. Finally, a productivity and resource cost factor is applied to the on-corridor infrastructure for overhead electrification and to all hydrogen related infrastructure for the Hydrail System (in addition to on- corridor infrastructure required for both systems). This cost factor is intended to capture the additional costs associated with the construction of the RER system in a shorter time frame and more complex environment than what is typical for similar projects. The productivity and resource factor is applied to on-corridor infrastructure base costs to account for construction under increased rail traffic conditions and ongoing service expansions, and includes consideration of limited specialized resources in the industry (particularly for electrification and hydrogen technologies). This factor has not been applied to system-wide costs like enhanced train control and maintenance facilities. The productivity and cost resource factor applied to the overhead electrical system in the IBC is 25 percent and it is understood that much of this factor accounts for the complexity of installing the overhead infrastructure during live rail operations meaning much of the work will have to take place overnight, for example. This same constraint does not exist for Hydrail implementation as capital works would likely not significantly impact operations on the rail corridor. A potential advantage of Hydrail is the ability to roll out fleet incrementally and intermingled with existing rolling stock. It is difficult to predict with accuracy at this stage of the project if there might be disruptions or complications associated with a mixed-fuel fleet,

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT or the impact construction of hydrogen production and fuelling stations might have on current operations. As a result, the productivity and cost resource factor for Hydrail has been reduced from 25 percent to 10 percent. Further refinement is necessary to the cost factors to account for the life cycle of electrification and Hydrail capital assets. Hydrail will require CAPEX throughout the life of the RER program to replace, either fully or partially, components of the system like the fuel cells and on-board storage tanks. This contrasts with overhead electrification where a large upfront CAPEX is expected but, based on the long life-span of these capital components, ongoing expenditures have been assumed within IBC to be limited to routine maintenance as opposed to system-wide replacement. While there are ongoing CAPEX as part of Hydrail, it is expected that there will be greater cost certainty and potential design and production cost savings as the Hydrail program ages and the technology matures. As such, the cost escalation factors that are applied to initial CAPEX in the overhead electrification case and the Hydrail case are not applied to the on-going expenditures related to the replacement or refurbishment of Hydrail specific capital components. Cost factors discussed in this section are summarized in Table 4-35.

TABLE 4-35 COST FACTORS APPLIED IN THE IBC Cost Factors Applied in the IBC Overhead Electrification Hydrail Environmental Assessment, 15 percent of base capital costs 30 percent of base capital costs Engineering and Design Infrastructure (Corridors) Contingency – 50 percent of base capital Contingency – 50 percent of base capital costs costs Productivity and resource factor – 25 percent Productivity and resource factor – 10 of base capital costs percent of base capital costs Infrastructure (System-wide Contingency – 50 percent of base capital Contingency – 50 percent of base capital components) costs costs

4.4.4 Sensitivity Analysis Following the development of the capital and operating costs for the Hydrail System, a sensitivity analysis was performed to quantify the impact of each individual variable on the be BCR using the following approach:  All cost variables were set at their high case values to establish a baseline for comparison (that is, the high scenario).  Each variable was then individually changed to its lowest case while keeping all other variables unchanged.  The NPV of the following outputs were recorded for each iteration:  Total CAPEX = total initial capital + total replacement cost  Total OPEX = total operating cost + total maintenance cost  The change in NPV was calculated and sorted from highest to lowest. The sensitivity analysis shows that three variables result in largest variation in the NPV of the selected outputs:  Cost of electricity  Lifetime of fuel cell  Price of fuel cell

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The sensitivity analysis shows that all other variables have a negligible effect (that is, below 2 percent) on the output parameters. The outputs from the sensitivity analysis are presented in Table 4-36. This analysis was used to guide the modelling team to the variables that require the most precision and that warrant the most in-depth analysis through conversations with industry and research.

TABLE 4-36 OUTPUT OF THE SENSITIVITY ANALYSIS High Low percent Change Cost of electricity ($/MWh) 76 46 - NPV of Total OPEX 2,356 1,623 -31 percent Price of fuel cell ($/kW) 1,000 450 - NPV of Total CAPEX 2,595 2,070 -20 percent Lifetime of fuel cell (hours) 25,000 40,000 - NPV of Total CAPEX 2,595 2,325 -10 percent

4.4.5 Model Benchmarking In addition to the financial analysis presented in this section, the hydrogen pricing model was compared to publicly available case studies. This exercise provides a benchmark for the result of the modelling exercise used in Hydrail feasibility study. Several key technologies for producing hydrogen were studied by the H2A145 team with expertise in design and advancement of these technologies within the United States Department of Energy Hydrogen and Fuel Cells Program146. One case study covers future estimates for central hydrogen production using PEM technology. The model inputs were modified to match requirements of the Hydrail project (that is, total hydrogen production, price of electricity, unit cost of electrolyzer and total capacity installed), as shown in Table 4-37.

TABLE 4-37 INPUT PARAMETERS FOR A CENTRAL HYDROGEN PRODUCTION FACILITY Cost Component Unit DOE CNL Hydrogen production tonnes /day 48.5 48 price of electricity $/MWh 66 63 cost of electrolyzer $/kW 508 508 lifetime of stack years 10 15 electrolyzer capacity installed MW 293 281

The results of the DOE model were then compared against the Hydrail simulation model. The results of this analysis are shown in Table 4-38.

145 H2A, which stands for Hydrogen Analysis, was first initiated in February 2003 to better leverage the combined talents and capabilities of analysts working on hydrogen systems, and to establish a consistent set of financial parameters and methodology for analyses (https://www.hydrogen.energy.gov/h2a_analysis.html) 146 Please refer to https://www.hydrogen.energy.gov/h2a_prod_studies.html

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TABLE 4-38 RESULTS OF THE CENTRAL HYDROGEN PRODUCTION FACILITY MODELS Cost Component DOE Hydrail Simulation Capital Costs ($)

Total direct capital $ 148,259,713 $ 147,957,111 Total indirect depreciable capital $ 27,817,995 $ - Site Preparation $ 3,272,705 $ - Engineering and design $ - $ - Project contingency $ - $ - Up-Front Permitting Costs (legal and contractor fees) $ 24,545,290 $ - Total depreciable cost $ 176,077,708 $ - Total non-depreciable cost $ 305,320 $ - Total capital cost $ 176,383,028 $ 147,957,111 Operating Costs ($)

Fixed operating cost (maintenance) $ 4,521,768 $ 2,351,710 Variable operating cost (cost of electricity) $ 58,588,148 $ 58,199,567 Total operating cost $ 63,109,916 $ 60,551,277

Cost of hydrogen production ($/kg) Depreciable cost of capital 0.99 0.56 Variable operating cost 3.31 3.31 Fixed operating cost 0.26 0.13 Other costs 0.23 - Initial Equity Depreciable Capital 0.00 - Cash for Working Capital Reserve 0.02 - Debt Interest 0.11 - Taxes -0.01 - Principal Payment 0.10 - Cost of production ($/kg) 5.02 4.01

The results of the two models are categorized as follows:  Capital costs: total capital cost estimated under the DOE model is approximately $30 million (19 percent) higher than those estimated by the Hydrail simulation. This is because some up-front costs (including permitting and legal costs), as well as site preparation costs, are not included in the Hydrail simulation model. It is important to note, however, that the two models produce comparable results for direct capital costs.  Operating costs: maintenance costs are estimated to be higher in the DOE model than in the Hydrail simulation model by approximately $2.5 million per year. The DOE model yields a result for operating costs that is very close to the Hydrail simulation model (4 percent variance).

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This analysis shows that the cost of hydrogen production (which is represented as $ per kg of hydrogen produced) is 20 percent lower in the Hydrail simulation model than the DOE model for the following reasons:  Approximately half of the difference is driven by the indirect capital costs. The following cost elements have not been captured in the Hydrail simulation model:  Site preparation cost  Permitting and legal costs  The remaining half is driven by financing costs and taxes associated with producing hydrogen that are not currently captured in the Hydrail simulation model. These costs include:  Initial equity depreciable capital;  Cash for working capital reserve;  Debt interest;  Principal payment; and  Taxes. 4.4.6 Results of the Hydrail Modelling Exercise The process discussed above outlines a systematic method for developing cost estimates. This process was used to develop, refine, and understand the cost estimate for the Hydrail System and how this estimate compares to the cost estimates for overhead electrification as presented in the 2014 IBC model. The IBC analysis resulted in a BCR of 3.07 for overhead electrification (Scenario 5). The update to the IBC model for Hydrail results in a BCR of 3.01 under the low-cost scenario and 2.65 under the high- cost scenario. According to this analysis, the costs of Hydrail and overhead electrification appear to be comparable in the low-cost scenario and the overall benefits continue to outweigh the costs of the system in all scenarios. Table 4-39 provides a high-level overview of the 60-year NPV costs and BCRs under the traditional overhead, and low, and high scenarios for Hydrail.

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TABLE 4-39 COSTS AND BCRS FOR ELECTRIFICATION SCENARIOS (60-YEAR NPV COSTS WITH A BASE- YEAR OF 2014)* Traditional Overhead Low Hydrail High Hydrail Electrification System System ($ M) ($ M) ($ M)

Operating Costs A 12,277 12,706 13,309 Capital Costs Initial Capital for Energy System Infrastructure B1 1,762 576 712 (2015 to 2024) Ongoing Capital for Energy System B2 - 257 356 Infrastructure (2025 to 2074) Energy System B=B1+B2 1,762 833 1,068 Initial Capital for Fleet (2015 to 2023) C1 2,260 2,703 2,986 Ongoing Capital for Fleet (2024 to 2074) C2 1,845 2,132 2,531 Fleet C=C1+C2 4,105 4,835 5,517 Total Capital Cost for Energy System and D=B+C 5,867 5,668 6,585 Fleet Other Capital Costs E 7,074 7,074 7,074 Total Capital Costs (D + E) B=D+E 12,942 12,742 13,659 Total Costs A+B 25,218 25,497 27,030 BCR 3.07 3.01 2.65 *Numbers may not sum due to rounding.

In Table 4-39, costs are represented as follows: (A) The total operating costs for the system, including estimates for the cost of maintaining rolling stock, hydrogen equipment, the overhead system, stations, and other components of the RER system. (B) The total capital cost of the system, including costs spent during construction of the system and capital expenditures required throughout the 60-year life of the RER program. (C) The total capital cost for the energy system and the fleet; for overhead electrification, this includes the cost of the catenary system and all electric vehicles and for Hydrail this includes all hydrogen equipment (both on- and off-vehicle equipment) and the cost for the vehicles themselves. (D) The cost for the energy system; for overhead electrification, this is the cost of the catenary system and for Hydrail this is the cost of the off-vehicle hydrogen equipment (for example, electrolyzers and distribution equipment). (E) The cost for the fleet; for electrification, this includes electric locomotives and EMUs and for Hydrail the cost represents locomotives and EMUs including the on-vehicle hydrogen equipment that will be used to power the vehicles (that is, fuel cells, batteries, and storage tanks). (F) Other capital costs required to develop the RER system including station modifications and track upgrades.

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Under both (D) and (E), initial capital (that is, capital spent during the construction or development phase of RER) and ongoing capital (that is, capital spent once the RER program is operational) are included as separate items. The intention is to illustrate the difference between overhead electrification and Hydrail as it relates to the distribution of spending over the lifetime of the RER program. When undertaking a like-for-like analysis through the IBC model, Hydrail shows a slight to moderate disadvantage when compared to overhead electric. This suggests higher costs will be observed throughout the life of the RER program. Under a low scenario the model shows only a small decline in the BCR between when compared to the overhead electrification case. Conversely, if a costlier scenario materializes (for example, electricity prices are higher in 2040 than expected), the outcome could impact into reduced BCR for Hydrail. The sensitivity analysis suggests that there are three factors that will have the most significant impact on cost. In order of importance these are: price of electricity; lifespan of fuel cells; and cost of fuel cells. Given the potential impact on the final results, these are the items where further analysis should focus. It is important to emphasize that the costs contained throughout the models (including IBC) are not intended to reflect the price to install and manage the system under a typical commercial arrangement. Such information would only be clearly understood following a market sounding exercise followed by a competitive procurement process. Other Benefits of Hydrail Other benefits of Hydrail (for example, establishing a hydrogen economy, local jobs) have been captured by a separate modelling exercise within the feasibility study. The socio-economic study examines:  Employment and GDP benefits  A reduction in disruption related to the construction of an overhead system in a live rail corridor.  The potential to develop a 'hydrogen economy' in the province that could spur the deployment of hydrogen for other applications.  Supporting deployment of hydrogen for commercial use in transportation (for example, passenger vehicles, buses, commercial vehicle).  The opportunity to support development of hydrogen based energy storage systems, which will facilitate the increased use of renewable energy in Ontario's electricity system w harness surplus energy 4.4.7 Updates to the IBC Metrolinx is currently in the process of updating the cost estimate for overhead electrification that was developed as part of the IBC. As discussed earlier in this chapter, during early stages of a project, where the design of a system is still in initial stages of development, large variability can be expected in cost estimates. As more detailed design is completed, costs are better understood and, in many cases, rise as a better understanding of the project often reveals costs not previously accounted for. Based on the update to overhead electrification costs currently underway, it appears that costs for overhead electrification will be higher than estimated in the IBC. The updated costs will not be finalized until after the completion of the Hydrail feasibility study and, therefore, these updates are not reflected in this analysis. Based on the work currently ongoing to update the cost estimate for overhead electrification there is an expectation that CAPEX and OPEX will be higher than envisioned in the IBC. Adjusting for these higher costs, the BCR in the IBC could fall below 3.07, as is currently captured by the IBC model.

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The estimated BCR for Hydrail may also change due to refinements in the technical model or changes to electricity policies. As illustrated in Figure 4-45, further modelling work may result in greater hydrogen required for the Hydrail System, which could result in increased capital and operating costs. Consequently, the BCR would be reduced from 2.65 as currently estimated in the high-cost case. On the other hand, an electricity policy change that results in lower electricity prices will improve the BCR from 3.01 as currently estimated in the low-cost case. It is however noted that any future electricity policy change that results in lower electricity prices could also improve the BCR for the overhead electrification case.

FIGURE 4-45 POTENTIAL CHANGES IN THE BCR OF AN OVERHEAD ELECTRIC SYSTEM COMPARED TO HYDRAIL

*Arrows are meant to illustrate potential higher and lower BCR ranges based on analysis to be completed in the future. 4.4.8 Other Considerations It is also important to note that there are several key considerations that are not captured by the IBC analysis that are critical to the overall business case and a decision on the technology that should be used to electrify the GO network. These considerations as discussed below include potential benefits from Hydrail, areas where it is unclear whether there is a benefit or a risk, and risks associated with deployment of Hydrail. First, the IBC model work likely does not completely account for the value of the risk associated with constructing an overhead electric system in a live rail corridor. Although an adjustment has been made to the Productivity and Resource cost factor to reflect reduced complexity associated with the construction of a Hydrail System, this adjustment likely does not fully capture the entire value of avoided risk that would be inherent to installing an overhead contact system on a live rail corridor, something that is rarely done in the rail industry. Second, Hydrail may present an opportunity to more gradually deploy HFC-powered train sets and to potentially achieve this roll out with little to no disruption to existing rail operations. RER service levels are currently scheduled to begin in 2024 accordingly, this is when additional operating costs begin and related benefits are expected to be realized. If Hydrail is deployed, commencement of RER

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT services may not be binary as is the case for overhead electrification. As Hydrail vehicles are delivered to Metrolinx, it may be possible to deploy these vehicles on a portion of the GO network before bringing the entire system online. This could potentially allow RER benefits to be realized earlier than would be the case through overhead electrification. While this phased roll-out could help to realize additional benefits, it could also increase operational complexity as some lines would be operating at significantly increased service levels and speeds that may be difficult to coordinate with slower routes through Union Station. This potential benefit could also be negated because of the need to develop a hydrogen supply chain across the GO network. Further analysis will need to be undertaken to understand if there may be regulatory, safety, operational or commercial considerations that may hinder ability to seamlessly deploy a mixed fleet of hydrogen and diesel train sets as is assumed in making this statement. Third, the IBC model work likely does not sufficiently capture the comparison between maintenance requirements of the two systems. While in concept, maintenance of fuel cells can be done without significant disruption, the entire maintenance regime for a Hydrail train is not fully understood. In some cases, manufacturers may require that maintenance is undertaken by their own trained workforce, or a workforce with certain credentials. This could introduce operational complexities if, for example, different workers are needed to maintain various components of the hydrogen system. The maintenance cycle may be further complicated by regulatory requirements associated with, for example, replacement of tanks and how the system is safety tested after such events. Furthermore, the amount of downtime associated with servicing Hydrail vehicles compared to traditional electric vehicles is unknown. This could impact the configuration of maintenance facilities and the size of the fleet. The key point is not that the costs will be higher, but that maintenance requirements will be more complex and will require different processes to be followed, potential impacts on facilities and fleet, and likely a higher skilled workforce. The specific nature of these differences is unknown and has not been quantified through the IBC model. Forth, it is reasonable to assume that accreditation requirements of those undertaking work on the hydrogen related components of the trains will likely be more stringent than for those servicing traditional electric vehicles. The potential for limited availability of technicians to service the Hydrail System is not captured by the Hydrail System model. Specialized technicians will be required to service Hydrail vehicles and this is expertise that does not currently exist in Ontario at the scale that would be required. The lack of a skilled workforce could lead to higher costs at the outset as the industry trains technicians. To meet demand, the Province of Ontario may need to invest in educational programs to develop this skilled workforce. Development of a new work force has potential long-term benefits for the Ontario economy. These benefits are discussed in Section 4.7 this study. The key point is that the lack of a skilled workforce introduces risk to the deployment of Hydrail that would need to be overcome to ensure a smooth transition into service. Fifth, a significant potential benefit of Hydrail is the opportunity it presents to electrify more of the go RER network than would otherwise be possible through overhead electrification. This includes electrification of the outer areas of the network where overhead electrification would be cost prohibitive, and also to electrify corridors that the IBC model assumes would continue to run diesel service over the course of the 60 year RER program. Broader electrification could mean increased ridership as services will be more frequent and faster and associated increases to the overall benefits associated with the RER program. These benefits would be realized assuming agreements to operate HFC-powered trains can be negotiated in areas of the GO network that are not owned by Metrolinx. Sixth, while Hydrail related costs have been modelled, there is inherent uncertainty in such processes. On one hand, it is difficult to predict the extent to which capital and operating costs could come down in the future in light of a potential surge in establishing hydrogen economies globally. This would

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT come through increased competition, more real-world cases of implementation, and likely more research funding going into the technology. Similarly, it is very difficult to predict with accuracy the impact Hydrail could have on future energy prices in Ontario. Modelling work that has been undertaken is based on Ontario’s current energy outlook. It is well-understood that the outlook is based on one scenario where disruptions like mass deployment of electrical vehicles or significant downturns in the economy have not been assumed. As explained in Section 4.3, the load presented by Hydrail could lead to an increase in the wholesale price of electricity during the periods electricity is demanded by the Hydrail System. This will be the case if a situation arises where the availability of surplus baseload significantly declines due to increased adoption of electric vehicles and potentially increased use of electricity for home heating as is contemplated in Ontario’s Climate Change Action Plan. Seventh, Hydrail has the potential to be an anchor point for Ontario’s hydrogen economy. Lack of infrastructure is regularly sited as the key barrier to wide spread adoption of hydrogen technologies. The scale of Hydrail could provide that essential backbone that is needed to make hydrogen a viable technology option for commercial and personal transportation and for other purposes. To make this a reality, the hydrogen supply chain for Hydrail would likely need to be purposely designed and procured to ensure the broader potential benefits are realized. If, as an example, the fuelling network was purposely built for Hydrail, those broader benefits may be missed. Should a hydrogen supply chain be established and anchored in a long-term agreement for the provision of a certain amount of hydrogen to supply the Hydrail System, and that system also is used for other commercial applications, the price could be significantly different. The Hydrail analysis does not capture the potential benefits associated with such arrangements. Related to this point, Hydrail has the potential to facilitate continued efforts to decarbonize Ontario’s electricity system and to support continued installation of renewable energy production capabilities as it provides a storage medium that is not currently available. As per above, this would require that the hydrogen supply chain is effectively open for purposes broader than Hydrail. Finally, it is very difficult to quantify the risk associated with deployment of Hydrail at the scale that would be required to replace plans for overhead electrification. While all aspects associated with the production, storage, dispensing and use of hydrogen in fuel cells has been proven internationally, it has not been accomplished in a rail setting at anywhere near the scale being contemplated in Ontario and it has yet to be tested on rail vehicles that are comparable in terms of size and weight to what would be required to meet RER service levels as contemplated in the IBC. 4.4.9 Fiscal Analysis I It is important to note that although the NPV of the cost of both systems appear to be similar, there are significant differences in the timing of expenditures. For the overhead system, it is expected that much of the capital cost will be incurred near the beginning of the project as the overhead contact system is constructed. For Hydrail, however, the initial capital cost is expected to be lower but the recurring CAPEX to refurbish or replace hydrogen equipment is expected to be higher than for the overhead system. The combined impact of capital investment and operating and maintenance costs (i.e., the fiscal analysis) is analyzed in this section as separate operating and capital cost results that were presented in the previous sections do not clearly show how the investment affects annual budgets. A fiscal analysis has been completed with respect to the following four categories:  Amortized cost: annual amortization cost of capital assets. The effect of initial capital investment will appear in the books under the amortized cost of investment. It is assumed that initial capital investment for overhead electrification will be amortized linearly over 50 years (that is, from 2024

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to 2074). Hydrail’s initial capital, however, will be depreciated at different rates depending on the asset type. For instance, fuel cells have a significantly higher depreciation rate comparing to storage tanks due to their shorter life span. Components of the Hydrail System were depreciated at the rates shown in Table 4-40.

TABLE 4-40 HYDRAIL SYSTEM – DEPRECIATION RATE Lifetime Depreciation Rate Depreciation Depreciation Capital Assets Lifetime Rate Lifetime Rate Electrolyzer 15 7 percent 12 8 percent Storage (including compressor) 20 5 percent 20 5 percent Distribution (including compressor) N/A N/A N/A N/A Refuelling (including compressor) 20 5 percent 20 5 percent Dispensing 10 10 percent 10 10 percent Fuel cell 9 11 percent 6 17 percent Battery system 10 10 percent 10 10 percent On-board storage tanks 15 7 percent 15 7 percent

 Cost of financing: annual cost of debt. It is assumed that the initial capital investment is fully financed by debt. The debt is assumed to be issued at a rate of 3.5 percent annually, maturing in 30 years for both overhead electrification and Hydrail.  Operating cost: annual cost of electricity. As explained in Section 4.3, the volume and unit cost of electricity was estimated using data provided by IESO and the Hydrail simulation model. The average annual operating costs for the first 10 years of operation was then estimated for comparison.  Maintenance cost: annual maintenance cost. The maintenance cost for Hydrail was derived from the Hydrail simulation model. The result of the fiscal analysis is presented in Table 4-41. The difference between total annual costs of overhead electrification and low- and high-cost Hydrail scenarios is also presented in Table 4-41. Under the low-cost scenario, Hydrail would result in an average decrease of $31 million in Government’s expenses over the first 10 years of operations. Under high-cost scenario, Hydrail would result in an average increase of $55 million over the same operating period.

TABLE 4-41 FISCAL IMPACT – HYDRAIL COMPARED TO OVER-HEAD ELECTRIFICATION Hydrail Hydrail Comparison IBC (low) Difference (high) Difference Amortized cost 42 55 20 99 63 Cost of Financing 73 25 (48) 34 (39) Operating cost* 34 35 1 61 27 Maintenance cost* 17 14 (3) 20 3 Total annual costs 160 129 (31) 214 54 *The incremental maintenance cost from IBC model

This analysis is based on the information provided by Metrolinx represents what is available at the time of the report’s publication. The analysis should be reviewed and further analyzed by Metrolinx to

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT develop a final conclusion on the fiscal impact of the implementation of the overhead electric and Hydrail systems. 4.4.10 Findings The comparison between Hydrail and overhead electrification, as envisioned in the IBC, illustrates based on the information available, that total capital and operating costs for Hydrail are either similar more costly than overhead electrification. In both the low- and high-cost cases for Hydrail, total operating costs are expected to be higher than for an overhead system, as estimated in 2014. The higher capital cost for the Hydrail System is primarily driven by the requirement for more frequent CAPEX required to replace the assets in the Hydrail System, due to the shorter lifespan of the assets. In the low-cost scenario, the higher ongoing capital requirement is counter-balanced by lower initial capital required in the Hydrail System. Although an attempt has been made to understand and account for the variability in cost estimates that is inherent at the feasibility-testing stage, it remains important to emphasize the uncertainty in both the cost estimates for Hydrail and for overhead electrification. While the BCRs for Hydrail and overhead electrification are similar, with overhead electrification showing only marginally lower costs than Hydrail under the low-cost scenario, further design is required to advance the cost estimate of both systems to allow for a complete picture of the cost difference. The findings presented are based on NPV estimation. An attempt has been made to translate the analysis into fiscal terms because the government’s decision-making depends heavily on the fiscal impact of the project. As discussed in Section 4.4.9, the capital and operating costs of the Hydrail System would result in an overall annual expense ranging between $129 million and $214 million in the low- and high-cost scenarios, respectively. The variation between the scenarios is primarily driven by the difference in amortized capital costs that results from higher unit costs and shorter life spans of the Hydrail System equipment in the high-cost scenario. The annual operating cost also increases materially as a result of higher cost of electricity considered in the high-cost scenario. This analysis requires further review and confirmation by the Metrolinx finance team, at which time a comparison between Hydrail and overhead electrification scenarios could be considered and the associated impact on capital and operating costs that will be carried in the provincial fiscal plan can be assessed. 4.4.11 Next Steps As discussed, a more detailed estimate for Hydrail should include costs like permitting and financing costs, and would also include a more detailed analysis of risk and the risk-related costs; this will provide a more accurate picture of the total costs of a Hydrail System. At the same time, work should be completed to update the overhead electrification costs. The IBC was completed in 2014 and, similar to the requirement for a more detailed assessment of Hydrail related costs, a more detailed assessment of overhead electrification, based on a more current understanding of costs should be conducted. This will allow for a more complete comparison of Hydrail and overhead electrification. Additionally, the focus of the financial modelling process to-date has been the total cost of the Hydrail and overhead electric systems. This does not represent the price of system to Metrolinx—further modelling work should consider things like procurement and financing costs to help provide a more accurate picture of the full financial impact of the development of either system. Finally, a detailed investigation of the risks associated with both Hydrail and overhead electrification technologies should be completed. This will contribute to the understanding of the true potential cost of each project.

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4.5 Environmental The objective of this section is to provide a high-level comparative review of the potential impacts of electrification and Hydrail scenarios. The seven scenarios included in the comparison are summarized as follows:  Scenario 1, RER Scenario 5: Electric-powered and diesel-powered train fleet mix.  Scenario 2a: Hydrogen-powered and diesel-powered train mix, with hydrogen production and storage facilities (five) located in industrial areas away from the five Hydrail corridors. Hydrogen fuel (liquid hydrogen [LH2] or CGH2) would be transported by truck from the hydrogen storage and production facilities to the dispensing and fuelling facilities located at existing railyards.  Scenario 2b: Hydrogen-powered and diesel-powered train mix, with hydrogen production and storage facilities (five) located adjacent to each of the five Hydrail corridors. Hydrogen fuel (LH2 or CGH2) would not require transportation to the existing railyards.  Scenario 2c: Hydrogen-powered and diesel-powered train mix, with hydrogen production and storage facilities (five) located in industrial areas away from the five Hydrail corridors. Liquid hydrogen would be transported by a 4-inch outside diameter (OD) steel pipeline from the hydrogen storage and production facilities to the dispensing and fuelling facilities located at existing railyards.  Scenario 3a: Full hydrogen-powered train fleet on seven corridors, with hydrogen production and storage facilities (seven) located in industrial areas away from the rail corridors. Hydrogen fuel (LH2 or CGH2) would be transported by truck from the hydrogen storage and production facilities to the dispensing and fuelling facilities located at existing railyards.  Scenario 3b: Full hydrogen-powered train fleet on seven corridors, with hydrogen production and storage facilities (seven) located adjacent to each rail corridor. Hydrogen fuel (LH2 or CGH2) would not require transportation to the existing railyards.  Scenario 3c: Full hydrogen-powered train fleet on seven corridors, with hydrogen production and storage facilities (seven) located in industrial areas away from each rail corridor. Liquid hydrogen would be transported by a 4-inch OD steel pipeline from the hydrogen storage and production facilities to the dispensing and fuelling facilities located at existing railyards. 4.5.1 Evaluation Methodology A reasoned argument evaluation methodology was used to compare technology scenarios. Assessment criteria were selected to correspond with the 11 environmental factors identified in the GO Rail Network Electrification Transit Project Assessment Process Final Environmental Project Report (TPAP EPR)147. For each criterion, metrics were defined and environmental effects were assigned to each of the seven scenarios based on available information. For each criterion, preference was assigned to the scenarios based on the magnitude of potential or anticipated environmental effect. A rationale for the preference determination was then provided for each criterion, and for the overall assessment.

147 Metrolinx. 2017. GO Rail Network Electrification Transit Project Assessment Process Environmental Project Report. Prepared by Morrison Hershfield Limited and Gannet Fleming Canada ULC. October 5. Accessed October 2017. http://www.gotransit.com/electrification/en/docs/technicalreports/GO percent20Rail percent20Network percent20Electrification percent20Environmental percent20Project percent20Report_Volume percent201.pdf

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4.5.1.1 Assumptions The scope of the assessment was based on Scenario 5 of the GO RER Initial Business Case148. Assumptions from the TPAP EPR were carried over to this assessment and include:  Service levels for the year 2025 and all additional RER infrastructure modifications are already in place.  Projects outside the scope of the TPAP EPR (for example, new tracks, grade separations, and new GO stations) would be assessed separately.  Electrification or Hydrail infrastructure implementation is separate from the other planned works; therefore, the assessment does not evaluate their impacts.  The diesel-Hydrail scenarios (2a-c) will maintain the same fleet mix of diesel and hydrogen trains as RER Scenario 5 diesel and electric trains.  Implementation timeframes for Scenarios 2 and 3 will be the same as for Scenario 1, 2024. Assumptions related to Hydrail and associated infrastructure include:  Under Scenario 2, the five rail corridors would be converted to Hydrail; and under Scenario 3, all seven rail corridors would be converted to Hydrail.  Liquid and compressed hydrogen fuels will have similar impacts at the level of detail assessed.  Central production facilities will be located in existing industrial areas, potentially several kilometres from each rail corridor, and would require transportation of hydrogen fuel to the dispensing and refuelling facilities.  Local production and storage facilities will be constructed adjacent to the hydrogen fuel dispensing and refuelling facility along each rail corridor.  Trucks or pipelines would be used to transport hydrogen fuel from central production and storage facilities to dispensing and fuelling facilities.  For Scenarios 2a, b, and c, facility footprints for the five hydrogen production and storage facilities and five dispensing and fuelling facilities will be a total of 10,841 square metres (m2). It was assumed that liquid and compressed hydrogen facilities would have the same footprints.  For Scenarios 3a, b, and c, facility footprints for the seven hydrogen production and storage facilities and seven dispensing and fuelling facilities will be a total of 15,144 m2. It was assumed that liquid and compressed hydrogen facilities would have the same footprints.  Facility footprint assumptions for electrification were based on infrastructure footprints (five hydro one-tap locations, five traction power substations [TPSs], five switching stations [SWSs], and six paralleling stations [PSs]) provided in the TPAP EPR. Areas associated with gantries, feeder routes, bridge modifications or replacements, paralleling barriers, and the overhead contact system were not included in the facility footprint.  Hydrogen production and storage facilities will have storage for 3 days’ worth of hydrogen.  Hydrogen production facilities can be located in areas designated for industrial use and in visually unobtrusive areas, and would not be located in sensitive natural habitats or in areas of high

148 Metrolinx. 2015. GO RER Initial Business Case. Accessed October 2017. http://www.metrolinx.com/en/regionalplanning/projectevaluation/benefitscases/GO_RER_Initial_Business_Case_EN.pdf

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archaeological potential. Facility locations were assumed to have impacts equivalent to those of electrification facilities.  Electricity for hydrogen production would be sourced from Hydro One through an underground connection to the facility.  Water for hydrogen production would be sourced from the local water mains.  Use of Hydrail vehicles can be scaled up on the corridors once the production and refuelling facilities are operational. 4.5.2 Evaluation Results The comparative evaluation is included in Table 4-42. This section presents a summary of the preliminary evaluation results, limitations, and additional considerations for future assessment. 4.5.2.1 Terrestrial and Aquatic Ecosystems For this criterion, Scenarios 2a and 2b are preferred, as they result in the smallest potential footprint disturbance to vegetation and wildlife habitat, and will not require modifications to existing water crossings. Scenario 3a and 3b are slightly less preferred, as the footprint of the required hydrogen production facilities is slightly larger than required for hybrid diesel-hydrogen scenarios. Pipeline options 2c and 3c may result in additional vegetation removals and watercourse crossings, making these scenarios less desirable than the other Hydrail scenarios. Electrification is least preferred for this criterion, as it requires significant right-of-way (ROW) clearing, footprint impacts associated with new facilities, and construction of new infrastructure in proximity to watercourses, including Redside dace habitat149. 4.5.2.2 Contaminated Soils and Groundwater For this criterion, Scenarios 3b and 3c are preferred, as they eliminate the operation of diesel trains and the requirement to transport hydrogen using diesel trucks. Scenario 2a is least preferred, as a portion of the transit fleet remains diesel, and the central hydrogen production facility introduces a requirement for 78 truck trips per day to transport hydrogen to the dispensing and fuelling facilities. 4.5.2.3 Built Heritage From a built heritage perspective, all Hydrail scenarios avoid the requirement to modify heritage properties, so are preferred. Scenario 1 is least preferred, as electrification requires modification of up to 12 heritage properties (bridges). 4.5.2.4 Archaeology From an archaeological perspective, Hydrail scenarios not involving pipeline construction (2a, 2b, 3a, 3b) are preferred, as they result in the least subsurface disturbance; therefore, they minimize potential impacts to archaeological resources. Scenarios 2c and 3c are less preferred, as pipeline construction increases potential to encounter archaeological resources. Electrification is least preferred, as this scenario requires the most subsurface construction.

149 Metrolinx. 2017. GO Rail Network Electrification Transit Project Assessment Process Environmental Project Report. Prepared by Morrison Hershfield Limited and Gannet Fleming Canada ULC. October 5. Accessed October 2017.

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4.5.2.5 Land Use Impacts to land use are not anticipated under any scenario. It has been assumed that hydrogen production facilities can be located in areas designated for industrial use. 4.5.2.6 Emissions From an emissions perspective, the full Hydrail scenarios (3a, 3b, and 3c) are preferred, as they eliminate diesel trains from the RER fleet mix and reduce GHG emissions regionally, leading to improved local air quality. Hydrail Scenarios 2b and 2c, and electrification (Scenario 1) are less preferred and are assumed to contribute comparable emissions, though less emissions than the current diesel train fleet. While Hydrail may require up to 3 times more electricity than electrification, hydrogen production can be carried out at periods of low grid demand, reducing reliance on fossil fuel sources. Hydrail Scenario 2a is least preferred, as diesel trains remain part of the fleet mix, and the central hydrogen production facility introduces the requirement for 78 additional truck trips per day. 4.5.2.7 Noise and Vibration From a noise and vibration perspective, the full Hydrail scenarios (3a, 3b, and 3c) are preferred, as they eliminate diesel locomotives from the fleet mix. Hydrail locomotives will not have mechanical engines, reducing the noise produced by the train. Assuming the proportion of diesel trains is consistent between Scenarios 1, 2a, 2b, and 2c, these scenarios are less preferred. Significantly more effects from noise and vibration can be expected during construction of electrification infrastructure along the rail corridors and at facilities. A comparison of impacts would require additional siting information and construction methodology for electrification and Hydrail scenarios. 4.5.2.8 Visual and Aesthetics From a visual perspective, Hydrail scenarios featuring a central production facility, pipeline, or both (2a, 2c, 3a, 3c) are preferred, as they do not require overhead infrastructure; and there is flexibility to site production facilities in visually unobtrusive locations (such as in industrial areas). Scenarios 2b and 2c are less preferred, as it is assumed that localized production facilities may be located in highly visible or residential areas. Electrification is least preferred due to the requirement for extensive overhead infrastructure. 4.5.2.9 Utilities From a utilities perspective, Hydrail scenarios not requiring pipeline installation (2a, 2b, 3a, 3c) are preferred, as they avoid potential for utility conflicts within road and rail ROWs. Scenarios 2c and 3c are less preferred, as pipeline installation increases the potential for utility conflicts. Electrification is least preferred, as extensive infrastructure required within the ROW is expected to result in significant utility conflicts. 4.5.2.10 Electromotive Force According to the TPAP EPR150, electromotive force (EMF) impacts are not anticipated. No impacts are anticipated under any Hydrail scenario.

150 Metrolinx. 2017. GO Rail Network Electrification Transit Project Assessment Process Environmental Project Report. Prepared by Morrison Hershfield Limited and Gannet Fleming Canada ULC. October 5. Accessed October 2017.

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4.5.2.11 Stormwater Management and Drainage As existing stormwater infrastructure would not need to be modified or expanded to accommodate Hydrail, all scenarios are equally preferred. Electrification is less preferred, as it requires modifications to the existing stormwater management system. 4.5.3 Environmental Conclusions 4.5.3.1 Overall Assessment Key Evaluation Criteria From this assessment, the criteria with the greatest relevance from an environmental evaluation perspective are:  Footprint impacts (both facility and ROW)  Impacts to built heritage structures  Emissions  Visual and aesthetic impacts Preferred Scenarios The full hydrogen-powered train fleet scenarios (3a, 3b, and 3c) are generally preferred, as they:  Eliminate the need for extensive ROW clearing (associated with electrification infrastructure)  Avoid impacts to heritage bridges (required under electrification to provide adequate clearance)  Remove diesel trains from the fleet mix (thereby, reducing emissions, noise, and vibration)  Present the ability to draw power from the grid during periods of low demand (reducing reliance on fossil fuel generation)  Eliminate the need for extensive aboveground infrastructure with the potential to negatively impact visual aesthetics in and adjacent to the corridor Comparison between Preferred Scenarios Within these alternatives, there are trade-offs to consider that will depend on the ability to mitigate impacts through design. For example, if the pipeline scenario (3c) could be designed to avoid impacts to vegetation, archaeological resources, and utilities, the residual environmental impacts would be minimal. Similarly, if a hydrogen-powered truck fleet was used to deliver fuel to the dispensing and refuelling facilities, the environmental effects of Scenarios 3a and 3b would be comparable. Consideration of further information, when available, on the environmental factors assessed and of additional environmental factors could change the overall preference described. As electrification requires construction of significant above- and belowground infrastructure, environmental effects are anticipated to vegetation aquatic and wildlife habitat, contaminated soils, cultural heritage and archaeology, utilities, air quality, noise and vibration, and visual aesthetics. While a significant improvement over existing conditions, the ongoing operation of diesel trains under Scenarios 1, 2a, 2b, and 2c will result in increased emissions when compared to the full hydrogen-powered train fleet scenarios. And while electrification requires less total electricity, there is also less flexibility in the timing of grid production, resulting in a potential increase in fossil fuel reliance.

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The following legend applies to Table 4-42.

TABLE 4-42 HYDRAIL PRELIMINARY ENVIRONMENTAL REVIEW Scenario 1 Scenario 2a Scenario 2b Scenario 2c Scenario 3a Scenario 3b Scenario 3c Reasoning and Rationale Hydrogen Only Diesel - Hydrogen (Central Diesel - Hydrogen Diesel – Hydrogen Hydrogen Only (Central (Localized Hydrogen Only Factor Area Metric Diesel - Electric Production - Trucked) (Localized Production) (Pipeline) Production - Trucked) Production) (Pipeline) Terrestrial and  Footprint Based on estimated sizes for PSs, SWSs, TPSs, and Five production facilities Same as Scenario 2a. Same as Scenario 2a, with Same as Scenario 2a, with the Same as Scenario 3a. Same as Scenario 3a, From a natural Aquatic impact on tap sites, the area required for electrification would be required. Each the following exception. following exceptions. with the following environment perspective, 2 Ecosystems vegetation and facilities is 31,104 m . Additional footprint will be production facility would have Additional footprint effects Each production facility would exception. Additional Scenarios 2a and 2b are habitat required for gantries, feeder routes and duct an area of approximately would result from have an area of approximately footprint effects would preferred, as they result in 2  Disturbance to banks, OCS support structures, OCS maintenance 2,168 m , and would provide construction of 367 km of 4- 2,163 m2, and would provide result from the smallest potential watercourses facilities, bridge replacements and modifications, storage for 3 days’ of fuel. inch OD steel pipeline. storage for 3 days’ of fuel. Total construction of 488 km footprint disturbance to during and parallel barriers. Total footprint for production, Effects could be mitigated footprint for production, of 4-inch OD steel vegetation and wildlife construction Impact to Vegetation and Habitat storage, dispensing, and by constructing the pipeline storage, dispensing, and pipeline. Effects could habitat, and will not require Tree removal and vegetation clearing will occur refuelling facilities would be in the existing utility corridor refuelling facilities would be be mitigated by modifications to existing approximately 10,841 m2. or transportation ROW, 2 constructing the water crossings. within 7 m of the outermost electrified track approximately 15,144 m . where feasible. pipeline in the existing through construction and operation to provide Hydrogen production facilities Scenarios 3a and 3b are utility corridor or safety. Tree removal and vegetation clearing would require 32 percent of the Hydrogen production facilities slightly less preferred, as transportation ROW, may be required for infrastructure and facility area needed for electrification the footprint of the would require 49 percent of where feasible. construction, and maintenance. facilities. the area needed for required hydrogen Construction activities may introduce invasive Impact to Vegetation and electrification facilities. production facility is species. Damage to trees not designated for Habitat slightly larger than that removal may occur during construction. Tree and vegetation removal required for hybrid diesel- hydrogen scenarios. Disturbance to migratory bird nests may occur have the potential to occur Pipeline options 2c and 3c during vegetation clearing or bridge during facility construction. may result in additional modifications. Temporary displacement of Construction activities may wildlife or disturbance to SAR may occur during introduce invasive species. vegetation removals and construction. Damage to trees not watercourse crossings, making these scenarios less designated for removal may Disturbance to Watercourses desirable than the other occur during construction. There are no direct impacts to watercourses Hydrail scenarios. Disturbance to migratory bird anticipated as a result of the electrification project. Electrification is least Potential indirect effects of the construction works nests may occur during vegetation clearing. Temporary preferred for this criterion, include siltation, introduction of contaminants into as it requires significant displacement of wildlife or the watercourse using industrial equipment, and ROW clearing, footprint disturbance to SAR may occur construction debris. Bridge works are impacts associated with new during construction. anticipatedwithin Redside dace regulated habitat facilities, and construction of at Fourteen Mile Creek, Little Rouge Creek, Disturbance to Watercourses new infrastructure in Robinson Creek, Brice Creek, and Rouge River. No effects to watercourses are proximity to watercourses, anticipated from new facility including Redside dace footprints. habitat. Preference Contaminated  Facility Facility Footprint Facility Footprint Same as Scenario 2a, with Same as Scenario 2b. Facility Footprint Same as Scenario 2a, Same as Scenario 3b. From a contaminated soils Soils and footprint Contaminated soils, groundwater, or both may be Contaminated soils, the exception of Contaminated soils, with the exception of perspective, Scenarios 3b Groundwater  Number of identified during ground disturbance for groundwater, or both may be hydrogen fuel truck groundwater, or both may be hydrogen fuel truck and 3c are preferred, as diesel trains as infrastructure installation and facility construction. identified during ground traffic. No trucks will be identified during ground traffic. No trucks will be they eliminate the operation part of the fleet Phase I and II ESAs would need to be completed disturbance for infrastructure required to transport disturbance for infrastructure required to transport of diesel trains and the mix during subsequent planning and design phases to installation and facility hydrogen between the installation and facility hydrogen between the requirement to transport  Number of characterize potential impacts. Total facility construction. Phase I and II production and construction. Phase I and II ESAs production and hydrogen using diesel dispensing and refuelling dispensing and trucks. diesel truck km footprint is 31,104 m2. ESAs would need to be would need to be completed during subsequent facility. during subsequent planning refuelling locations. Scenario 2a is least required for Diesel Trains completed hydrogen planning and design phases to and design phases to preferred, as a portion of Potential effects from diesel spills at refuelling transportation characterize potential impacts. characterize potential impacts. the transit fleet remains facilities or from accidents. Assume 32 diesel Total facility footprint is 10,841 Total facility footprint is 15,144 diesel, and the central locomotives will operate. m2. m2. hydrogen production facility Diesel Trains Diesel Trains introduces a requirement for 78 truck trips per day to Potential effects from diesel No diesel trains will operate. transport hydrogen to the spills at refuelling facilities or Hydrogen Spills dispensing and fuelling from accidents. Assume 32 Hydrogen spills are anticipated facilities. diesel trains will operate. to have minimal effect: CGH2 Hydrogen Spills plumes will disperse to the Hydrogen spills are atmosphere when it is released, anticipated to have minimal

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effect: CGH 2 plumes will and LH2 will evaporate quickly disperse to the atmosphere when spilled. when it is released, and LH 2 Hydrogen Transportation when will evaporate quickly Potential for spills from trucks spilled. used to transport hydrogen fuel Hydrogen Transportation from production and storage Potential for spills from trucks facilities to dispensing and used to transport hydrogen fuel refuelling facilities. Use of from production and storage compressed hydrogen as a fuel facilities to dispensing and will require approximately twice refuelling facilities. Use of the number of trucks to compressed hydrogen as a fuel transport hydrogen fuel as will require approximately twice liquid hydrogen. Assume 110 the number of trucks to trucks will transport hydrogen transport hydrogen fuel as to dispensing and refuelling liquid hydrogen. Assume 78 locations. trucks will transport hydrogen to dispensing and refuelling locations.

Preference Built Heritage  Number of There is no removal or demolition of any It is assumed that cultural Same as Scenario 2a. Same as Scenario 2a. Same as Scenario 2a. Same as Scenario 2a. Same as Scenario 2a. From a built heritage heritage identified heritage properties anticipated as part heritage properties will not be perspective, all Hydrail properties of the Electrification TPAP project. Twelve affected by construction of scenarios avoid the requiring properties were identified as potentially hydrogen production facilities requirement to modify modification impacted by electrification, such as alternation or modifications at existing rail heritage properties, so are (e.g., displacement of heritage attributes, facilities. preferred. disruption of setting, or both). Scenario 1 is least preferred, as electrification Preference requires modification of up to 12 heritages properties. Archaeology  Footprint There are 12 locations with undetermined or Facility locations are flexible; Facility location must be Facility locations are Facility locations are flexible; Facility location must be Facility locations are From an archaeological within areas of potential archaeological effects. As recommended locations can be selected to near the rail facility. Stage flexible; locations can be locations can be selected to near the rail facility. flexible; locations can perspective, Hydrail archaeological in the Stage 1 Archaeological Assessment, Stage 2 reduce potential 1-4 Archaeological selected to reduce potential reduce potential archaeological Stage 1-4 be selected to reduce scenarios not involving potential Archaeological Assessments will be completed as archaeological effects. Stage Assessments will be archaeological effects. effects. Stage 1-4 Archaeological potential pipeline construction (2a, part of the TPAP where possible and where PTE 1-4 Archaeological completed as part of the Stage 1-4 Archaeological Archaeological Assessments Assessments will be archaeological effects. 2b, 3a, 3b) are preferred, as access has been granted. Based on the results of Assessments will be detailed design process Assessments will be will be completed as part of the completed as part of the Stage 1-4 they result in the least the Stage 2 Archaeological Assessments, further completed as part of the for any new facilities. completed as part of the detailed design process for any detailed design process Archaeological subsurface disturbance; Stage 3 Archaeological Assessment, Stage 4 detailed design process for detailed design process for new facilities. for any new facilities. Assessments will be therefore, they minimize mitigation, or both will be conducted, as required, any new facilities. any new facilities. completed as part of potential impacts to on any newly discovered Indigenous or Euro- the detailed design archaeological resources. Canadian site determined to have CHVI that will be process for any new Scenarios 2c and 3c are less impacted by construction associated with the OCS facilities. preferred, as pipeline along the rail corridors, tap locations, traction construction increases power facility sites, or some combination of these. potential to encounter archaeological resources. Preference Electrification is least preferred, as this scenario requires the most subsurface construction. Land Use and The TPAP assessment concluded there are no net Potential for incompatible land Potential for incompatible Potential for incompatible Potential for incompatible land Potential for Potential for Impacts to land use are not Social Features adverse land use effects anticipated during uses that could be mitigated land uses that could be land uses that could be uses that could be mitigated incompatible land uses incompatible land anticipated under any (including parks operation. through appropriate facility mitigated through mitigated through through appropriate facility that could be mitigated uses that could be scenario. It has been and open spaces) siting within industrial- appropriate facility siting appropriate facility siting siting within industrial- through appropriate mitigated through assumed that hydrogen designated land. within industrial- within industrial -designated designated land. facility siting within appropriate facility production facilities can designated land. land. industrial-designated siting within be located in areas land. industrial-designated designated for industrial land. use. Preference

Air Quality and  Estimated CO2 Emissions CO2 Emissions Same as Scenario 2a, Same as Scenario 2b. CO2 Emissions Same as Scenario 3a, Same as Scenario 3b. From an emissions Emissions emissions Electrification will result in a significant reduction Hydrail will result in a reduction except for hydrogen fuel Hydrail will result in a except for hydrogen fuel perspective, the full Hydrail based on of diesel emissions, which has both local and of diesel emissions and local truck traffic. No trucks will reduction of diesel emissions truck traffic. No trucks scenarios (3a, 3b, and 3c)

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Preference Noise and  Diesel train Operational noise levels could be mitigated Same as Scenario 1. Same as Scenario 1. Same as Scenario 1. Reduced noise due to full Same as Scenario 3a. Same as Scenario 3a. From a noise and vibration Vibration operation through noise abatement measures. Further Hydrail vehicle fleet. perspective, the full noise analysis would be needed to determine Hydrail scenarios (3a, 3b, appropriate noise abatement measures, if and 3c) are preferred, as required. they eliminate diesel trains from the fleet mix. Preference Assuming the proportion of diesel trains is consistent between Scenarios 1, 2a, 2b, and 2c, these scenarios are less preferred. Visual  Presence of All rail corridors had moderate visual impact, Visual impacts would be Visual impacts would be Same as Scenario 2a. Same as Scenario 2a. Same as Scenario 2b. Same as Scenario 2a. From a visual perspective, new and four corridors had high visual impacts limited to construction of new limited to construction Hydrail scenarios featuring a aboveground (residential areas where homes are within 8 m of hydrogen production facilities. of new hydrogen central production facility, infrastructure the railroad ROW) associated with the Flexibility to site the facility in production facilities. pipeline, or both (2a, 2c, 3a, electrification infrastructure. a visually unobtrusive location. 3c) are preferred, as they do not require overhead Preference infrastructure; and there is flexibility to site production facilities in visually unobtrusive locations (industrial areas). Scenarios 2b and 2c are less preferred, as it is assumed that localized production facilities may be located in highly visible and residential areas. Electrification is least preferred due to the requirement for extensive overhead infrastructure .

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due to installation and operation of the traction Hydrail scenario. power facilities No adverse EMI and EMF effects are anticipated due to installation and operation of tap infrastructure

Preference Stormwater Stormwater management infrastructure may be No effects to stormwater Same as Scenario 2a. Same as Scenario 2a. Same as Scenario 2a. Same as Scenario 2a. Same as Scenario 2a. As existing stormwater Management affected by placement of electrical infrastructure. management along the rail infrastructure would not Electrical infrastructure has limited flexibility in corridors is anticipated. need to be modified or placement. Stormwater management will be Stormwater management will expanded to accommodate required at all new facilities. be required at all new Hydrail, all scenarios are facilities. equally preferred. Electrification is less Preference preferred, as it requires modifications to the existing stormwater management system. Overall In general, key differentiators from an environmental perspective include footprint impacts (both facility and ROW), impacts to built heritage structures, emissions, and visual and aesthetic impacts. The full Hydrail scenarios (3a, Assessment 3b, and 3c) are generally preferred, as these scenarios eliminate the need for extensive ROW clearing, avoid impacts to heritage bridges, remove diesel trains from the fleet, present the ability to draw power from the grid during periods of low demand (reducing reliance on fossil fuel generation), and eliminate the need for extensive aboveground infrastructure with the potential to negatively impact visual aesthetics in and adjacent to the corridor. Within these alternatives, there are trade-offs to consider that will depend on the ability to mitigate impacts through design. For example, if the pipeline option could be designed to avoid impacts to vegetation, archaeological resources, and utilities, the residual environmental impacts would be minimal. As electrification requires significant physical construction of above- and belowground infrastructure, impacts are anticipated to vegetation and wildlife habitat, cultural heritage and archaeology, utilities, and visual aesthetics. While a significant improvement over existing conditions, the ongoing operation of diesel trains under electrification will result in increased emissions when compared to the full Hydrail scenarios. And while electrification requires less total electricity, there is less flexibility in the timing of grid production, resulting in an increased reliance on fossil fuels.

Preference Notes: CHVI = Cultural Heritage Value or Interest km/d = kilometre per day EMI = electromagnetic interference m = metre ESA = environmental site assessment OCS = overhead catenary system HOEP = Hourly Ontario Energy Price SAR = species at risk km = kilometre

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4.5.3.2 Evaluation Limitations Limited information is available with respect to Hydrail at this early stage of assessment. To fully account for the anticipated or potential environmental effects of Hydrail, infrastructure design and impact assessment is required at a similar level of detail as has been completed for electrification. For these reasons, this should be considered a preliminary high-level review to be used as a guide for future assessment. 4.5.3.3 Additional Considerations While the 11 environmental factors assessed in the TPAP EPR were considered in the Hydrail comparison, additional factors could be considered during a more detailed assessment. Human health considerations were not assessed due to a lack of available information, but should be addressed. Climate change and the operational constraints of extreme weather should also be considered when comparing electrification and Hydrail. Both weather extremes, high electricity demand during extreme heat, and operations under extreme cold weather should be assessed. Electricity sources were assumed to be from the current power supply sources, but future electricity supply may be from more renewable sources. A comprehensive assessment of GHG emissions is recommended to allow for a comparison of electrification and Hydrail151. The amount of material to construct electrification and Hydrail infrastructure and the energy to produce, transport, and dispose of that material could be evaluated in a comprehensive assessment associated with the electrification and Hydrail scenarios. Large amounts of galvanized steel will be required for construction of the electrification infrastructure, while different production impacts are associated with lithium ion batteries. Waste management and recycling for all construction materials, including lithium ion batteries, would also need to be considered. A review of plans for recycling programs for automotive and other large-scale lithium ion batteries, and the capacity to support the high numbers of spent batteries, should be completed.

151 Meegahawatte, Danushka, Stuart Hillmansen, Clive Roberts, Marco Falco, Andrew McGordon, and Paul Jennings. 2010. Analysis of a fuel cell hybrid commuter railway vehicle. Birmingham: Birmingham Centre for Rail Research and Education, University of Birmingham; and Coventry: Warwick Manufacturing Group, International Manufacturing Centre, University of Warwick. February 1.

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4.6 Legal, Policy, and Regulatory Framework This section provides:  an overview of the existing legal, policy, and regulatory framework, and the standards, codes, and zoning considerations relevant to the use of hydrogen on passenger trains, as well as the generation, storage, and transportation of hydrogen  an understanding of where existing regulations may need to change to enable the deployment of Hydrail and  where gaps in existing regulations are identified and recommendations are made to resolve them. 4.6.1 Laws and Regulations Governing Metrolinx The Ontario Metrolinx Act (2006) governs the structure of Metrolinx’s business. This act touches on accountability and the applicability of the Canada Transportation Act. The act applies directly to public and private railway systems. There is specific federal legislation covering railways that apply to Metrolinx operations. There are basic legal requirements under building, electrical, and fire codes on building infrastructure that apply to Hydrail. At the legislative level, there is nothing obvious that applies specifically to the use of hydrogen as fuel. The references start to appear at the regulation level. Note that there are federal regulations specifically on safety of railways, including:  Railway Safety Act  SOR-2017-121 Locomotive Emissions Regulations  SOR-2015-26 Railway Safety Management Regulations  SOR-2014-258 Railway Operating Certificate Regulations  SOR-87-150 Railway Employee Qualification Standards Regulations Under the Railway Safety Act (RSA), Metrolinx is responsible for:  The safety of their rail line infrastructure, railway equipment and operations.  Ongoing inspection, testing, and maintenance programs that meet regulatory requirements,  Any specific operating and environmental conditions. Under the Railway Safety Act (RSA), Transport Canada is responsible for:  Promoting railway safety through education and awareness;  Overseeing the safety of federally-regulated railways;  Developing regulations, rules and engineering standards;  Monitoring industry compliance with rules, regulations and standards through audits and inspections; and  Taking enforcement action, as required.

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Before they could operate their current fleet, Metrolinx had to meet, amongst other requirements, the Railway Operating Certificate Regulations (SOR/2014-258). To obtain this certificate, the operator needs to have a safety management system that meets the requirements of the Railway Safety Management System Regulations (SOR/2015-26). Under the Railway Safety Act, a railway operator needs to submit a new Risk Assessment before the introduction of a new technology. 4.6.2 Existing Laws, Regulations, Standards, and Codes – Hydrogen Facilities and Transportation Hydrogen facility legal requirements, codes, and standards include: 1. CAN/BNQ 1784-000, Canadian Hydrogen Installation Code (2007, currently in review). This code (commonly referred to as CHIC) is enforced in Ontario (through the Technical Standards and Safety Authority [TSSA], Fuels division) and is intended to apply to most hydrogen equipment and systems used for generation, dispensing, storage, and piping. The relevant exceptions are:  Industrial use (process feedstock) or production as by-product  Industrial production of more than 21 kilograms per hour (kg/h)  Liquid hydrogen production  Transportation of hydrogen, including pipelines  Hydrogen onboard vehicles (it is not clear, but inferred, that this includes trains) For the full-scale deployment of Hydrail, this standard would not apply to the hydrogen production plant, since the scale (2,000 kg/h) is much higher than the CHIC limit. However, CHIC would likely apply to a pilot Hydrail project and to various parts of the full-scale project (in fuelling depots). The CHIC remains as a preferred guide for any hydrogen installation in Canada, since it has been developed by those experienced in all parts of the hydrogen industry. 2. CSA-B51 Part 1, General Requirements for Boilers, Pressure Vessels and Pressure Piping. This standard applies to most systems where hydrogen is used or stored at gauge pressure greater than 101 kiloPascals (kPa). However, it does not apply to cylinders for transportation of hydrogen regulated by Transport Canada, onboard automotive vehicle hydrogen fuel storage, or refuelling station pressure piping and ground storage systems. 3. CSA-B51 Part 3, Compressed Natural Gas and Hydrogen Refuelling Station Pressure Piping Systems and Ground Storage Vessels. This standard covers pressure piping systems with design pressures greater than 414 kPa (gauge) used in hydrogen refuelling stations and local hydrogen storage vessels for refuelling stations. This was not intended to apply to trains, though trains are not specifically excluded and should be relevant, though the size of train systems would be expected to be much larger than for automobiles or buses. 4. CSA-C22.1, Canadian Electric Code, Part 1. This safety standard provides requirements for installation of electrical equipment. It does not apply to systems that supply motive power to trains or are used for railway communications. Of particular note is Section 18 that deals with hazardous locations where electrical equipment and hydrogen may be present at quantities greater than its lower flammability limit. A prescribed method for determination of the area classification is not included in the Canadian Electrical Code, but informative recommendations are provided in Appendix L. The prescriptive standard from the International Electrotechnical Commission (IEC), IEC-60079-10-1, Explosive Atmospheres - Part 10-1: Classification of Areas - Explosive Gas Atmospheres, is the main reference used for area classification.

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5. ISO 22734-1, Hydrogen generators using water electrolysis process - Part 1: Industrial and commercial applications. This international standard applies to caustic and solid polymer electrolyte types, regardless of size. It provides a standard for certification of electrolysis systems for safety and performance. 6. ISO/TS 19880-1, Gaseous hydrogen — Fueling stations — Part 1: General requirements. This is the first of a series of international standards (there are parts 1 to 8) specifying requirements and recommendations for hydrogen fuelling stations for light-duty land vehicles. It particularly notes that it is suitable guidance for fuelling stations for larger vehicles (buses and trams, though trains are not noted). The other parts of 19880 cover specialized equipment required in a fuel dispenser (for example, nozzles). Some discussion of SAE International (SAE) J2601, Fueling Protocols for Light Duty Gaseous Hydrogen Surface Vehicles, requirements is also presented. 7. ANSI/CSA HGV 4.1, Standard for hydrogen dispensing systems. This North American standard applies directly to general requirements for integrated automobile hydrogen dispensers. Others in this series (HGV 4.1-4.8 and 4.10) cover parts of the dispenser system and operation. HGV 4.9 deals with design, installation, and O&M of hydrogen fuelling stations for automobiles. These are all suitable as some guidance for train hydrogen fuel dispensing systems. 8. CGA G-5.5, Hydrogen Vent Systems: This North American standard is for the safe design of hydrogen vent systems (required to be pressure systems by CHIC). 9. ISO 14687, Hydrogen fuel quality – Product specification. This international standard specifies the minimum quality characteristics of hydrogen fuel, including use in fuel cells. Containers and Transportation of Hydrogen (UN1049 – gas, UN1966 – liquid) Hydrogen container and transportation requirements, codes, and standards include: 1. SOR 2017-137, Consolidated Transportation of Dangerous Goods Regulations. This act covers requirements for transportation of hydrogen by road and rail. 2. TP 14877E, Containers for the Transportation of Dangerous Goods by Rail. This Canadian standard provides the minimum requirements regarding the design, manufacture, qualification, selection, and use, or testing, of containers for transportation by rail. It applies to compressed gas or liquid hydrogen. 3. CSA B620-14, Highway tanks and TC transportable tanks for transportation of dangerous goods. This Canadian standard is used in conjunction with Canadian transportation of dangerous goods regulations to cover design, fabrication, use, and maintenance of containers transportable by road. It (along with CSA B621, Selection and use of highway tanks, TC portable tanks, and other large containers for the transportation of dangerous goods, Classes 3, 4, 5, 6.1, 8, and 9; and B622, Selection and use of highway tanks, TC portable tanks, and ton containers for the transportation of dangerous goods, Class 2) applies to compressed gas and liquid hydrogen in all types of acceptable tanks. 4. CGA G-5, Hydrogen. This well-established North American standard covers hydrogen container design, and safe storage and handling of containers for compressed gas and liquid. 5. CSA Z662-15, Oil and gas pipeline systems. This Canadian standard extensively covers pipelines for conveying natural gas, but does not address pipelines specifically for hydrogen.

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Hydrogen-powered Locomotion Hydrogen-powered locomotion legal requirements, codes, and standards include: 1. SAE J2578, Recommended Practice for General Fuel Cell Vehicle Safety. This document relates to the overall design, construction, and O&M of FCVs. It is intended for automobiles, but relevant for trains. 2. CSA-B51 Part 2, High-pressure Cylinders for the Onboard Storage of Natural Gas and Hydrogen as Fuels for Automotive Vehicles. This standard covers only metal, metal-lined, and composite cylinders between 20 and 1000 litres (L) in capacity used for onboard automotive fuel storage. It does not appear to apply to trains. 3. IEC 62282-2, Fuel cell technologies - Part 2: Fuel cell modules. This international standard covers all types of fuel cells of any size, but excludes fuel cells on vehicles. While not stated directly, it appears to also exclude fuel cells on trains. Part 3 of this standard is for stationary fuel cells, and Part 4 is for industrial trucks (that is, forklifts). North American standards have been developed for fuel-cell powered vehicles but are limited to light-duty vehicles, including automobiles, small trucks, and forklifts. These include: 1. ANSI HGV 3.1, Fuel System Components for Compressed Hydrogen Powered Vehicles 2. ANSI-CSA HPRD 1, Thermally Activated Pressure Relief Devices for Hydrogen Vehicle Fuel Containers 3. CSA HPIT 1, Compressed Hydrogen Powered Industrial Trucks On-Board Fuel Storage and Hydrogen Components 4. CSA HPIT 2, Dispensing Hydrogen Powered Industrial Trucks 4.6.3 Other Existing Laws, Regulations, Standards, and Codes Relevant to Hydrail There are many existing rail transportation regulations, codes, and standards to cover aspects other than the driving energy source. To supplement the regulations, codes, and standards presented in the previous section, there are some additional general codes and standards for hydrogen, including: 1. NFPA-2, Hydrogen Technologies Code. This code applies to American hydrogen installations and has fewer exceptions than CHIC (particularly for industrial installations), but does exempt onboard vehicle systems. It is prescriptive, but with disclaimers allowing authority having jurisdiction (AHJ) discretion. It clearly applies to the fire safety of fixed, transportable, and mobile hydrogen systems. 2. ISO-TR 15916, Basic Considerations for the Safety of Hydrogen Systems. This international standard provides a comprehensive review of principles for safe design and use of hydrogen in systems. 3. NFPA-55, Compressed Gases and Cryogenics Fluids Code. This United States (U.S.) code is well- accepted for guidance on the fire-safety aspects of design and use of compressed gas and liquid hydrogen systems and containers. Web-based resources for hydrogen safety are also available. The U.S. Department of Energy (DOE) hosts websites with information about OPEX and background safety resources, including: 1. Hydrogen Tools, https://h2tools.org/: Developed by Pacific Northwest National Laboratory with funding from the DOE Office of Energy Efficiency and Renewable Energy's Fuel Cell Technologies Office, the goal of this website is to support implementation of the practices and procedures used

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to safely handle and use hydrogen in a variety of fuel cell applications. It provides resources on codes, safety, best practices, and lessons learned. 2. U.S. Department of Energy Hydrogen and Fuel Cells Program, https://www.hydrogen.energy.gov/: Hosted directly by the DOE Office of Energy Efficiency and Renewable Energy, this site has more general resources on hydrogen technologies. 4.6.4 How Existing Regulations Might Need to Change for Hydrail The Hydrail System can be logically divided up in two ways—either by step in the sequence of production to use, or by process type. For this discussion, the steps are: 1. Hydrogen Production: This step is assumed to be a single, large-scale, industrial water electrolysis plant. The electrolysis equipment would be expected to comply with ISO-22734. The plant would not fall under CHIC, but would follow the normal industrial practice of meeting building codes, and process vessel and piping codes. As well, hydrogen system engineering expertise would be fully involved in the project. The design would be proven to be safe to the satisfaction of the AHJ, often with reference to first principles. No change to codes and standards appears to be needed in this step. 2. Hydrogen Storage (Production Site): Existing codes and standards (B51 Part 1 and CGA G-5) adequately cover this. 3. Hydrogen Distribution: Transport Canada regulations and codes adequately cover this, both for gas and liquid by road and rail. Pipeline distribution is regulated in Ontario by the Ontario Energy Board, with TSSA responsible for review and inspection according to CSA Group (CSA) codes and standards (Z662). This is expected to need revision to adequately cover hydrogen, though there are already approved and operating hydrogen pipelines in Canada (for example, Heartland in Alberta). 4. Hydrogen Refill (local storage at refuelling site): The existing codes that address refuelling station storage systems are directed towards public-access automobile refuelling. The rail system refuelling will differ in several ways. It will be much larger, single-purpose, within a controlled area, and operated by trained staff. The existing standards (B51 Part 3, ISO/TS 19880) should be able to be modified for rail. However, B51 Part 1, CGA G-5, and NFPA-2 are also applicable and could be adequate for this purpose. 5. Hydrogen Dispensing (Refuelling): Requirements for dispensing are not well-defined at this point. It is expected that the transfer rates will be high compared with those for existing systems based on automobiles. New equipment and codes (that is, the HGV 4 series) may be needed. For dispensing liquid hydrogen, existing industrial methods and equipment should be applicable. 6. Hydrogen Vehicle (onboard use of hydrogen): The codes and standards noted in this section address all the types of systems required for Hydrail locomotives, but only for automobiles and forklifts. For trains, there is not only a significant change in the size and quantities involved, but the situation is different because the operation is controlled by trained staff, and the travel is restricted to dedicated areas. Incorporating allowance for trains into the standards for road vehicles may not be practical, and new standards may need to be developed. This step in the Hydrail sequence provides the most complex situation with the most diverse scenarios for safety analysis.

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4.6.5 Need for Additional Laws, Regulations, Standards, and Codes specifically for Hydrail An overview of the existing regulations, codes, and standards relevant to the use of hydrogen on passenger trains, as well as the generation, storage, and transportation of hydrogen, has identified the following for each Hydrail system component:  For hydrogen production, no change to codes and standards appears to be needed.  For hydrogen storage, existing codes and standards are adequate.  For hydrogen distribution, revision to the codes and standards for pipelines may be required.  For hydrogen refill, the existing codes (B51 Part 3, ISO/TS 19880) that address refuelling stations for automobiles should be modified for rail applications, but the codes (B51 Part 1, CGA G-5, and NFPA-2) are also applicable and could be adequate for rail.  For hydrogen dispensing, requirements are not well-defined, so new equipment and codes (for example, the HGV 4 series) may be needed. For dispensing liquid hydrogen, existing industrial protocols and equipment should be applicable.  For hydrogen vehicles, incorporating allowance for trains into the standards for road vehicles may not be practical, and new standards may need to be developed. 4.6.6 Proposed Roadmap To create a comprehensive regulatory framework for Hydrail, the following steps are proposed: 1. Engage a group of hydrogen and rail safety experts to work with Metrolinx. 2. Review Metrolinx’s existing safety management system (for example, programs, procedures, protocols, training, work activities) to highlight any modification required for Hydrail. 3. Review Transport Canada regulations and standards, CSA codes and standards, U.S. standards, and ISO standards. Prioritize these codes and standards in terms of applicability to Hydrail. 4. Engage ISO TC197 and CSA working groups to develop new or modify existing codes and standards specifically for Hydrail. 5. Seek public input and feedback. 6. Preparation and submission of Safety Case for approval by Transport Canada.

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4.7 Socio-economic Impacts This section provides an assessment of the socio-economic impacts of Hydrail deployment in Ontario, in accordance with plans for RER as outlined in the IBC. A quantitative assessment of Hydrail relative to overhead electrification is outlined, with consideration given to the short- and long-term job creation and gross domestic product (GDP) impacts. Further to this, a qualitative assessment was conducted, with consideration given to the additional environmental and economic benefits to be derived by a decision to pursue Hydrail, including the potential to fully electrify all corridors of the GO network and to spur the creation of a hydrogen economy in Ontario. 4.7.1 Quantitative Assessment 4.7.1.1 Methodology and Approach To assess the economic impact of Hydrail relative to overhead electrification, the Statistics Canada (StatCan) Interprovincial input-output model (the StatCan Model or the I-O model) was used to estimate the economic impact of each system. A comprehensive economic impact study, including the use of econometric or Computable General Equilibrium (CGE) models, was outside of the scope of this study. The StatCan model is however considered to be satisfactory for the level of economic impact analysis required to support the assessment being conducted in this study. In deriving the inputs into the StatCan model, reliance was placed on the description of the overhead catenary system (OCS) as described in Section 5.1 and of the Hydrail System as described in Section 4.2, as well as outputs of the IBC model and the Hydrail Operational Simulation Model, as described in Section 4.4. The determination of economic impact is a process of statistical estimations through the various sources, analysis by subject-matter experts and the use of valid economic and statistical methods. While the input-output framework provided by StatCan has been validated for accuracy, coherence, and overall reasonableness, the nature in itself is still an estimation. Further to this, the accuracy of estimates decreases in situations where the source data is incomplete in detail on a particular commodity, where there is limited coverage, where concepts are inappropriate concepts and/or where definitions do not coincide with the input-output accounts. The method used to determine the economic impact takes a collection of economic multipliers that translate direct impacts into indirect and induced economic impacts. Direct impacts are the inputs into the model and are generally defined as a change in industry output or final demand for a good. Indirect impacts reflect a change in supplier output or final demand to support direct impacts. Induced impacts reflect additional economic activity as a result of income generated by direct and indirect impacts given, for example, the increased disposable income of workers. As an example, in the case of the broadband sector the model would contain data describing supplier linkages between industries; these linkages generate the indirect economic effect. The industry’s purchases of repair services, electricity, fuel, and real estate services would generate employment in each of these sectors. Similarly, the induced economic effect estimated using an I-O model reflects the impact of the direct activity (broadband) on other sectors through employee purchases. Employees will have additional disposable income that will be spent at retailers, restaurants, service providers, and other businesses that will in turn create employment. For the analysis, the national and provincial economic and tax impacts related to RER and Hydrail will be estimated using the regional StatCan economic multipliers. The StatCan multipliers are estimated using an I-O economic model which describes relationships between businesses, households, and

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT governments within Canada. This model follows the flow of purchases of local goods by companies, as well employees, support sales, jobs, and tax revenues across Canada. The StatCan model is used by the public sector, private-sector businesses and other researchers and is based on widely accepted methodology for estimating these types of economic linkages. The multipliers in the StatCan model are based on the Leontief matrix, which estimates the total economic requirements for every unit of direct output in a given industry using detailed interindustry relationships documented in the input-output model. The input-output framework connects commodity supply from one industry to commodity demand by another. The multipliers estimated using this approach capture all of the upstream economic activity and backward linkages related to an industry’s production, by attaching technical coefficients to expenditures. These output coefficients (dollars of demand) are then translated into dollars of GDP, labour income and number of employees, based on industry averages. The analysis will primarily use the most recent economic multipliers developed by StatCan, currently as at 2013. The primary benefit of this approach is that the model can be built with a reasonable degree of accuracy, particularly in view of the limited economic data available for Hydrail. The limitations of this approach are that:  The analysis assumes constant production functions, labour-capital ratios, and productivity. Therefore, it is predicting future economic impact on the current economy.  This approach does not allow for differences in the cost of capital to result in capital-labour substitution.  The impact of a tax policy change on an industry cannot be directly predicted. For example, I-O models contain no information that allows the user to estimate the impact of a 10 percent investment tax credit on the level of investment. An external estimate of the amount of investment that would be stimulated by the tax credit would be required as in input to the model.  I-O models do not predict the cross-border flow of capital or population changes. The I-O Model provides a framework for assessing the order of magnitude of the potential financial and economic impacts that might arise from alternative assumptions related to the Hydrail and overhead electrification systems. The impact estimates produced by the I-O Model are subject to a very wide range of assumptions, all of which can have an important bearing on the results obtained. As such, it is important to understand that the model is not a forecasting tool but rather a simulation framework for obtaining, in a structured and organized manner, a sense of the impacts that may arise from the wide range of alternative assumptions adopted. The I-O Model incorporates assumptions concerning the building of either system (including, among other things, location, size and productivity) with a calculation framework for estimating the resulting financial and economic impacts. In setting the initial estimates for the model parameters, we have made use of data gathered from several sources, including past economic impact studies and StatCan input- output models, as well as real estate, construction and transit industry experts. To generate estimates of the financial and economic impacts, the Economic Impact Model incorporates numerous assumptions regarding the two systems. These key inputs include:  Location of CAPEX  The jurisdiction wherein the equipment is built  The value of construction costs and operating costs

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4.7.1.2 Limitations due to Data Inputs The assumptions that are associated with the inputs and the impacts that these assumptions could have on the outputs are detailed below (Table 4-43). Where there was uncertainty or lack of detail certain assumptions had to be made about the inputs. These assumptions are also detailed.

TABLE 4-43 LIMITATIONS DUE TO DATA INPUTS Input Description, Assumptions, Limitations Costs All costs include design, labour, contractors and materials. Assumptions: Each cost item was assumed to have a mix between these four components to estimate the impact in different industries. Limitations: The ultimate results will be impacted slightly as each industry, product and service has different economic impacts. Labour Costs All inputs related to labour costs represent total compensation costs, which typically include related items such as vacation pay, medical and dental benefits, life insurance, and employment assistance programs. Assumptions: Benefits, termed SLI in the I-O model, are based on the StatCan model for each service type, and varies industry to industry. SLI includes EI, and health and life insurance. Limitations: The assumptions across all labour costs may result in different direct labour impacts and direct employment, as the rate of benefits can differ between unionized workers and non-unionize workers, part-time, full-time and temporary workers, thereby causing a potential difference in the output values. Material Material Costs are described by their underlying commodity. Costs Assumptions: Based on general knowledge of the underlying items, major categories of commodities were used. Limitation: The ultimate results will be impacted by the commodity applied as each commodity has different economic impacts. Location of At this stage, the business case does not specify the suppliers of the material and services, therefore it is suppliers not possible to definitively determine whether the material and service providers are located in Ontario, Canada or internationally. Assumptions: The StatCan model dictates, based on its historical data whether the underlying commodity is wholly or partially produced in Canada or internationally Limitations: The location of the material is a significant assumption. Given that design specifications have yet to be determined for either technology, it is difficult to determine where materials will be purchased. For both technologies, there are limited categories and historical information in Canada to realistically indicate the mix of supplier locations. The actual supply mix will impact the result, with a negative impact being more international purchases. The output will provide the direct impact on Ontario. We have considered the inputs from all of Canada. Industry Industry categories are based on operating or capital activities rather than the industry categories used categories by Statistics Canada. Assumptions: Each cost, based on the knowledge provided and with the assistance of StatCan, was placed into a specific SUPC required by the StatCan model. Limitations: There may be variances between the SUPC chosen and the actual SUPC of the underlying commodity or service. Assumptions may have been made for the proper categories of OPEX and CAPEX for both systems to fit within the framework of the StatCan model. This was necessary for Hydrail because, while there is an existing hydrogen industry, the industry in Canada is relatively small. As such, StatCan does not necessarily have individual classifications for the relevant capital components or related services.

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Input Description, Assumptions, Limitations Base Year Costs are in 2014 values, and represent the impact for 60 years, while the StatCan model uses 2013 data. Assumptions: Inputs have not been adjusted for the difference in the base year. Limitations: The economic impact is as at 2013 and will vary from the impact in the 60-year timeframe. The results could vary significantly due to the length of the project cost period. Notes: EI = employment insurance SLI = supplementary labour income SUPC = Supply Use Product Classification 4.7.1.3 Business Model Results Financial Costs and Assumptions for Overhead Electrification The operating and capital costs as reflected in the IBC model and relevant assumptions are summarized below (Table 4-44). Values are presented in 2014 dollars.

TABLE 4-44 OPERATING AND CAPITAL COSTS AND RELEVANT ASSUMPTIONS NPV Operating Costs ($M) Description of line item Crew Costs 1,479 Train operators Assumption: Includes 15 percent benefits Diesel Fuel 691 Diesel fuel Electricity for Traction 521 Electricity Rolling Stock Maintenance 2,255 Vehicle Maintenance of the locomotives in use Assumption: Includes 15 percent benefits Infrastructure Maintenance 1,217 Includes track maintenance, signal maintenance and overhead line maintenance. Annual incremental infrastructure maintenance is 1 percent of track CAPEX. Annual incremental signaling maintenance is 1 percent of signaling CAPEX. Annual OHLE maintenance is 2 percent of OHLE CAPEX. Assumption: Repairs costs relative to capital costs are the same as operating costs. User Charges – 404 User Charges for trains to run on CN/CP tracks Plant & Roadway Assumption: Proxy to land leasing costs Other 5,710 Includes dispatching costs; other operational costs such as wayside power for diesel trains when not in use; administrative costs; facilities such as headquarters, maintenance facilities, layovers and layover berths; and administrative costs including MX Corporate, GO Execs and GO Customer Service. Assumption: Material cost includes contractors/professional fees - 8 percent, insurance - 2 percent and materials - 24 percent (electricity - 19 percent, Gas - 4 percent, water - 1 percent). Total Operating Costs 12,277 Infrastructure 4,093 Includes station modifications, guideway and track costs. This includes costs for rough grading, excavation, fencing bridge deck, noise walls, rail/road grade separations. Includes all construction materials and labour regardless of who will perform the work. Includes 15 percent engineering design, 50 percent contingency and 25 percent accelerated mark-up. Assumption: Metal and construction grade make up 80 percent of material costs.

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TABLE 4-44 OPERATING AND CAPITAL COSTS AND RELEVANT ASSUMPTIONS NPV Operating Costs ($M) Description of line item Electrification capex 1,762 As associated with electrification-related systems, includes all construction materials and labour regardless of who will perform the work. Includes 40 percent overhead catenary, 35 percent signal immunization, 15 percent electrification substations, 10 percent station modifications for electrification, bridge rework for electrification and electrification of sidings. Assumption: Wires and transformers are 85 percent and 15 percent is for regular construction. Property 221 Includes professional services associated with the real estate component of the project. These costs may include agency staff oversight and administration, real estate and relocation consultants, legal counsel, court expenses, and insurance. Assumption: 60% is the actual property cost, 35% is for consultants, and 5% is for insurance. Carparking 624 Parking, includes 15% design costs. Fleet 4,105 Rolling stocks costs for RER fleet and GO 5-Year Plan. 84 4-car EMU to be acquired in 2024 which the diesels are retired. No more acquisitions/replacements after 2044. Other network CAPEX 2,137 As associated with all other systems, include all construction materials and labour regardless of whom is performing the work. Include signal prioritization at intersections. Include passenger information systems at stations and on vehicles (real time travel information; static maps and schedules). Include equipment to all communications among vehicles and with central control. Include fare sales and swipe machines, fare counting equipment. Includes 15 percent engineering cost and 50 percent contingencies. Total CAPEX 12,942

Financial Costs and Assumptions for Hydrail The Hydrail System is assumed to maintain the same level of service and delivery as proposed for RER. To isolate the true differences between Hydrail and overhead electrification, only the cost items that are directly and explicitly impacted by Hydrail are altered from the IBC model to the Hydrail simulation model. The three line items impacted are described in Table 4-45.

TABLE 4-45 OPERATING AND CAPITAL COSTS AND RELEVANT ASSUMPTIONS Costs NPV ($M) Description Electric Traction 1,299 This line item represents the electricity requirement of the system under Hydrail. Power – Hydrail Infrastructure 1,534 In the RER model, this refers to the maintenance and renewal of the overhead Maintenance electrification lines. This includes an allowance of 2 percent of the capital costs of overhead line electrification per year per. In the Hydrail model, these overhead lines do not exist. The costs therefore are associated with maintenance of the hydrogen infrastructure, and is estimated at 10 percent of the capital costs. Since there is a portion of the infrastructure that is similar to overhead electrification, such as guideways and signaling, there are assumptions built in to the breakdown of the costs for the I-O Model that these costs would remain the same.

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TABLE 4-45 OPERATING AND CAPITAL COSTS AND RELEVANT ASSUMPTIONS Costs NPV ($M) Description Hydrail Capex 2,658 This includes the cost of production facilities, pipelines, storage tanks, storage compressors, refill tanks, refill compressors and dispensing infrastructure. Fleet 3,927 This includes costs for rolling stock, excluding HFC costs, which are covered under Hydrail Capex. 4.7.1.4 Economic Impacts RER will generate a wide range of financial and economic impacts on the province, including:  Incremental growth in the Province’s GDP arising from the construction and the ongoing operation of either an overhead electrification or Hydrail Syste  The creation of new employment during the construction and ongoing operation of either system Gross Domestic Product The analysis considered the direct and indirect tax revenue that each level of government may potentially receive as a result of Overhead Electrification and Hydrail in Ontario (Table 4-46). The results indicate that RER implementation will positively impact GDP, with Hydrail being expected to generate approximately $2.6B more in GDP than overhead electrification.

TABLE 4-46 GDP IMPACTS ($000) Overhead Electrification Hydrail Operations $72,455,685 $72,596,379 Capital152 $12,631,935 $15,150,014 Total $85,087,620 $87,746,393

Employment Levels The analysis indicates that during the construction and operational phases of RER, implementation through overhead electrification can be expected to lead to the creation of 429,031 Full-Time Equivalent (FTE) jobs, while implementation through Hydrail can be expected to lead to the creation of 427,734 FTE jobs (Table 4-47). FTE is the ratio of the average number of paid hours during a period (part time and full time) by the total number of working hours in that period. In other words, one FTE is equivalent to one employee working full-time. The FTE job metric is measured in person-years, as in the number of FTE per the hours required on an annual basis to qualify as such. Table 4-47 EMPLOYMENT (FTE)153 Overhead Electrification Hydrail Operations 320,170 340,876 Capital 108,861 131,858 Total 429,031 472,734

152 Input and Investment Total Impact, Closed Model 153 Total Impact, Closed Model; includes the direct, indirect and the induced impacts.

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The FTE job numbers are likely overstated since I-O is a static model and does not incorporate dynamic macro variables such as, labour force, population, wages, and salary growth over time. Using 2014 dollars, it is likely that over the life of the project, wages and salaries, labour supply constraints, and more generally, business cycles, would impact the number of FTE per the proposed OPEX and CAPEX, and likely overstate the number of FTE jobs. 4.7.2 Qualitative Assessment A consideration of the qualitative, non-financial and/or social aspects of the Hydrail is necessary to fully understand the impact of Hydrail relative to overhead electrification. The government is accountable to the community and its use of public funds. Therefore, all benefits and costs must be considered (where possible and as practical) to ensure the best option for the community is progressed, even if the option is not optimal in financial terms. A role of government is deliver public goods and services such as community transit. These projects, by addressing public issues, result in many qualitative, but significant impacts. These must be identified, considered and assessed for an informed government decision to occur. Social impacts refer to the effects of an activity on the well-being of communities and people. Due to this broad definition, for the purposes of this study we have sought to only identify and discuss those qualitative and/or social impacts that are unique to the use of Hydrail, as opposed to electrification of the system in general, or other methods of powering rail. We have broadly identified three core areas of qualitative impacts that are important to consider alongside the financial results when determining the long-term feasibility of Hydrail:  Industry impacts  Environmental impacts  Community impacts Each of the above identified areas are discussed in the sections that follow. The discussion focusses on the nature of the impact (that is, positive or negative) rather than the extent of such impact. 4.7.2.1 Industry Impacts Fuelling Innovation and the Hydrogen Economy While the hydrogen and fuel cell sectors in Canada is growing in Canada, it still represents a very small percentage of the country’s GDP. An investment in Hydrail will lead to growth in not only this sector, but also other sectors that support the Hydrail System, such as the automotive, oil and gas and power and utilities sectors. Though the broader economic impacts of this investment have been considered, it is also important to note the qualitative or social benefit of growth of the hydrogen and fuel cell sectors. It is expected that a decision to use Hydrail for RER would act as a catalyst and drive interest and activity in the sector, due to the arising need for supporting infrastructure. Further to this, Hydrail can facilitate the establishment of infrastructure to also facilitate the deployment of hydrogen and fuel cell technology in other areas of transportation. This would incentivize an increase in research and development (R&D), drive innovation and technology improvements. These activities will create the right economic conditions or climate to stimulate demand for further investment in this industry and technology.

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Skilled Workers Our economic impact analysis indicates that, relative to overhead electrification, Hydrail will create over 40,000 more jobs across a range of industries. While a clear economic benefit, it is important to note the qualitative benefits associated with this growth. This investment in technology that is relatively new to the province would support and drive the up-skilling of labour, resulting in more Ontarians becoming skilled technicians available to construct, deploy, maintain and repair a Hydrail System. It is however noted that a significant and immediate investment will have to made to train the required workforce, such that skilled labour is available as required for Hydrail deployment, and to limit the need to import labourers. 4.7.2.2 Environmental Impacts Full Electrification of the GO Network As noted in Section 4.2.1.2, the current plans for electrification of the GO network do not include the Richmond Hill and Milton lines nor do they include the extremities of the Kitchener and Lakeshore West lines. These rail lines or sections were not included because of concerns of flooding along the Richmond Hill line and complexities surrounding obtaining approval for installation of an OCS along rail lines or sections that are not owned by Metrolinx. Hydrail, however, eliminates or reduces these concerns, thereby allowing for the full electrification of the GO network. The environmental impact of this is significant, as there would be a further reduction in GHG emissions with the full phasing out of diesel fuelled rail vehicles. All other benefits of electrification relative to diesel will also extend to these rail lines or sections, thereby increasing the overall benefit of the RER program. Supporting renewable energy Hydrogen has the potential to support the generation and supply of renewable energy. Hydrogen can act as an energy storage medium, thereby allowing for renewable energy, such as solar and wind energy, to be captured when available and stored. Stored energy can then be used to generate electricity at times when market would otherwise demand exceeds supply. The increase in research and development activity generated from the deployment of Hydrail in Ontario, will likely lead to increased knowledge and innovation in respect of the use of hydrogen as an energy storage medium. This could lead to wider benefits accruing to the benefit because of increased access to clean energy. The province could also benefit from reduced cost of delivering electricity to Ontarians, as energy storage options allow for increased ability to the maximize the use of existing renewable energy generating facilities, thereby deferring investments in new infrastructure. Noise The construction of an overhead catenary system that extends across the GO network will generate noise and vibration during the construction phase, which are likely to disrupt local residents. The level of disruption is expected to be less with Hydrail, noting that there would be relatively minimal construction activity associated with the development of hydrogen infrastructure.

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4.7.2.3 Community Impacts Availability and Reliability During the construction phase, disruptions to transportation caused by the construction of an OCS may have long term consequences, particularly given longer commute times, with higher than usual congestions on roads, highways, and subways as commuters seek alternative transportation options. These factors would ultimately negatively impact economic productivity. During the operations phase, no differences are expected between overhead electrification and Hydrail in terms of availability and commuter waiting times. As discussed in Section 4.2.1.2, each locomotive will be prepared for service in an identical manner, with no difference with regards to the dispatching timeline. In the initial roll-out of the project however, delays may occur as employees or technicians would take some time to advance along the learning curve. As such, maintenance or servicing of a HFC-powered rail vehicle will likely require greater time than for vehicles powered by an OCS. This time off the track for maintenance or servicing may disrupt schedules and thus cause commuter delays, which would translate into reduced productivity. Initiative to Transition Ontario to a Hydrogen Economy The introduction of Hydrail on the GO network can serve as a launching pad for the establishment of a hydrogen economy in Ontario, as described in Section 4.9.1. This could in turn have far reaching socio-economic benefits across the province. As has been noted in the preceding sections of this study, hydrogen has a variety of different uses in industry, with significant annual production levels globally. Within the transportation sector, hydrogen can be used to fuel vehicles and, where derived from clean sources, allows for a significant reduction in the level of GHG emissions historically generated from transportation. As part of a global imperative to reduce GHG emissions, several governments, including the Ontario government, have allocated funding to facilitate the transition to hydrogen and other clean energy sources for transportation. Ontario’s expertise in the development of HFCs and the generation of clean energy, can be leveraged to support the transition to clean fuel sources in Ontario and beyond, and also support the local production of hydrogen for other industrial purposes. A significant barrier has been the necessary investment in infrastructure to support the adoption of hydrogen fueled vehicles. The scale of operations needed to fully support the GO network, can serve to attract initial investments to develop, and later expand hydrogen generation, storage, distribution and fuelling facilities, along with HFC production facilities within the province. These investments can lead to the broader application of hydrogen as a fuel in other areas of transportation, including other forms of public transportation such as buses, streetcars and subways services; municipal fleets such as school buses and garbage trucks; commercial fleets; and private motor vehicles. Such wide scale application can in turn lead to an increasing demand for skilled labour along each step of the supply chain, and the potential for increased production of the various components within the province. This will spur other indirect and induced impacts throughout the economy. Ontario is already recognized as a global leader in the development of HFC technology and in the generation of clean energy. The development and accumulation of skills and knowledge to support the hydrogen supply chain within Ontario will eventually also position the province as a thought leader in hydrogen technologies. Ontario will be able to export its expertise to other regions looking to transition to clean fuels for transportation, thereby increasing the economic benefits associated with Hydrail.

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Given the global drive to reduce GHG emissions, the opportunities for the application of hydrogen as a fuel source for transportation are significant. To date, there has however been low penetration of hydrogen in transportation globally. Ontario’s early adoption and development of relevant skills and knowledge therefore presents significant opportunities to propel the local economy, and to facilitate the global transition to clean energy. 4.7.3 Conclusion The quantitative analysis presented indicates that Hydrail is expected to have a slightly greater economic impact than overhead electrification, in respect of the ability to spur job creation and GDP growth. The benefits of Hydrail are enhanced when considering other benefits as described in the qualitative analysis. In particular, the potential for the development of a hydrogen economy in Ontario has not been quantified, but as discussed, the resulting impacts would be significant. Further to this, there are other key societal benefits to be derived from the ability to electrify the full GO network, and the enhanced ability to support renewable electricity generation and clean fuels across all modes of transportation. These additional benefits suggest that the province will realize greater socio-economic benefits using HFC to power trains on the GO network.

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4.8 Public Acceptance While Canada is a global leader in the development of HFC technology, there has been little application of the technology in transportation in Canada. As discussed in Section 4.10, most applications in public transportation fleets or in passenger vehicles have occurred in British Columbia. Ontario has seen application of the technology on a much smaller scale, but only in powering forklifts. Accordingly, there is limited experience with hydrogen as source of fuel among average citizens, who best know hydrogen for its combustive properties. Hydrail deployment in Ontario will involve the creation of hydrogen generation and storage facilities within the province, possibly in proximity to residential and commercial centres, and the operation of passenger trains with reservoirs of hydrogen onboard. Given the likely perception of hydrogen as a highly combustible gas, should a Hydrail deployment be pursued, a robust public education campaign would have to be designed and implemented. The campaign should facilitate a high degree of comfort around the safety of hydrogen for use in transportation in general, and in passenger rail operations in particular. The most wide-scale implementation of hydrogen and HFC technology in transportation in North America has come with the development of the California Hydrogen Highway Network (CaH2Net or the Hydrogen Highway). There are limited cases of the use of HFC technology in passenger rail across the globe, with the most relevant and advanced case being the planned German deployment of HFC-powered trains into full service, across five states, in 2018. This section provides an overview of the public engagement strategies employed in California and Germany, and recommends steps to be taken to facilitate public acceptance of a deployment in Ontario. 4.8.1 The California Hydrogen Highway154 In April 2004, the Governor of California signed Executive Order S-7-04, calling for the creation of the Hydrogen Highway in response to the need to diversify the state’s sources of transportation energy, while also providing environmental and economic benefits. The Executive Order (EO) called for:  The designation of California’s 21 interstate freeways as the CaH2Net  The planning and build-up of a network of hydrogen fuelling stations along these roadways and in the urban centres they connect so that by 2010, every Californian will have access to hydrogen fuel  The acceleration of progress in hydrogen use through public incentives and financing mechanisms  The promotion of economic development opportunities resulting from increased use of hydrogen for stationary and mobile applications The development was being pursued over three phases, as demonstrated in Table 4-48.

154 California Environmental Protection Agency. 2005. California Hydrogen Blueprint Plan – Volume 1. May. Accessed November 2017. http://www.casfcc.org/2/StationaryFuelCells/PDF/CA percent20Hydrogen percent20Highway percent20Blueprint percent20Volume percent201_050505.pdf

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TABLE 4-48 HYDROGEN HIGHWAY DEVELOPMENT OVERVIEW Phase 1 2 3 Stations 50 – 100 250 250 Light-duty FCVs and ICEVs 2,000 10,000 20,000 Heavy-duty FCVs or ICEVs 10 100 300 Stationary and off-road vehicle applications 5 60 400 Notes: ICEV = internal combustion engine vehicle

Phase 1 was to be implemented over a 2-year period, and Phase 3 was expected to be complete by 2010. An EO Team was formed to manage the development of a California Hydrogen Blueprint Plan (the Blueprint). The Blueprint, which initially focussed on Phase 1 of the implementation, was developed through a process of partnership and cooperation with stakeholders. The EO Team was counselled by a Senior Review Committee, consisting of senior state government officials, and an Implementation Advisory Panel, which consisted of high-level representatives from industry, California State agencies, federal and local government agencies, academia, and public advocacy groups. In addition to this, volunteer experts across an array of government agencies, private industry, academia, and environmental organizations provided detailed technical, financial, and policy inputs across five topic teams, namely: 1. Rollout Strategy 2. Societal Benefits 3. Economy 4. Implementation 5. Public Education The Blueprint presented a series of findings and recommendations for the development of the Hydrogen Highway. Today, there are approximately 29 open-retail and 4 on-retail hydrogen fuelling stations in operation in California, with 37 more stations scheduled to be opened by the end of 2017. As of April 2017, there were over 1,600 active registrations of FCEVs155. The sections that follow describe the public education strategy recommended by the Marketing, Communications, and Public Education Topic Team (Topic Team) as part of the development of the Blueprint.

155 Air Resources Board. 2017b. 2017 Annual Evaluation of Fuel Cell Electric Vehicle Deployment and Hydrogen Fuel Station Network Development. California Environmental Protection Agency. August. Accessed November 2017. https://www.arb.ca.gov/msprog/zevprog/ab8/ab8_report_2017.pdf

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4.8.1.1 Marketing, Communications, and Public Education Topic Team Report156 In its report to the EO Team, the Topic Team emphasized that public education would be a key factor to the success of the Hydrogen Highway, noting the importance of the public understanding the reasons for the initiative and being supportive of it. The Topic Team asserted that key groups would have to be engaged, and active public education, marketing, and communications campaigns would be essential. Early engagement was also considered important, to avoid misinformation causing negative views to take hold. While it was recommended that one key message be communicated across all stakeholder groups, it was also deemed necessary to identify key messages and action steps for each group. The key groups identified and messages suggested are summarized in this section. Key Groups Technology and Industry Enablers Companies, industry associations, labour organizations, and research institutions will need to facilitate technology advancements and commercial installations. They will need to recognize the business opportunities that a hydrogen economy presents, and help to communicate to the wider public on its merits. Government, Policymakers, and Policy Influencers The advancement of hydrogen technology and the installation of hydrogen infrastructure will require the support of this group to create the necessary policies and regulatory environment. This group will have to be educated on hydrogen and hydrogen technology, particularly in regards to the safety of hydrogen’s production, delivery, and use, as well as the potential benefits of a hydrogen economy. Consumers, Customers, and News Media The general public should be educated such that they understand that using hydrogen in transportation is consistent with other sustainability policies. The public education campaign should allow for the public to become familiar and comfortable with hydrogen, understanding that is it as safe as other fuels, and that HFC-powered vehicles have the potential to deliver performance and utility similar to other vehicles. For communities where hydrogen fuelling stations will be installed, there should be early and concentrated efforts at the local level. This will engender a sense of pride in having hydrogen programs in these communities, before fear and opposition, based on a lack of knowledge, sets in. Education Community It was recommended that a sustained program, covering basic concepts related to hydrogen and fuel cells, be incorporated into curriculum guidelines throughout all levels of California’s education system. Community colleges were also recognized as playing an integral role in the development of a workforce to support the hydrogen economy, so it was recommended that they incorporate hydrogen and sustainable technology in their programs. It was also suggested that universities, colleges, and

156 Air Resources Board. 2005. Marketing, Communications, and Public Education Topic Team Report, California 2010 Hydrogen Highway Network. California Environmental Protection Agency. January 5. Accessed November 2017. https://www.arb.ca.gov/msprog/zevprog/hydrogen/documents/historical/pubedreport.pdf

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT research institutions expand their roles in the training of engineers, scientists, business leaders, and policymakers to support the hydrogen economy. Key Messages It was recommended that the communication strategy be centralized, directed, and coordinated at a senior policy-making level to support success. Additionally, for each key group identified, a single, visible, and accessible point of contact should also be identified. To the greatest extent possible, joint participation between industry, government, nongovernment organizations (NGOs), and academia was encouraged, as this would demonstrate the depth of support for the hydrogen economy. It was, however, noted that care should be taken in developing communications and public engagement programs, so that unrealistic expectations are not created that would threaten public and political support. 4.8.2 The German Experience

The German Federal Government had set 2030 objectives to reduce CO2 emissions by 55 percent and generate 50 percent of electricity from renewable sources. In view of this, there was strong industry and public interest in reducing emissions along rail routes. Roughly 50 percent of the German rail network is not electrified; however, overhead catenary construction was considered to be too capital intensive, negatively impacting profitability on some sections of the network. Further to this, overhead catenary lines were not desirable in scenic areas, where the necessary infrastructure would detract from the landscape. Electric trains, powered by HFC technology, were seen as an interesting and promising option to reduce emissions, develop a hydrogen industry, and meet stakeholder expectations. Germany has a long history with hydrogen in transportation. The German government has identified hydrogen and fuel cell technology as essential to the future of mobility and energy supply. In 2002, the Clean Energy Partnership (CEP) was established, as a joint venture (JV) between government and industry, to test the suitability of hydrogen as a fuel157. In 2006, the government, industry, and science established the 10-year National Innovation Programme for Hydrogen and Fuel Cell Technology (NIP) to facilitate the development of these technologies and provide support for initial products. Fuel cell hybrid buses have been in operation in Hamburg, Germany since 2011 and in Stuttgart, Germany since 2013. The government has also formed partnerships with car manufacturers since 2003. In 2007, the first set of hydrogen-powered vehicles were handed over to customers. Today, there are over 400 cars in operation in Germany. The German government has pledged continued support of innovations in HFC technology for use in various transportation sectors, including buses, transportation, and rail. The first hydrogen filling station went into operation in Berlin in 2004, and there is currently a network of 32 hydrogen fuelling stations in operation in Germany. These stations were sponsored by the German government through the NIP. Germany plans to have 100 filling stations in operation by 2018 and as many as 400 by 2025, supported by an investment of €350 million by the German government158. Since 2008, the CEP has been engaged in intensive public relations activities, aimed at effectively anchoring hydrogen in the public consciousness as a fuel and energy store. A long-term

157 Clean Energy Partnership (CEP). 2017a. "What is the CEP." Clean Energy Partnership. Accessed October 2017. https://cleanenergypartnership.de/en/clean-energy-partnership/what-is-the-cep/ 158 CEP Review 2002-2016

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT communication plan was developed for defined target groups, with various tools used to engage each group, including print and web-based communication, appearances at trade fairs, viral films, social media activities, Campus Days at select universities, and test drive events. 4.8.2.1 Government’s Role in Using Hydrogen in Transportation The National Organisation Hydrogen and Fuel Cell Technology (NOW) was founded in February 2008 as a federally owned company. It was established to:  Administer the programs for NIP and electro-mobility on behalf of the Federal Ministry of Transport  Act as an interface for the strategic alliance of government, the scientific community, and industry  Allocate public funding and to create synergies in the industry  Act as a competency and public education centre NOW’s management is supported by a Supervisory Board and an Advisory Board. The Advisory Board has the task of providing both content and technical consultation support to the management of the program partners for NIP implementation. The board comprises representatives from 18 interest groups, across government, science, industry, and infrastructure. The NIP was specifically created to facilitate product and process innovations. It also facilitates partnerships across government, industry, and academia. The NIP was initially funded by the Federal Ministry of Economics and Technology (14 percent), the Federal Ministry of Transport and Digital Infrastructure (36 percent), and industry partners (50 percent). The Federal Ministry of Transport and Digital Infrastructure has also contributed up to €500 million for industry-led research projects.

FIGURE 4-46 NATIONAL ORGANISATION HYDROGEN AND FUEL CELL TECHNOLOGY OVERVIEW

The Federal Ministry of Transport and Digital Infrastructure intends to invest approximately €250 million in Phase 2 of the NIP by 2019159. Under Phase 2, the ministry is promoting the competitiveness of technically mature products.

159 CEP Review 2002-2016

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4.8.2.2 NOW’s Role in Hydrail Development in Germany In 2014, the Federal Ministry for Transport and Digital Infrastructure, through the NIP, committed €7.9 million in support of the development of HFC-powered rail vehicles, with the first prototypes expected to go into test service operation by the end of 2016. The government’s support was based on the view that electricity-based fuels from renewable energy were key for sustainable mobility, and also allowed for new job creation in Germany. The vehicles were to be developed and manufactured by train manufacturer, Alstom, in the company’s competence centre for regional trains in Salzgitter, Germany. The German states of Lower Saxony, North Rhine-Westphalia, Baden-Württemberg, and Hesse had signed Letters of Intent for the purchase of HFC-powered train sets. NOW also commissioned a study to assess the feasibility of the use of HFC to propel trains in Germany. The research examined the technical, legal, and economic requirements for hydrogen integration into existing rail infrastructure. The study showed that deploying HFC trains is economically feasible in principle. A public engagement roadmap was produced as a part of the study. Even though by 2016 there was already a high level of public acceptance of hydrogen-fuelled transportation in Germany, a government-led public relations, education, and stakeholder consultation campaign for Hydrail was key. As a part of the public engagement plan, a Fuel Cell Electro-mobility in Rail Transportation symposium was jointly held by NOW, Alstom, and Lower Saxony’s Ministry for Economy, Labour and Transport in 2016. The symposium was intended to lay the foundation and bring greater focus on the topic of Hydrail among key players from government and industry. The event focussed on technical issues on both the vehicle and infrastructure sides, and considered national and European transportation strategy policies and perspectives of various transportation service providers. A second symposium was held in 2017, where a model HFC train was made available for test rides. 4.8.2.3 Regional Governments’ Roles in Hydrail Development in Germany German regional governments control the public transit authorities; accordingly, their commitment to purchase HFC-powered trains through signing Letters of Intent was a significant driving force behind the development of the technology for trains. Aside from the environmental benefits, the regional governments recognized the potential for job creation and economic development. As at March 2017, Alstom had signed Letters of Intent to purchase a total of 60 trains from the German states of Lower Saxony, North Rhine-Westphalia, Baden-Württemberg, and the Hessian transport association Rhein-Main-Verkehrsverbund160. Political leadership was also instrumental in public acceptance of the technology. They provided support by being at the forefront of public engagement and consultation. 4.8.3 Differences between Ontario and the California and German Deployments In California, there had been some familiarity with the use of hydrogen as a fuel when the Blueprint was initiated. At the time, there was an estimated 39 stations either planned or in existence in the state, and 200-300 light-duty FCVs were already being provided as part of existing industry and government programs. Further to this, the scale of hydrogen production needed to support the

160 Alstom. 2017. "Alstom’s hydrogen train Coradia iLint first successful run at 80 km/h." Press Centre. March 14. Accessed November 2017. http://www.alstom.com/press-centre/2017/03/alstoms-hydrogen-train-coradia-ilint-first-successful-run-at-80-kmh.

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT planned vehicle deployment across the state was small in comparison to the scale required to support RER, as planned in Ontario. Another significant difference lies in the timeline to full deployment. The CaH2Net has now been in active development over a 12-year period, and while there have been successes, the level of deployment of hydrogen-fuelled vehicles has not reached 20,000, which is the goal set in the Blueprint for realizing full-scale commercialization of hydrogen and fuel cell technologies. In Germany, public engagement was consistent and strategic over roughly 6 years prior to the decision to pursue the use of HFC to power passenger trains. Familiarity with hydrogen and HFC technology had advanced to the point where it was easier for the public to assess the advantages and risks of Hydrail relative to overhead electrification. In the Ontario context, public engagement will have to play an even more significant role in a Hydrail implementation plan, particularly given that the starting point in respect to public awareness and acceptance of the technology is vastly different. This is especially important within the context of very vocal communities that are significantly empowered at the municipal level. Provincial mandates are often actively challenged, and the strong opposition of activists within communities can force plans to be abandoned, where the province is unable to engender the support of community members. 4.8.4 Recommendations for Ontario Deployment Should Hydrail be pursued in Ontario, it will be important to identify all stakeholders across federal and local government bodies, communities, political representation, industry, academia, labour groups, environmental groups, media, and any other key groups. A clear communication plan should be developed and promptly implemented. The plan should outline the reasons for pursuing Hydrail, take a balanced approach to outlining the rationale within the context of competing technologies, and directly address the risks and challenges presented by Hydrail deployment. It is recommended that there be consultation and dialogue with key stakeholders, using surveys, community meetings, symposia, and demonstrations. These methods have been identified as key success factors in California and in Germany. 4.8.4.1 Key Themes Similar to the German example, the key themes of the approach should address the five phases of hydrogen use for rail:  Production  Transport  Storage  Fuelling  Usage The key themes at each of the phases are further broken into five subject areas:  Safety  Sustainability  Environmental  Economics  Reliability, as described in this section

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Safety The safety of the technology, systems, and processes is likely to be of significant concern to the public. Controls across the five phases, as well as mechanisms to prevent leakages and to minimize the impact of systems failures or human error, should be strongly emphasized. Where possible, opportunities should be provided for the public to experience the technology, a key example being the demonstrations and test rides that were offered to members of the public in Germany. Given that safety concerns will largely centre on the supply and storage of hydrogen, the public should be educated on the long history of the generation and use of hydrogen in various processes across industry. Existing safety standards and the industry’s track record in meeting the standards set should also be highlighted. Sustainability With the increased focus on sustainability in transportation, the public will likely be interested in the sustainability of Hydrail, relative to both diesel and overhead electrification. This should not only consider the ultimate source of hydrogen, but also the sustainability of the hydrogen supply chain. As discussed in Section 4.3, Ontario’s electricity system should accommodate the supply of relatively clean electricity to produce hydrogen through electrolysis. Further consideration should, however, be given to the carbon footprint of other processes, such as the supply of water and the transportation of hydrogen. The additional benefit of being able to electrify the full GO network (including the Milton and Richmond Hill lines) should be considered, and the sustainability of the full Hydrail system assessed in comparison to traditional diesel and electrification, using a well-to-wheel approach. Environmental The installation of overhead catenaries across the GO network will require the removal of approximately 2.5 km2 (square kilometres) of trees; therefore, will have a significant negative environmental impact, in addition to the visual impact of wires strung across the province’s landscape. While Hydrail will not have a similar impact, concerns will likely be raised about the environmental impact of potential leakages or spills, particularly at hydrogen storage sites or during transportation. Environmental stakeholders and regulators will have to be engaged, and a level of comfort provided around mechanisms that will be in place to prevent spills or leakages, or to limit the environmental impact where spills or leakages cannot be prevented. The ability to comply with existing standards will have to be demonstrated, and the need for additional standards emerging from the establishment of Hydrail and related services will have to be assessed. Economics Given the size of the RER project, the public is likely to have strong concerns about the economic benefit of any plan to electrify the network. These concerns will likely be magnified in considering the use of HFC technology, given that the technology has had limited application in passenger rail, with no instances of application on the scale being considered in Ontario. A decision to pursue Hydrail will, therefore, have to be supported by robust financial and economic assessments that demonstrate the merit of RER in general, and the use of HFC technology as opposed to traditional electrification. The economic benefits should also be assessed within the context of the broader socio-economic benefits of Hydrail. Hydrail creates the strong potential for increased economic activity within the province to support the five phases of hydrogen use, as well as the production of HFCs. These benefits should be highlighted, with a clear demonstration of provincial, commercial, and institutional plans to support the training and development of workforces to support the full supply chain.

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Reliability Particularly within the context of the cost of a Hydrail implementation and the cost of failure, public engagement will have to facilitate a high degree of comfort around the reliability of HFC technology and the hydrogen supply chain. While there is a long history of electrification in public transit for buses, streetcars, and subway trains, HFC has had relatively limited application in public transportation. This will generate concerns around the long-term prospects for the technology. The public should also be aware of Canada’s role in the development of the technology, and government and industry sponsored initiatives to improve the technology, as discussed in Section 4.9. This will allow for comfort around the level of commitment from government and industry to the continued development of HFC technology. There are limitations in respect to current hydrogen fuelling technology that should also be adequately addressed, with a clear demonstration of the ability to overcome challenges. Further to this, concerns will arise around the hydrogen supply chain, given the limited examples of large-scale production and storage of hydrogen. There should be a clear demonstration of the scalability of hydrogen technology along each step of the supply chain and the market’s capacity to support Hydrail in Ontario.

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4.9 Implementation Readiness This section provides an assessment of technological readiness at present, describes expected changes to the maturity of the technology, and considers competing technologies. This assessment forms the basis for the rest of the report. The section also provides an overall assessment of the readiness of the industry to support Hydrail deployment in Ontario, including hydrogen generation, storage, transportation, and fuelling, as well as fuel cell technologies. This section also discusses deficiencies and what may be required to ready the industry should there be gaps. 4.9.1 Hydrogen Economy161 Hydrogen can, in principle, replace all forms of energy in use today and serve all sectors of the economy. The fundamental attraction of hydrogen over fossil fuels is its potential environmental advantages. At the point of use, hydrogen can be burned, or it can be converted to electricity in a fuel cell, producing no harmful emissions. If hydrogen is produced without emitting any GHGs, it could form the basis of a truly sustainable energy system – the hydrogen economy. In a world that has transitioned to the hydrogen economy, an efficient and competitive hydrogen production, storage, and transportation system has been built; and hydrogen has become widely accepted as a clean, safe, and sustainable form of energy. A hydrogen economy could be as follows:  Hydrogen is produced through electrolysis using electricity derived solely from nuclear power or renewable energy sources, or through thermochemical or biological techniques based on renewable biomass. Produced hydrogen is burned in highly efficient gas turbines to provide electricity, or is piped to customers. Hydrogen is also used to store the intermittent energy generated from wind turbines and photovoltaics.  Highly efficient hydrogen-powered vehicles are used to convey people and goods. Most of these vehicles refuel at public stations fed by centralized hydrogen production facilities. Small-scale natural gas reformers or renewable-energy-powered electrolysis plants are also used at home or in the workplace to produce the hydrogen required for filling on-board hydrogen tanks.  Home owners have the choice of buying electricity from the grid or supplying their own energy needs using hydrogen with a dedicated fuel cell that provides electricity and thermal energy for heating and cooling. Like any other product, hydrogen must be stored, transported, and transferred to bring it from production to final use (Figure 4-47). While production and final use has been the focus of attention for many years, the infrastructure required to store, transport, and transfer the hydrogen for final use in a hydrogen economy is not fully developed or is nonexistent in many jurisdictions, including Ontario.

161 United Nations Environment Programme (UNEP). 2006. The Hydrogen economy, a non-technical review. Paris: Division of Technology, Industry and Economics (DTIE). Energy Branch.

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FIGURE 4-47 HYDROGEN ECONOMY Hydrogen Economy Storage Hydrogen (compressed gas, liquefaction, hydrides) Hydrogen Use Production Distribution (pipelines, road, rail, ship) Transfer

Various governments around the world have developed policies and provided funding to kick-start development of the required infrastructure for the hydrogen economy. This section provides a summary of the required infrastructure in other jurisdictions. 4.9.1.1 California Hydrogen Highway Network162 The CaH2Net was initiated in April of 2004 to support and catalyze a rapid transition to a clean, hydrogen transportation economy in California. The goal was to assure that hydrogen fuelling stations were in place to meet the demand of fuel cell and other hydrogen vehicle technologies being placed on California’s roads. The CaH2Net was the first point of coordination between the California government, academia, and private industry stakeholders, establishing a shared vision in the form of a Blueprint describing the actions needed to create a hydrogen highway. The 2004 Blueprint identified four main principles that would contribute to the achievement of CaH2Net: 1. The CaH2Net should be developed in phases. 2. The State should co-fund the early phases of station deployment. 3. Hydrogen produced as a transportation fuel should be in line with the State’s environmental goals. 4. The State should establish policies that help create a favourable business climate for establishing hydrogen infrastructure. The Government of California has introduced following policies and funding programs to support hydrogen transportation initiatives:  Staff from the California Air Resources Board, California Energy Commission, and the Governor’s Office of Business and Economic Development, along with other state agencies, closely coordinate and work with other government and industry stakeholders to implement actions that support the development of a robust hydrogen and FCEV market.  Assembly Bill 8 (AB 8) provides a specific focus on development of the state’s hydrogen fuelling station network. AB 8 dedicates up to $20 million per year to support continued construction of at least 100 hydrogen fuel stations.  Executive Order B-16-201211 provides another strong policy driver for accelerating commercializing FCEVs and their associated hydrogen fuel station network.  The State of California is co-funding the initial network of hydrogen fuelling stations, in advance of vehicle launches, through the Energy Commission’s Alternative and Renewable Fuel and Vehicle Technology Program.

162 Air Resources Board. 2017a. California's Hydrogen Transportation Initiatives. California Environmental Protection Agency. October 27. Accessed November 2017. https://www.arb.ca.gov/msprog/zevprog/hydrogen/hydrogen.htm

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As of April 5, 2017, more than 1,600 FCEVs had active registrations with the California Department of Motor Vehicles. Drivers of these early market cars can fuel at 29 Open-Retail stations, nine of which are new fully retail fuelling stations completed in the last year alone. Revised projections, based on improved understanding of issues facing certain station developers’ project timelines, show 37 stations total are expected to be open by the end of the year (including retail and non-retail)163. According to Air Products and Chemicals, Inc. (Air Products), one of the hydrogen suppliers to California fuelling stations, the hydrogen supplied to the stations can be delivered to a site via truck or pipeline164. It can also be produced by natural gas reformation; biomass conversion; or electrolysis, including electrolysis driven by renewable energy sources, such as wind or solar. In response to the development of hydrogen infrastructure in California, the following announcements by the fuel cell and hydrogen industry were made in 2017, illustrating the expansion of fuel cell and hydrogen technology in several transportation applications:  Honda’s 2017 Clarity fuel cell sedan launched in early 2017, with an estimated range of 590 kilometres (km). Honda and GM also established the auto industry’s first joint venture (JV) to mass produce a HFC system for use in future products in both companies165. Hyundai and Genesis unveiled a concept design for FCEVs, and Kia announced plans for bringing a new FCEV model to the market in 2020166.  Air Products announced that it will now be able to offer hydrogen for FCEV fuelling at a price of less than $10 per kilogram (kg) at its five stations in California167. Air Products cites advances in fuelling station and hydrogen distribution technology, as well as projected FCEV deployments as enabling factors in reaching this pricing milestone.  A 30 percent reduction in storage tank cost could be achieved by using a new steel hydrogen storage tank product (developed by Nippon Steel and Sumitomo Metal Corporation) that promises a cost savings compared to conventional carbon fibre-wrapped tanks168.  United Parcel Service (UPS) announced that its first prototype fuel cell extended-range delivery van, developed in collaboration with the U.S. Department of Energy (DOE), will be deployed in the third quarter of 2017169.

163 Air Resources Board. 2017b. 2017 Annual Evaluation of Fuel Cell Electric Vehicle Deployment and Hydrogen Fuel Station Network Development. California Environmental Protection Agency. August. Accessed November 2017. https://www.arb.ca.gov/msprog/zevprog/ab8/ab8_report_2017.pdf 164Air Products and Chemicals, Inc. (Air Products). 2017. “Air Products’ California Fueling Stations Offering Hydrogen Below $10 Per Kilogram.” News Release. Lehigh Valley, Pa. March 6. Accessed November 2017. http://www.airproducts.com/Company/news- center/2017/03/0306-air-products-california-fueling-stations-offering-hydrogen-below-$10-per-kilogram.aspx 165 Abuelsamid, Sam. 2017. “GM Teams Up With Honda To Manufacture Fuel Cells Near Detroit. Autos/#UnderTheHood.” Forbes. January 30. Accessed November 2017. https://www.forbes.com/sites/samabuelsamid/2017/01/30/gm-and-honda-form-joint-venture-to- manufacture-fuel-cells-near-detroit/#2d388c438a93 166 Greimel, Hans. 2017. "Kia fuel cell vehicle to arrive in 3 years Hyundai brand to launch technology first." Automotive News. April 3. Accessed November 2017. http://www.autonews.com/article/20170403/OEM04/304039933/kia-fuel-cell-vehicle-to-arrive-in-3-years 167 Air Products and Chemicals, Inc. (Air Products). 2017. “Air Products’ California Fueling Stations Offering Hydrogen Below $10 Per Kilogram.” News Release. Lehigh Valley, Pa. March 6. Accessed November 2017. http://www.airproducts.com/Company/news- center/2017/03/0306-air-products-california-fueling-stations-offering-hydrogen-below-$10-per-kilogram.aspx 168 The Asahi Shimbun Company. 2017. "Cost of hydrogen tanks cut by 30 percent for stations for fuel-cell vehicles." Asia & Japan Watch. March 12. Accessed November 2017. http://www.asahi.com/ajw/articles/AJ201703120003.html

169 https://www.pressroom.ups.com/pressroom/ContentDetailsViewer.page?ConceptType=PressReleases&id=1493730807330-217

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 Toyota unveiled a proof-of-concept demonstration for a fuel cell truck-and-trailer combo powered by two Mirai fuel cell stacks with a range of 320 km170.  Truck manufacturer Kenworth also announced the development of a truck prototype for use in Southern California ports, integrating Ballard fuel cell stacks171.  Nikola Motor Company (Nikola), a new truck manufacturing company, unveiled its Class 8 over- the-road semi-truck with a range of up to 1,900 km. Nikola’s offering is also unique in that commercial leases will include hydrogen fuel, provided by a network of nationwide stations the company is planning to develop172. 4.9.1.2 Germany According to a study that looked at the prospects of providing hydrogen as a fuel by 2050, hydrogen could cover up to 40 percent of the demand for energy in Germany’s transport sector by 2050173. Industry, science, and government have recognized the potential advantage of hydrogen and fuel cell technology for clean mobility, and are working on the market preparation of these technologies through strategic alliances. The National Organisation Hydrogen and Fuel Cell Technology (NOW) is responsible for the coordination and management of the National Innovation Programme for Hydrogen and Fuel Cell Technology (NIP) and the Electromobility Model Regions programme of the Federal Ministry of Transport and Digital Infrastructure (BMVI)174, as follows:  NOW’s primary task is to initiate and evaluate projects, and bundle them in an appropriate manner to benefit from potential synergies.  NOW also incorporate subjects, such as production technology, education and training, and public relations, to raise the public profile of these technologies and related products.  NOW is also commissioned by the BMVI to support the continued development of the Mobility and Fuel Strategy, as well as implement the EU Directive 2014/94/EU on the development of alternative fuels infrastructure (CPT). NOW is coordinating the development of 50 hydrogen refuelling stations within the scope of a carefully monitored process. To support the rapid roll-out of refuelling station infrastructure in metropolitan areas and along main transport roads, H2 Mobility (a JV founded by six industrial partners, Air Liquide, Daimler, Linde, OMV, Shell, and TOTAL in 2015175) will establish and operate the first 100 hydrogen refuelling stations by 2018 or 2019 unconditionally and irrespective of the number of vehicles using the stations. This will mean developing up to 10 stations in each of 6 major metropolitan areas in Germany (Hamburg, Berlin, Rhine-Ruhr, Frankfurt, Stuttgart, and Munich) and establishing hydrogen corridors along motorways. The second phase of the project will be aligned

170 Toyota. 2017. “Toyota Opens a Portal to the Future of Zero Emission Trucking.” News Releases. April 19. Accessed November 2017. http://corporatenews.pressroom.toyota.com/releases/toyota+zero+emission+heavyduty+trucking+concept.htm. 171 Kenworth. 2017. Kenworth Advances Low - Zero Emission Prototype Projects on T680 Day Cab Drayage Trucks for Southern California Ports. News Releases. May 2. Accessed November 2017. https://www.kenworth.com/news/news-releases/2017/may/advanced-prototype- projects/ 172 Nikola Motor Company. 2016. "Nikola One Truck Revealed Tonight @ 7:00 p.m. MST Class 8 zero-emission hydrogen-electric truck in production by 2020." News Releases. December 1. Accessed November 2017. https://nikolamotor.com/pdfs/December_1_Release.pdf

173 H2 Mobility. 2017a. H2-Stations. Accessed November 2017. http://h2-mobility.de/en/h2-stations/ 174 https://www.now-gmbh.de/en/about-now/aufgaben 175 H2 Mobility. 2017b. Missing Hydrogen Infrastructure. Accessed November 2017. http://h2-mobility.de/en/h2-mobility/

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H2 Mobility receives funding from BMVI within the framework of the NIP, as well as from the European Commission through the second phase of the FCHJU as part of the Hydrogen Mobility Europe Project, and the Trans-European Transport Network (TEN-T CEF) as part of the Connecting Hydrogen Refuelling Stations programme176. 4.9.1.3 South Korea177 The Korean Government has committed to building a national hydrogen infrastructure, pledging to have 100 fuelling stations in operation by 2020 and 230 stations by 2025. Korean stations are fully financed by the local and national governments, with local cities and regions owning and operating them. In June 2017, Nel ASA (Nel, a dedicated hydrogen company headquartered in Norway) entered into an agreement with Deokyang Co., Korea’s largest hydrogen supplier, to establish a JV for exclusive sale and marketing of Nel’s hydrogen fuelling stations in Korea. 4.9.1.4 Plan for Hydrogen Economy in Japan and South Australia Japan178 First articulated in a 2014 blueprint, the vehicle and infrastructure advances would position hydrogen at the centre of Japan’s everyday energy needs. The government envisions:  Small hydrogen plants at homes and businesses  A nationwide hydrogen distribution system  Big advances in deployment and scale that would dramatically reduce vehicle and fuel prices  The establishment of a carbon-free hydrogen manufacturing process If the government’s plans succeed, there will be 800,000 FCEVs on Japanese roads by 2030 (compared with just 1,700 today) along with a network of 900 filling stations to serve them. The government and industry are pushing together, with heavy subsidies flowing in support of corporate hydrogen projects, and businesses fully committed to seeing the government's vision through. One motivation for the collaboration is to raise Japan’s image as global clean-energy leaders ahead of the 2020 Summer Olympics in Tokyo. Another is the goal for energy independence in a country that depends on imports for nearly all of its oil. Hydrogen holds special promise for resource- poor Japan because it can be produced from a wide variety of sources, including natural gas, coal, biomass, solar or wind power, nuclear power, and hydro stations.

176 ibid. 177 Nel ASA (Nel). 2017. Nel ASA: Enters Korean hydrogen market through JV with Deokyang. June 30. Accessed November 2017. http://mb.cision.com/Main/115/2300162/695161.pdf 178 Greimel, Hans, and Naoto Okamura. 2017. "Japan dreams of a hydrogen society. As automakers join effort, will they lead the world or be left behind?" Automotive News. April 24. Accessed November 2017. http://www.autonews.com/article/20170424/OEM06/304249965/japan-dreams-of-a-hydrogen-society

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South Australia179 On September 8, 2017, the South Australian Government announced a hydrogen roadmap for South Australia. The government’s vision is to accelerate South Australia’s transition to a clean, safe, and sustainable producer, consumer, and exporter of hydrogen. The government highlighted the following actions that will be taken to support the hydrogen economy:  Support early investment in hydrogen infrastructure, including co-investment in a demonstration project for hydrogen production and use under the $150 million Renewable Technology Fund; create demand for hydrogen through government leadership; incentivize investment in hydrogen infrastructure; and provide up-to-date information on the potential for hydrogen technology projects.  Promote and enhance the attractiveness of head office location, equipment distribution, and servicing and manufacturing in South Australia, including using the $200 million Future Jobs Fund to target job creation in the emerging hydrogen sector, and encouraging automotive industry diversification along the supply chain.  Deepen relationships with key trading partners, particularly with Asia-Pacific trading partners.  Unlock hydrogen innovation, including support for commercialization of home-grown technologies, facilitation of research and industry partnerships, and continued encouragement in developing clean technology and renewable energy expertise.  Create a strong regulatory framework for hydrogen production, storage, and use through providing a fair, predictable, and trustworthy regulatory framework. 4.9.1.5 Conclusion The hydrogen economy is envisioned as a truly sustainable energy system that, if the hydrogen is produced from zero-emission energy sources, has the potential advantage of producing no harmful emissions. A hydrogen supply chain is the cornerstone of any jurisdiction’s efforts to build a hydrogen economy. Additionally, in all cases studied, government funding and policy has been essential to the development of a hydrogen economy. As other jurisdictions take steps to advance the use of hydrogen for transportation and industrial uses, there is a real opportunity for Ontario to contribute to leading global innovation in the development of the hydrogen supply chain and hydrogen-powered applications. To date, the focus of international governments has been hydrogen applications related to passenger cars and other on-road vehicles, but an opportunity exists for larger transportation applications. If Ontario chooses Hydrail as the technology for the GO RER network, significant demand for the hydrogen supply chain would be created immediately, unlike in other jurisdictions where demand is expected to follow the supply of infrastructure. This, in addition to existing Canadian expertise in hydrogen technology, could transform Ontario into a centre for hydrogen technology innovation globally.

179 Government of South Australia. 2017. A Hydrogen Roadmap for South Australia. Accessed November 2017. https://service.sa.gov.au/cdn/ourenergyplan/assets/hydrogen-roadmap-8-sept-2017.pdf

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4.9.2 Overview of Hydrogen Related Businesses Depending on the procurement approach that is adopted it is likely that a combination of an industrial process contractor and a rail vehicle manufacturer will be responsible for designing and building the Hydrail System. The design and supply of Hydrail’s subsystems and components would be undertaken by specialist businesses located in Ontario, Canada and throughout the world. As part of the feasibility study the team spoke with and received information from a broad section of these businesses to understand their current capabilities and their expectations of where their industry is headed. All the businesses expressed a strong interest in being part of the Hydrail Program and confirmed their capabilities and capacities to meet our potential requirements. The table below contains a list of businesses that have capabilities in the following areas:  Supply and distribution of hydrogen;  Supply of tanks for the storage of liquid and gaseous hydrogen;  Supply of refuelling systems;  Supply of electrolyzers and fuel cells;  Supply of batteries;  Testing and systems integration services. Some of the businesses are multi-national in size and provide services in Canada. Other businesses are based in Canada (highlighted below in Table 4-49). These are all smaller in size, although businesses such as Hydrogenics and Ballard have a global portfolio of completed and current projects. However, for these Ontario and Canadian based companies to benefit from the implementation of the Hydrail System there would be the need for them to expand their current production capacities. We believe that this is achievable given that there will be design and development phase of the program that will last several years, however it is an area that we intend to investigate in more detail during the next phase of the study.

TABLE 4-49 LIST OF ORGANIZATIONS IN THE HYDROGEN BUSINESS Organization HQ location Main Focus of the Business in Relation to Hydrogen Air Liquide Paris, France Production and distribution of gaseous assets (argon, oxygen, nitrogen, helium and hydrogen) to large industries and healthcare sectors Air Products Allentown, Pennsylvania, US Supply of LNG process technology and equipment; atmospheric and process gases and related equipment to manufacturing markets (including refining and petrochemical, metals, electronics, and food and beverage) AKASOL Darmstadt, Germany Battery manufacturing Bae Systems - HybriDrive London, UK Hybrid electric power and propulsion transit solutions Ballard Burnaby, BC Fuel cell power solutions for transit, automotive, rail, infrastructure and defence sectors Change Energy Services Oakville, ON End-to-end compressed gas fuelling solutions

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TABLE 4-49 LIST OF ORGANIZATIONS IN THE HYDROGEN BUSINESS Organization HQ location Main Focus of the Business in Relation to Hydrogen Chart Industries Garfield Heights, Ohio, US Design and manufacturing of highly engineered cryogenic equipment Clean Fuel Systems Brampton, ON Hydrogen systems integration Electrovaya Mississauga, ON Development and manufacture of portable lithium-ion battery power solutions for the automotive, power grid, medical and mobile device sectors Enbridge Gas Toronto, ON Natural Gas Distribution General Motors Detroit, Michigan, US Design, manufacturing, market and distribution of flexible fuel cell electric platforms with autonomous capabilities for the automotive and military industries Hexagon Composites Aalesund, Norway Supply of composite pressure cylinders and systems for gas applications Honda Tokyo, Japan Design, manufacturing, market and distribution of flexible fuel cell electric platforms for the automotive industry HTEC Vancouver, BC Build and operation of renewable electrolysis and industrial by-product streams facilities for hydrogen production Hydrogen In Motion Vancouver, BC Mobile hydrogen storage tanks for the automotive industry Hydrogenics Mississauga, ON Industrial and commercial hydrogen generation, fuel cells and energy storage solutions Hyundai Seoul, South Korea Design, manufacturing, market and distribution of flexible fuel cell electric platforms for the automotive industry ITM South Yorkshire, UK Integrated hydrogen solutions manufacturing Linde Munich, Germany Production, storage and distribution solutions, as well as dispenser manufacturing, fuelling stations and infrastructure for hydrogen fleet applications NATECH Jean-sur-Richelieu, QC High-performance battery and charger solutions NEL Oslo, Norway Hydrogen delivering solutions to produce, store and distribute hydrogen from renewable energy Next Hydrogen Mississauga, ON Water electrolysis Powertech Labs Surrey, BC Testing and research of utility generation, transmission and distribution power systems Toyota Toyota, Japan Design, manufacturing, market and distribution of flexible fuel cell electric platforms for the automotive industry Tugliq Energy Montreal, QC Alternative energy infrastructure (wind, LNG and hydrogen) for Northern communities

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4.9.3 Hydrogen Fuel Cell Rail Vehicle Market Maturity and Trajectory The maturity of HFC-powered rail vehicles has moved from chatter and speculation to become a serious contender to wayside electrification and diesel power. Conversations about HFC rail vehicles are also starting to shift away from lack of ready resources of hydrogen, performance and range anxiety to project analysis and studies to deploy HFC locomotives in an effective manner. Germany, for example, has started to invest in a hydrogen generation plant and hydrogen distribution networks since 2002. The German government identified hydrogen and hydrogen-fuel-cell technology as essential to the future of mobility and energy supply. In 2002, it established the Clean Energy Partnership as a joint venture between government and industry to test the suitability of hydrogen as a fuel. Germany, like Ontario, has an energy mix that favours green energy. Surplus energy is continually used to generate hydrogen. In response to favourable market environments like Germany, all over the world, major rail vehicle manufacturers have made significant investments in HFC technology. Alstom’s Coradia iLint is the most well-known example of a rail vehicle that uses HFC technology. The Coradia iLint, successfully completed its test run on its own track in Salzgitter, Lower Saxony, Germany. Alstom plans passenger test runs in early 2018. Several German states have signed letters of intent to buy the trains once Alstom puts them into production which is expected to be in 2019. East Japan Railway (JR) demonstrated the world’s first hydrogen hybrid commuter train to the public in 2006. JR’s New Energy Train (NE Train) has two 65-kw PEM fuel cells and can travel up to 60 mph for approximately 60 miles. The NE Train uses regenerative braking, common to hybrid cars, to recharge the battery pack. In addition, the NE Train consumes 20 percent less fuel than traditional trains. The NE Train was designed to travel to more remote regions of Japan that do not have overhead power cables to replace both electric trains and diesel locomotives.180 More recently, Siemens and Ballard have partnered together to develop a fuel cell version of the Siemens’ Mireo EMU. Ballard has also engaged with CCRC Tangshan to develop a hydrogen power version of a LRV. Trials began on a dedicated test track in October 2017.181 BNSF Railway and Vehicle Projects converted a GG20B locomotive to an experimental testbed, for the use of HFCs. The new locomotive was designated HH20B. The locomotive was publicly demonstrated for the first time on June 29, 2009, at Topeka, Kansas and was built initially for the CP, but was not delivered, due to the cancellation of the order. It was sold to BNSF in 2008, and shipped to the railroad's shops at Topeka, Kansas for conversion. The diesel generator set was removed, and the fuel cell power unit was installed in its place. Hydrogen storage is in a set of tanks installed in a heavily vented enclosure on top of the locomotive's long hood, above the batteries.182 Sifang Co., a subsidiary of China South Rail Corporation (CSR) successfully presented the world's first hydrogen-powered tramcar at an assembly facility in Qingdao. With over 60 seats and the ability to carry up to 380 passengers, the tram can be refilled with hydrogen in only three minutes and can run distances of up to 100 kilometers at a maximum speed of 70 kilometers per hour.183 184.

180 http://www.hydrogencarsnow.com/index.php/Hydrail/jr-east-demonstrates-worlds-first-commuter-hydrogen-train/ 181 http://www.railjournal.com/index.php/rolling-stock/siemens-and-ballard-to-develop-fuel-cell-train.html 182 http://www.trainweb.org/gensets/owners/bnsf1.html

183 http://en.yibada.com/articles/21142/20150321/china-worlds-first-hydrogen-fueled-tram.htm# 184 https://www.bloomberg.com/news/articles/2015-03-25/china-s-hydrogen-powered-future-starts-in-trams-not-cars

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4.10 Commercial This section seeks to identify options and a recommended approach to commercial structures and procurement processes to support Hydrail deployment on the GO network. This entails an assessment of the possible contractual arrangements for the following factors:  Purchase of rolling stock  Supply, generation, and transportation of hydrogen  Fuelling of trains  O&M of trains and train storage facilities  O&M of hydrogen generation and storage infrastructure Consideration is given to appropriate risk transfer mechanisms and the effective bundling of services. The section also contemplates the most effective procurement methods for the aforementioned services, with a view to achieving the best value, as well as the impact on the existing plans for procurement through RER Package 3. 4.10.1 Current RER Procurement Strategy and Impact of Hydrail Delivering on RER plans will involve the procurement of services related to the operations and maintenance of trains, services along the railway corridor (on-corridor), and services outside of the corridor (off-corridor). On-corridor works are primarily related to the installation of fixed infrastructure, such as communications-based train control, signalling, radio and data communications, and track upgrades, as well as maintenance of all elements. On-corridor works will also include the electrification of the GO network, requiring the installation of overhead catenaries to allow for trains to be powered. The associated capital costs are significant, including costs related to, inter alia, the relocation of utilities, the acquisition of property access rights/property acquisition, environmental assessments and bridge upgrades. The maintenance of the overhead catenary system will also cause further costs to be incurred over the concession period. Off-corridor works are primarily related to upgrades to existing stations and parking infrastructure, as well as the development of new stations and parking infrastructure. As currently envisioned, off-corridor works will be procured through separate contracts. Given the complexity and inter-relation of train operations and on-corridor services, it has been recommended that, in keeping with international best practices, train operation services and on-corridor works and services will be delivered through a single, integrated design, build, finance, operate, maintain (DBFOM) contract. While Metrolinx will continue to be responsible for customer facing activities, the on-corridor concessionaire (OnCo) will be responsible for the operation and maintenance of trains. OnCo will procure electric train sets and undertake the necessary on-corridor infrastructure works. At a defined date following award of the DBFOM contract, OnCo will also take over the operation and maintenance of existing trains, and on a go-forward basis, be responsible for the operation and maintenance of trains along with on-corridor infrastructure. Within the context of the current RER procurement plans, Hydrail can create both opportunities and risks/costs. Some of the key features of the existing procurement plans and the related impact of Hydrail are discussed in the following sections.

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4.10.1.1 On-Corridor Works Procurement Based on current electrification plans, the capital cost of the on-corridor infrastructure works is estimated at $7B, with a further CAPEX on rolling stock of $2B. Some parts of the work are being procured and constructed in advance of the commencement of the DBFOM contract. The size of the capital infrastructure in the proposed DBFOM contract will therefore likely constrain the field of bidders that will be able to meet the requirements of Metrolinx and finance providers to secure construction performance for a project of this magnitude. Further to this, over the proposed 30-year concession period, the DBFOM contract will require flexibility to accommodate changes in service levels and the service plan. A decision to pursue Hydrail could eliminate the requirement to install overhead catenary wires, resulting in a significant reduction in the overall on-corridor project scope and cost. This cost saving may be partially offset by the additional costs of establishing a hydrogen supply chain. However, the hydrogen supply chain capital costs would lie outside the RER DBFOM contract, and the reduction in the DBFOM capital costs could potentially allow for a greater number of bidders who could meet the necessary construction security requirements, thereby providing an opportunity for increased competition. Though the scope of the DBFOM contract would be reduced with the pursuit of Hydrail, Hydrail and the use of HFC technology presents enhanced technology risk relative to overhead electrification. While this risk may, at least partially, be passed on to the ProjectCo, proponents will assign a value to the risk they are assuming and ultimately incorporate this value in their bids. Further to this, there are likely to be less companies interested in taking on the level of technology risk presented, which could limit the field of bidders. System Service Specifications The RER system service specifications will define, inter alia, capacity, service frequency and average journey times. Service levels will be set based on Metrolinx’s projections over the concession period. The service specifications will provide the framework in which OnCo proponents will decide the infrastructure and rolling stock that will allow for a maximum service level to be achieved. It is expected that the project agreement will allow Metrolinx to purchase capacity and train service levels based on its projections, on which basis OnCo will procure and commission the required rolling stock and infrastructure. It is expected that OnCo will design infrastructure to meet the projected 2044 service requirements. The associated capital costs would be paid over the concession period through availability payments. Service levels could be varied at Metrolinx’ discretion with appropriate notice to OnCo. Capacity levels could be increased with appropriate notice. This will allow Metrolinx to determine the pace at which infrastructure will be expanded/upgraded and allow flexibility in train service levels over the concession period. The pursuit of Hydrail will likely create greater flexibility for Metrolinx to increase the system’s capacity level, as less changes would be required to fixed infrastructure. In this case, increasing the system’s ability to supply increased power to trains is expected to be a simpler and less expensive process than it would be in the case of overhead electrification. Procurement Timeline A Request for Qualifications (RFQ) for the DBFOM contract is expected to be issued in Spring 2018, and the Request for Proposals (RFP) issued later that year. Financial close is anticipated in 2019, after which OnCo is expected to begin on-corridor infrastructure works and the procurement of rolling

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT stock. OnCo is expected to assume current operations at a defined date after 2021 and to provide the upgraded RER service delivery to various corridors commencing in 2024. The current procurement timeline is somewhat aggressive, noting significant works to be completed in the installation of overhead catenaries. These works will also involve significant third party and public interface, given the need to obtain environmental approvals, relocate utilities, upgrade bridges, remove trees and obtain property rights. Additionally, there are potentially significant scheduling risks associated with the installation of overhead catenary wires. While Hydrail will eliminate the need for the infrastructure works associated with the installation of overhead catenary wires, additional scheduling risks are presented because hydrogen fuel powered train sets that meet RER requirements do not currently exist. Based on initial market consultations, it is however, anticipated that train sets could be designed and delivered within the planned timeline for RER implementation. 4.10.1.2 Off Corridor Works The procurement of off-corridor works is ongoing and includes platform construction or upgrades as well as the acquisition of land to house new stations or facilitate the expansion of, or changes to, existing stations. The procurement of off corridor works will be impacted by any changes to train configuration. Such a change could be required if, for example, it is determined that, due to the need for on-board fuel storage, there is the need for longer trains, or for the trains’ floors to be at a different height than is currently the case. In such an event, passenger platforms would have to be adjusted to facilitate safe boarding of passengers. It is however noted that Metrolinx may have a preference to adjust platform heights anyway to provide for level boarding. A decision to pursue Hydrail would also necessitate the construction of hydrogen generation, storage, transportation and dispensing infrastructure. This will require additional land acquisition and the design and construction of these facilities. Consideration will also have to be given to operation and maintenance of these facilities, noting that fuelling infrastructure is not contemplated under current RER procurement plans. It is noted, as discussed in Section 4.9, that hydrogen generation and storage facilities at the scale or functionality level required to support the GO network do not currently exist. 4.10.1.3 Rail Vehicle Maintenance Facilities Rail vehicle maintenance facilities allow for the mechanical maintenance, body repair, the day-to-day cleaning of trains and operational services such as fuelling and sanding. There is currently one train maintenance facility, the Willowbrook facility, located in Etobicoke, ON. A second facility, the East Rail Maintenance Facility, is currently under construction as a design, build, finance, maintain (DBFM) project, with substantial completion scheduled for December 2017. OnCo is expected to take over use of the maintenance facilities in 2021. The maintenance requirements of hydrogen fuelled vehicles will differ from those of electric or diesel vehicles. A key consideration will be that maintenance facilities for hydrogen fuelled vehicles should allow for greater levels of ventilation. Other health and safety concerns would have to be addressed, as appropriate and required. Notwithstanding this, it is anticipated that these concerns can be addressed without any significant structural changes being required.

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4.10.2 Jurisdictional Scan The following sections provides an overview of recent examples of the deployment of vehicle fleets fuelled alternative fuels. The examples offer some insight into the commercial considerations of other jurisdictions as they sought to diversify their fuel mix, in the provision of public transportation services. Though, with one the exception, these are not examples of hydrogen powered rail, they provide examples of approaches to the introduction of alternative fuels in public transportation fleets. The risk profiles associated with these initiatives are therefore, relevant as we examine the commercial considerations for Hydrail in Ontario. 4.10.2.1 Hydrail Deployment – The German Example The German government has taken steps to electrify parts of its rail network using HFC technology. As at March 2017, the German states of Lower Saxony, North Rhine-Westphalia, Baden-Württemberg and the Hessian transport association ‘Rhein-Main-Verkehrsverbund’185 had signed letters of intent to purchase a total of 60 trains from Alstom, an integrated rail transport company. While there are limited public details of the procurement activities to date, in the study conducted to assess the feasibility of the use of HFC to propel trains in Germany, recommendations were made for the procurement of services. The study highlighted the provision of hydrogen infrastructure as a new service component, which would not have had to be considered with more conventional railway service models. Two options, integrated or separate procurement of train services and hydrogen infrastructure, were considered. The models were analyzed within the context of appropriate distribution of risks between the commissioning authority and the transport and infrastructure companies. Acknowledging that there was no precedent on which to base an assessment, the models considered were intended to illustrate the spectrum of conceivable procurement possibilities. Option 1 - Separate Procurement of Train Services and Hydrogen Infrastructure Two of the models considered for separate procurement of train services and hydrogen infrastructure are outlined below. Conventional Vehicle Procurement In this model, the provision, maintenance and repair of vehicles as well as the transport service is undertaken by the rail transport company. The supply of hydrogen is procured separately. The advantages of the model are that transport services are provided by one integrated company and there is the generation of service and value chain synergies through the rail transport company, while the commissioning body profits from market knowledge of the rail transport company. A key disadvantage is that there are high market entry hurdles, which could preclude small and medium- sized rail transport companies. Given the higher capital costs, and to facilitate competition, the study suggested that the commissioning authority consider providing various forms of support to the rail transportation company, including a reauthorization guarantee, a redeployment guarantee (vehicles), the retention of interest rate risk, a capital service guarantee, a residual value guarantee, or some combination of these.

185 “Alstom’s hydrogen train Corodia iLint first successful run at 80 Km/h.” Alstom.com. N.p., 14 Mar. 2017. Web. 01 Oct. 2017.

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Commissioning Authority Vehicle Pool In this model, the commissioning authority would procure vehicles, separately from the rail transport company procurement, and maintain them in a pool. Vehicles would then be made available to the rail transport company, as scheduled, over the concession period. The key advantage of this model is that the commissioning authority stands to benefit from economies of scale by ordering trains in larger quantities. The rail transport company also benefits as the commissioning authority would maintain residual value risk. The key disadvantage is that the commissioning authority maintains the risks associated with the vehicles, including technology risk, which is more significant in the case of HFC-powered trains. Further to this, the commissioning authority does not benefit from the experience of the rail transport company in the procurement of the trains. Option 2 - Integrated procurement of train services and hydrogen infrastructure Two of the models considered for integrated procurement of train services and hydrogen infrastructure are outlined below.

The LNVG H2 Model This model is based on the planned procurement of services for Hydrail by Landesnahverkehrgesellschaft Niedersachsen mbH (LNVG), the state local public transport company of Lower Saxony. In this model, the provision of trains and hydrogen infrastructure were bundled into one procurement package, while rail transport services were intended to be procured separately. The provision of trains and hydrogen infrastructure along with the related services by one entity reduces the risks to which the commissioning authority is exposed. Additionally, as in the Commissioning Authority Vehicle Pool, the commissioning authority is likely to benefit from economies of scale in procuring trains in larger quantities. The significant disadvantages are however, the reduction in the competitive field, loss of the benefit of the experience of the rail transport company in the vehicle procurement process, and the retention of certain risks associated with the vehicle procurement, such as technology risk.

The H2 Service Model

The H2 Service Model builds on the LNVG H2 model by bundling rail transport operations with the provision of trains and hydrogen infrastructure, along with the related services. The benefits of the LNVG H2 model are enhanced. In particular, the commissioning authority can transfer all risks related to the vehicle procurement to a fully integrated services provider. However, given the scale of the procurement package and the inherent risks, the primary disadvantage is that there is likely to be an even greater reduction in the competitive field. 4.10.2.2 Hydrogen in Canadian Transit Fleets In 2010, BC Transit launched what was at the time the world’s largest fleet of HFC-powered buses186. The project was jointly funded by the federal government and the Province of British Columbia. The fleet of 20 fuel cell electric buses were integrated into regular service operations in Whistler, British Columbia. The buses were supplied by Winnipeg bus manufacturer New Flyer, while the fuel cells and batteries were provided by Ballard. Air Liquide was contracted to supply hydrogen and the company was initially expected to construct a 1,000-kg hydrogen fuelling station in Whistler. The station never materialized and instead, hydrogen was trucked from Quebec, leading to higher costs and

186 Canadian Hydrogen and Fuel Cell Association (CHFCA).- http://www.chfca.ca/say-h2i/cars-and-buses/bc-transit-fuel-cell-bus-fleet

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT significantly higher GHG emissions than anticipated. In 2014, BC Transit issued a request for offers to purchase the vehicles, which were reported to have cost three times more in maintenance and fuel costs than the diesel buses they had replaced.187 4.10.2.3 The Hydrogen Highway – California188 189 190 191 The CaH2Net is an initiative of the State of California in the USA to promote the use of hydrogen as a fuel in transportation, thereby diversifying energy sources while ensuring environmental and economic benefits to the state. An economic report prepared as part of the development of the state’s hydrogen blueprint concluded that the early risks related to the development of hydrogen fueled vehicles and products must be shared between government and the private sector. Through a bill passed in 2005, funding was provided to co-fund up to three demonstration hydrogen fuelling stations, purchase or lease up to two hydrogen internal combustion engine shuttle buses and lease a fleet of up to twelve hydrogen fuelled vehicles. A Request for Proposal (RFP) was issued to solicit competitive bids from qualified teams or individuals including energy suppliers, original equipment manufacturers, utilities, contractors and other parties interested in further developing and demonstrating hydrogen refuelling infrastructure in California. The fuelling stations which were to be open to the public, were intended to demonstrate and test the viability of the use of hydrogen as a transportation fuel. The state committed to funding 50 percent of the cost of each station, with the state’s contribution to be used in part, to help offset and provide incentives for the increased capital outlay and engineering required to meet the emissions targets and new renewable energy requirement. The stations, once completed, were required to be in operation for a minimum of two years, after which all capital equipment paid for by state funds would become the property of the operator/successful bidder, leaving the state with no financial or intellectual interest in the station. An RFP was issued to solicit viable businesses with a proven track record and a demonstrated ability to provide proven hydrogen fuelled vehicles. The vehicles, which were to be leased for a 24-month period, were intended to demonstrate the viability of hydrogen as a fuel in transportation and of hydrogen vehicles. The vehicles would be used in areas where they could facilitate public demonstration, data collection and reporting requirements. The areas would have to be near hydrogen fuelling stations and allow for sufficient travelling miles to be accumulated. The lessor would be required to supply a new vehicle, facilitate driver training, provide educational materials and safety information, and maintain the vehicles. The state continues to fund new hydrogen fuelling stations. To date, the state has co-funded 62 hydrogen fuelling stations across California. Through Assembly Bill No. 8, up to $20M per year is dedicated to support continued construction of at least 100 hydrogen fuel stations.

187 Vancouver Sun - http://www.vancouversun.com/technology/Transit+hydrogen+fleet+sale/10441639/story.html 188 “California Hydrogen Initiatives.” ARB.ca.gov. California Air Resources Board. 15 Jul. 2016. Web. 19 Oct. 2017. 189 “California Hydrogen Blueprint Plan – Volume 2.” ARB.ca.gov. California Environmental Protection Agency. May 2005.PDF. 19 Oct. 2017. 190 “RFP #05-609.” ARB.ca.gov. Air Resources Board. n.d. PDF. 19 Oct. 2017. 191 “RFP #05-610.” ARB.ca.gov. Air Resources Board. n.d. PDF. 19 Oct. 2017.

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4.10.2.4 Alternative Fuels in Canadian Transit/Municipal Fleets CNG Bus Fuelling, Storage and Maintenance Facility192 In 2016, the City of Calgary signed a fixed price agreement with Plenary Infrastructure Calgary LP (Plenary) to design, build, finance and maintain the Stoney CNG Transit Facility for Calgary Transit. The facility will include CNG fuelling infrastructure and allow for the storage and maintenance of both CNG and diesel fuelled vehicles, as both types of vehicles will be operated in the transit company’s fleet as it transitions from diesel. The estimated capital cost was $174M. Plenary Infrastructure Calgary LP is a consortium of Plenary Group (Canada) Ltd. and PCL Investments Canada Inc. Other team members include PCL Construction Management Inc. and Johnson Controls Canada LP. The facility will be the first CNG transit bus storage and maintenance garage delivered through a P3 model in North America and the indoor CNG fuelling facility will be largest of its kind in North America193. Plenary will receive a substantial completion payment and, over a 30-year concession period, will receive monthly payments as they provide facilities maintenance and rehabilitation services. The City’s staff will continue to service and maintain the buses. 4.10.2.5 Alternative Fuels in North American Transit/Municipal Fleets CNG Fuelling Infrastructure and Bus Maintenance Facility Upgrade – Orlando, FL194 The Central Florida Regional Transportation Authority (LYNX) entered in to a P3 with Nopetro, a leading natural gas fuelling infrastructure provider, to provide CNG fuelling infrastructure and convert LYNX’ existing bus fleet to CNG. The agreement also provided for necessary upgrades to the existing LYNX maintenance facility. The facility was intended to accommodate public access. The CNG fuelling infrastructure was entirely privately funded and the agreement included a revenue sharing component. The fuelling facility was opened in April 2016. CNG Fuelling Infrastructure – St. Johns County, FL195 St. Johns County entered a P3 arrangement with Nopetro to provide a CNG fuelling station within the St. Johns County Public Works facility. The county provided the land on which to construct the facility, with no charge to Nopetro for 2-3 years, while Nopetro invested US$3MM to construct the facility. The county committed to purchase 100,000 gallons of fuel in the first year of operations. Under a separate agreement, the county invested US$987,000to convert its fleet of 100 vehicles to CNG. The fuelling facility opened in August 2016. CNG Buses and Fuelling Infrastructure and Bus Maintenance Facility Upgrade – Miami Dade, FL196 Miami Dade County contracted Trillium CNG to design, build, finance, operate and maintain the CNG facilities, upgrade maintenance facilities, and procure 300 CNG buses for the county’s public

192 The City of Calgary - http://www.calgary.ca/Transportation/TI/Pages/Transit-projects/Stoney-CNG-Transit-Bus-Garage.aspx 193 Plenary Group - https://plenarygroup.com/projects/north-america/stoney-cng-bus-storage-and-transit-facility 194 Nopetro - http://nopetro.com/nopetro-opens-nations-largest-publicprivate-compressed-natural-gas-fueling-facility/ 195 Nopetro - http://nopetro.com/st-johns-county-jumps-into-natural-gas-economy-as-first-cng-facility-opens/ 196 Trillium CNG - https://www.loves.com/en/news/2017/february/trillium-contract-for-cng-locations-miami-dade-dot

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT transportation system. Trillium will operate the facilities under a 10 year operations and maintenance agreement. The contract is valued at over US$330MM197 and the project will involve the leasing of land from the county and the construction of two fuelling stations. Both stations will have separate fuelling facilities that are open to the public, with a revenue sharing agreement between Trillium CNG and the county. For the public access stations, there is a minimum annual guarantee payment, which will cover the rent due to the county. Both stations are scheduled to be opened in 2018. It is expected that Trillium CNG will provide the fuel for both stations, while New Flyer of America Inc. will supply the buses. http://www.miamidade.gov/procurement/library/RFP/00096/RFP-00096-Trillium.pdf CNG Fuelling Infrastructure and Bus Maintenance Facility Upgrade – PA198 The Pennsylvania Department of Transportation (PennDOT) entered into a 20-year P3 with Trillium CNG under which Trillium CNG will design, build, finance, operate and maintain 29 compressed natural gas, or CNG, facilities in Pennsylvania. The agreement also includes CNG-related updates to existing transit maintenance and storage facilities. Seven of the fuelling station will be open the public, with a revenue sharing agreement between PennDOT and Trillium CNG. Under the agreement PennDOT will supply of procure the supply of CNG for the stations, including that required for the commercial operations. The stations were to be completed over 2017-2021 as at 27-Jul-17, 6 stations had been completed. 4.10.2.6 Electrified Train Operations in Canada Eglinton Crosstown - Light Rail - Ontario199,200 Metrolinx and Infrastructure Ontario entered into a contract valued at $5.3B (2010$) with Crosslinx Transit Solutions (Crosslinx), to design, build, finance and maintain the Eglinton Crosstown light rail transit (LRT) system, which is to be operated by the Toronto Transit Commission. Crosslinx is a consortium comprising ACS, Aecon, Ellis Don, and SNC Lavalin. Under the project agreement, Crosslinx will maintain the LRT system for 30 years, during which they will be responsible for the maintenance of vehicles and the lifecycle repair and renewal of building and system components. Bombardier will supply the light rail vehicles for the project. Energy consumption risk is shared, with price risk being retained by Metrolinx and volume risk being borne by the consortium. The operating agreement creates an incentive for the operator to minimize both total energy consumption and peak energy demand through a gain-share / pain-share mechanism.

197 Fleets and Fuels - http://www.fleetsandfuels.com/fuels/cng/2017/02/loves-trillium-cng-fuelbuses-for-miami/ 198 Pennsylvania Department of Transportation -http://www.penndot.gov/ProjectAndPrograms/p3forpa/Documents/CNG percent20Transit percent20Facilities/Executed percent20Public percent20Private percent20Partnership percent20Agreement.pdf ; http://www.penndot.gov/ProjectAndPrograms/p3forpa/Documents/CNG percent20Transit percent20Facilities/Implementation percent20Timeline percent20V4.pdf 199 Ontario Ministry of Transportation - https://news.ontario.ca/mto/en/2015/11/crosslinx-transit-solutions-signs-contract-to-deliver- eglinton-crosstown-by-2021.html 200 Metrolinx - https://news.ontario.ca/mto/en/2015/11/crosslinx-transit-solutions-signs-contract-to-deliver-eglinton-crosstown-by- 2021.html

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Edmonton Light Rail Transit System - Alberta201 The City of Edmonton entered into a P3 agreement with TransEd Partners General Partnership (TransEd) to design, build, finance, operate and maintain a new LRT project. The concession period is 30 years. TransEd is a consortium comprising Fengate Capital Management Ltd., EllisDon Capital Inc., Bechtel Development Co., and Bombardier Transportation Inc. Through the project agreement, TransEd will supply the light rail vehicles. The energy consumption risk is transferred to TransEd, while the energy price risk is retained by the City. The project is availability-based, with the city setting and collecting fares. The Confederation Line – Light Rail – Ontario202 The City of Ottawa entered into a P3 with Rideau Transit group to design, build, finance and maintain the Confederation Line. The concession period is 30 years. The Rideau Transit consortium comprises SNC-Lavalin, ACS Infrastructure and EllisDon. The project agreement creates an incentive for the operator to minimize energy consumption through a gain-share / pain-share mechanism. 4.10.3 Considerations for structuring commercial arrangements As noted in Section 4.9, the hydrogen industry, including the generation, storage, transportation and dispensing of hydrogen is well developed globally; however, the hydrogen dispensing technology is not at the stage to allow for the dispensing of hydrogen at the rate required to support Hydrail on the GO network. Further to this, while the industry is well developed at large scale globally and in western Canada, there is no significant activity in Ontario. Building this industry to support Hydrail in Ontario is a critical factor to ensuring successful implementation. In respect of rolling stock, though there have been some advances in the development of hydrogen powered rail vehicles, there are currently no known cases of the development of hydrogen powered rail vehicles that can meet the performance specifications of RER. There are many considerations along with options for proposed actions that require further exploration if the Hydrail concept is pursued further by Metrolinx. The entire supply chain or system model components that will be explored in this section are shown in the CNL figure (Figure 4-48).

FIGURE 4-48 HYDRAIL SYSTEM MODEL COMPONENTS

201 PPP Canada - http://www.p3canada.ca/en/about-p3s/project-map/edmonton-light-rail-transit-system/ 202 City of Ottawa - http://www.ligneconfederationline.ca/page/2/

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The following sections below provide commercial considerations on each of the components that must be explored further to make Hydrail a functional option for Metrolinx. For the purposes of this Report, the components have been broken down and examined in two groupings: 1. Grid Interface, Hydrogen Production, Storage, Distribution and Dispensing 2. Hydrail Rolling Stock, Operations and Maintenance of Rolling Stock and Related Maintenance Facilities These groupings were chosen due to the natural business lines between fuel supply chain and vehicle supply and operations. One consortium of various firms may be able to manage the entire supply chain in Figure 4-48, plus operations and maintenance of rolling stock; however, this will depend on the procurement model chosen and market acceptability. This will be explored in the Procurement Factors section below. A further separation of the supply chain, for the purposes of this Report, was believed to lead to both inefficiencies and additional interface risks for Metrolinx, which together negatively impact the availability of the fuel for operational needs and therefore, the success of the program. 4.10.4 Grid Interface, Hydrogen Production, Storage, Distribution and Dispensing Ensuring that Hydrail will work and provide desired benefits is the first step to seeing progress; however, for hydrogen-fueled vehicles to be successful long term on the Go network there needs to be a strong and clear commercial foundation in place. Also, this option must be competitive and ultimately comparable to the electrification option, while also delivering on long-term, desired environmental benefits. Hydrogen-powered public transit has been explained as technologically feasible by various entities that contributed to development of this Report, but it is still unclear if the long-term costs of supplying these non-conventional services on a very large scale are comparable to the cost of more proven technologies for public transit elsewhere in Canada. The reality is that this uncertainty adds an incremental level of risk not commonly seen on electrified rail or diesel locomotives for a programming perspective (that is, will levels of service be met over time?). These realities do not mean that Hydrail is not possible. Rather, it is extremely important to fully understand various business factors and develop a comprehensive strategy to ensure successful advancement of the initiative. The following section provides details on the various business factors identified and discussed during the development of this Report. 4.10.4.1 Business Factors While hydrogen generation, storage and transportation facilities exists in Canada, they largely support industrial activities, with little application in transportation. One notable example of the application of hydrogen as a fuel in Ontario is CTC’s recent pilot project to generate hydrogen on site and use the fuel to power Brampton Distribution Centre forklifts. Due to the success of this pilot project, this technology has also been incorporated into the new Bolton Distribution Centre in the Town of Caledon. This application is however at a much smaller scale than required to support Hydrail. There is more hydrogen-powered transportation expertise worldwide (for example, Germany and Japan), which Ontario may learn from; however, capacity and expertise for the scale envisioned to support the GO network is not believed to be present in these markets either at this time. Aside from

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TABLE 4-50 BUSINESS FACTORS TO BE CONSIDERED IN DEPLOYING THE HYDRAIL SYSTEM FOR GO Category Factor for Consideration Potential Steps/Options Grid Interface The availability of electricity to generate A good understanding of capacity and volume hydrogen fuel must be a key consideration risk for electricity along the corridor is required, for a potential Hydrail solution on the GO including appropriate mitigation measures. This network. may be completed in a separate study that Electricity usage may fluctuate over time, should include: but is expected to remain quite constant  Finding ideal locations for generation facilities once processes are developed and the level (large and/or localized) where there is either of service is determined. existing capacity or opportunity for new capacity to be added to the grid at a low cost.  Consider bulk power purchasing agreements once a range of volume need is known, particularly if government is to assume risk for the volume of electricity required to produce hydrogen fuel.  Consider passing the risk of electricity volume to a private partner, either through an AFP contract or other contracting arrangement o On previous AFP contracts, electricity volume risk has been shared with the private partner Hydrogen Production Electricity cost is important due to the high Explore opportunities and reasonability to use need for power to complete the electrolysis off-peak electricity for Hydrail with specific process and Metrolinx should further assess consideration given to cost per megawatt and the opportunities and risk of electricity costs meeting service level needs (i.e., will off-peak changing over time electricity save substantial money, and what is the long-term potential of this electricity staying relatively inexpensive). Currently, optimistic estimates for electricity are $46 per MWh, but may range as high as $76 per MWh. It is unlikely that a private partner would take pricing risk for electricity (unless increased costs could be at least partially passed on to government), regardless of the procurement model; however, market sounding on this point could be undertaken. Hydrogen Production A constant supply of water for the hydrolysis Discussions with local municipal organizations is process is also necessary and although this essential to accurately forecast availability and is not anticipated to be a major concern for cost of water for the electrolysis process. supply and pricing, analysis is still required to ensure risks are understood and the technical solution is achievable within any related constraints (i.e., if local water supply is available)

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TABLE 4-50 BUSINESS FACTORS TO BE CONSIDERED IN DEPLOYING THE HYDRAIL SYSTEM FOR GO Category Factor for Consideration Potential Steps/Options Hydrogen Production, There are two main options for hydrogen Metrolinx needs to determine the best approach Storage, Distribution production (with potential for a hybrid from cost, risk, strategy and various other & Refuelling model) that each come with opportunities perspectives. Depending on the scale of Hydrail and challenges: relative to the entire GO network (e.g., pilot 1. Centralized production – A large facility program, only part of the network or the entire or facilities capable of efficiently network), the generation and distribution options producing hydrogen in large quantities may become clearer. o The facility can be located where CTC recognized benefits of an on-site hydrogen electricity, water and land is generation solution, which has now been available – reducing short-term replicated at a second warehouse location. This costs being said, the scale of their operation is estimated at approximately <1 percent of the o Requires transport of fuel via truck scale contemplated on the GO network (i.e., 200 or pipeline to where the fuel is to 300 kg of hydrogen per day vs. 40 tonnes per needed for refilling stations day). o Interface risk exists, as the fuel is Understanding opportunities for land acquisition required to be moved longer for both options is critical, particularly for the distances decentralized option where production facilities o Pipelines are expensive and may would be located near existing, busier stations not be able to be built within the along the corridor. From a business perspective, existing right of way or through it will be difficult to transfer land acquisition risk well-developed commercial and to the private partner for this government residential communities initiative, especially since government has o Trucking the fuel will at least expropriation rights that can be triggered if partially offset GHG emission required. reductions (assuming trucks use fossil fuels), which is a desired outcome of RER 2. Decentralized production – Many localized generation facilities that are located at or near the sites that require the fuel o There is limited need for distribution of the fuel, reducing cost and GHGs or transport o Land acquisition is required at sites near where fuelling of trains is required o Inefficiencies of production and staffing may result Hydrogen Production, Technical labour supply is anticipated to be There will be a need to educate technicians to Storage, Distribution limited outside of research facilities and operate and maintain the hydrogen fuel supply & Refuelling smaller industrial competencies. There may chain and also HFC-powered rail vehicles. This be some transferrable knowledge from may not be a risk that can be adequately other related industries (e.g., industrial transferred to a private partner; however, market natural gas) that will lessen the impact of this sounding may provide more details. This needs potential issue; however, that is yet to be to be explored further depending on the determined. feasibility and related scale of Hydrail on the GO network. Some colleges in Canada and the United States have existing programs or have started to plan for future programming to train employees for this industry. One example is Stark College in

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TABLE 4-50 BUSINESS FACTORS TO BE CONSIDERED IN DEPLOYING THE HYDRAIL SYSTEM FOR GO Category Factor for Consideration Potential Steps/Options Ohio, which has a program for Fuel Cell Technology. Further, colleges in Canada have recently facilitated forums or meetings related to hydrogen fuel technology, including Canadore College in North Bay, Ontario and Red River College in Manitoba. Partnerships and funding (public and private) to support skills training in this industry is crucial to ensure the skills and abilities exist for an initiative as large as Hydrail on the GO network. General - Regulatory The CHIC falls under the TSSA; however, Engagement with Transport Canada is believed this regulatory framework does not seem to to be underway with CNL providing advice on accommodate hydrogen powered trains on safety and other related factors. Currently, there a large scale. Without an adequate is no regulatory framework in place for hydrogen regulatory framework, it will be difficult for powered trains and the timeline is unclear. A plan companies to assume risk on this type of of action, including for required consultations venture. and engagement with involved agencies, should be developed and actioned. There have been licences granted in Canada for hydrogen powered equipment, including forklifts and vehicles (e.g., buses). This will provide a baseline for future work in the area.

4.10.5 Hydrail Rolling Stock, Operations and Maintenance of Rolling Stock and Related Maintenance Facilities The Ontario Ministry of Transportation and Metrolinx recently issued an RFP to allow various rail vehicle manufacturers to develop designs and determine the overall impacts on the addition of fuel cell technology on BL trains. The focus of this procurement was on how this relatively new technology may impact the overall RER business case, service delivery and ultimately the performance of the GO network. Responses have recently been received and are being evaluated by government officials. The results of this process, which are still unknown, are expected to lead into the planning of an integrated DBFOM procurement should Hydrail be considered a potential technical solution for the RER Strategy. Although the results of this process may add clarity to what options exist for rolling stock, there are other commercial considerations as well. These are explored further below. 4.10.5.1 Business Factors Hydrogen powered vehicles are a relatively new concept compared to other traditional methods, primarily fossil-fuel (that is, diesel) public transportation vehicles. Though on a relatively small scale, there are many examples of the application in buses, particularly in Europe and in California. Also, current plans are being implemented in Japan for over 100 Toyota hydrogen powered buses for the Tokyo 2020 Olympic Games. There are no examples of hydrogen fuelled trains in commercial operation. Aside from the current state of business for hydrogen powered vehicles, there are other specific considerations that should be addressed as Hydrail is contemplated for the GO network (Table 4-51).

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TABLE 4-51 COMMERCIAL FACTORS TO BE CONSIDERED IN DEPLOYING THE HYDRAIL SYSTEM FOR GO Category Factor for Consideration Potential Steps/Options Hydrogen Vehicle Lack of competition for the manufacturing, Hydrail pilot projects could be possible on operations and maintenance of hydrogen sections of the GO network that are more difficult powered trains could leave government in a for overhead electrification (should electrification difficult business position. Depending on the be chosen as the preferred option). Ideally, this structure of related procurement processes, would occur once existing diesel locomotives are this could lead to limited competition and price nearing the end of their useful lives. This might or quality risk for government. include Milton and Richmond Hill sections due to Based on research completed to date, Alstom physical restrictions and potential environmental is the only company advanced in the and stakeholder concerns. manufacturing of HFC passenger trains, This approach would allow for a phased-in although Siemens recently announced a train approach to hydrogen powered rail and also lead development agreement with fuel cell to a more organic development of the related company, Ballard. Further, Alstom’s current industry in Canada on a larger scale than currently hydrogen powered rolling stock is in the pilot exists. project stage, has not been proven for wide- If Hydrail is chosen as either a potential or scale use and is a different train set compared preferred model for the entire GO network, some to requirements planned to date for Metrolinx. or all of these risks may be able to be transferred It is also important to note that European rail to a private partner(s), depending on the manufacturers Alstom and Siemens have procurement model chosen. A market sounding announced intentions to merge operations. It is would be required to determine what may be unclear what this means for the hydrogen acceptable to industry. Also, depending on the powered train program in Germany. results of the recent RFP issued, which asked rail vehicle manufacturers to develop Hydrail options, these risks may be mitigated. Timing of Useful life still exists on existing diesel Opportunity to phase-in a new approach (e.g., Hydrogen Vehicle locomotives in the GO fleet and it is planned electrification or Hydrail) may be considered so Introduction that any private partner would assume that priority segments are completed in early responsibility for these locomotives phases and lesser priorities are completed in the future. This will allow for lessons learned to be applied on future phases. The structuring of procurement may still allow for one consortium to complete all phases or for phases to be split up to allow for increased competitive tension in the market. Hydrogen Vehicle To ensure that Metrolinx operations are not Control for on-site hydrogen storage, dispensing Operations interrupted, a constant, uninterrupted fuel and refuelling may be best placed at the operator supply is required by the vehicle operator. It is level; however, there would still not be a unlikely that there will be another hydrogen guarantee that interface risk won’t occur. A plan fuel provider outside of this initiative that will be for redundancy in the case that hydrogen fuel not able to provide the large scale of fuel required be available should be developed. daily to ensure no loss of service. Alternatively, full integration of the supply chain identified in Figure 4-48 could be accomplished with one large procurement with the risk of fuel not being available being fully passed to the private partner. Hydrogen Vehicle The East Rail and Eglinton Crosstown A report detailing the impact of Hydrail on existing Maintenance Maintenance Facilities are examples of recent maintenance facilities should be completed. This capital investments made by Metrolinx to would include an understanding of costs and improve maintenance of rolling stock. These timelines associated with improvements (e.g., facilities have not been designed to mechanical, electrical, safety). accommodate Hydrail and the cost and impact This may not be an issue; however, to date there is on timeline of retrofits, if required, is unknown. a lack of clarity on this potential issue.

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4.10.6 Procurement Factors Innovation through procurement is essential for governments to obtain the best value for money on major initiatives like the RER strategy. Allowing the private sector to determine the best solution for meeting certain program and service level needs, within performance specifications to be developed by government, has proven to produce positive results across various infrastructure types and jurisdictions. Applying these same principles to rolling stock and associated infrastructure throughout the GO network is an option that may be pursued, depending on the results of discussions with industry. If Project Specific Output Specifications (PSOS) are drafted to allow Hydrail approaches to meet government’s needs, rather than specify that certain technologies must or must not be used, there will be room for innovative and cost-effective approaches that capture the purchase, operations, maintenance of rolling stock and infrastructure (for example, supply chain for hydrogen fuel or electrification of the network) required to make the system function long term. The alternative would be to specify the type of technology or particular approach to infrastructure that must be used either for the entire GO network or for particular sections. This can be done through a traditional (that is, Design-Bid-Build) procurement model or also by tightening performance specifications in such a way that only one solution may be technically compliant during evaluation. Although this approach may be required in certain unique circumstances (for example, requirement to meet legislation or stakeholder concerns), industry will be constrained in their approaches to innovation the more constraints that are put on the procurement parameters. This typically has the impact of increased timeline and cost, which ultimately reduces value for money long term. 4.10.6.1 Procurement and Project Objectives Major capital initiatives like the RER strategy have focussed on determining what desired outcomes are for a successful procurement. The intent is to choose the right tools that will ultimately offer a highly effective solution to meeting both short and long-term needs of the organization. The first step of this process is typically to develop project and procurement objectives, which provide a high-level indication of considerations and constraints specific to the Project, which would be used to assess the strategic alignment of different procurement options available to Metrolinx. The information below provides an example of what these objectives might look like for RER. Project Objectives  The desired public transit service objectives  To comply with affordability criteria  Financial and planning flexibility regarding long term strategic objectives  The nature of the assets and services to be delivered (longevity and quality)  Value engineering or innovation provided by the private sector  Local contractor involvement in the Project and the extent to which training and education opportunities are provided

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Procurement Objectives  The degree of participation in the procurement process and the competition generated  The fairness and transparency of the process  The extent to which Metrolinx receives schedule and cost certainty from the private sector contractors  The ability to optimally allocate risk between the government and private sector  Ability to ensure no loss of service and to limit risk to government  Compliance with existing trade agreements (for example, Agreement on Internal Trade) It is important to note that these have not been discussed with Metrolinx to date and are only provided to illustrate how organizational objectives may impact the procurement model that is ultimately chosen. Analysis is typically undertaken, beginning with a workshop setting, to narrow down options to those that will delivered on desired outcomes. 4.10.6.2 Procurement options – Hydrail focus There are numerous procurement options that may be considered for delivery of a Hydrail solution, should this be chosen as a possible technical solution to meet Metrolinx’s long-term needs. These options should be developed based on the size of the project scope, timeline considerations, optimization of risk transfer, value for money and other objectives. Various funding mechanisms have been explored in other similar studies (for example, CaH2Net), including market-based concepts, subsidization of industry often through tax breaks and/or grants to allow for development, sole-source mandates for a period of time until an industry is mature and other reinforcing approaches like financial or non-financial awards and incentives. Although these models may be successful in some instances, they are not believed to be applicable for what Metrolinx is working towards accomplishing on the GO network. There may be potential however for certain funding mechanisms to be used on smaller scope items connected to the initiative (for example, licences to sell hydrogen to other customers beyond Metrolinx). Although many options exist, for the purposes of this report, there are two potential procurement approaches that are explored further as potential options to meet known objectives. This analysis is not intended to be comprehensive in nature, as limited information still exists; however, it does provide an indication of potential solutions for incorporating Hydrail into the RER strategy. Further discussion and analysis will be required depending on the outcome of this Report. Option 1: Broadened Output Specifications on Integrated DBFOM to Accommodate Hydrail It may not be good practice to choose between overhead electrification and Hydrail at this point in the project, but instead allow the market some flexibility to determine best value within certain government established parameters (that is, PSOS during procurement). Recent decisions have been made to undertake an Integrated DBFOM procurement, rather than separating the infrastructure from the rolling stock and operator. This is an opportunity for Hydrail, since the infrastructure required for the supply chain is integral to the operations of the rolling stock. Unless the Government of Ontario plans to use Hydrail as a catalyst to build the hydrogen transportation industry to support a larger Province-wide strategy, the procurement can be structured to allow for various technical solutions within defined PSOS. These specifications (and proposal evaluation criteria) can focus on maximum GHG emissions, noise, land available, level of service requirements (for example, trip time, passenger volume), safety requirements, as well as price, and many other important factors.

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As the indicative design is being developed in advance of release of an RFP, considerations would need to be given to Hydrail to ensure the PSOS are broad enough to allow for related innovations. Examples include ensuring land availability for certain elements of the hydrogen production, developing an appropriate regulatory framework for Hydrail and assisting with skilled workforce development through universities and colleges. Private sector consortiums bidding on the RFP would then determine the best approaches, including both Hydrail and electrification, to ensure technical compliance. A Project affordability ceiling (based on the indicative design) would be another key constraint outside of technical compliance. Metrolinx would need to be more open to innovations under this approach and the market would likely need to be accepting of more risk associated with technology, operations, land acquisition, stakeholder consultation and other items. This is because Metrolinx cannot assume direct risk that a private sector innovation (beyond what is proposed in the indicative design) will not function as planned to provide the intended service or outcomes that are acceptable to stakeholders and the general public. A potential variation of this option would be to have two or more separate DBFOM procurements; however, due to the potential for interface risk and the decision to proceed with an integrated DBFOM procurement, this option was not explored further in the Report. Ultimately, this option provides flexibility for the market to determine the most appropriate solution instead of government dictating that overhead electrification or Hydrail is the desired solution. The following are potential pros and cons of this approach (Table 4-52).

TABLE 4-52 BROADENING OUTPUT SPECIFICATIONS ON INTEGRATED DBFOM TO ACCOMMODATE HYDRAIL Pros Cons Decisions and associated risks on overhead electrification If Hydrail was considered a catalyst for further hydrogen vs. Hydrail are shared with the private sector, rather than industry development, this may not occur assumed 100 percent by government Innovation often leads to lower costs and increased value More time may be required to broaden PSOS to allow for for money for the same quality of service envisioned Hydrail, which could delay the planned schedule Stakeholder consultation risk is shared with a private sector Some planning (e.g., preparation of stations for overhead partner, as the technology decision is not the sole electrification, land acquisition assumptions) may become responsibility of government redundant depending on the solution chosen A broadened PSOS may lead to increased industry There is increased pressure on government to come up competition (that is, not only companies that have with PSOS that are broad enough to allow for innovation experience with overhead electrification)

It should be noted that even if Hydrail is chosen as the preferred technology option on which the indicative design would be based upon, a broadened PSOS may still be a good procurement strategy. Innovations outside of existing technical or business assumptions may be possible with a more flexible approach to procurement of an initiative that is as complicated and unprecedented as the RER strategy. Option 2: Hydrail Pilot Projects Other jurisdictions, specifically Germany, have decided to run pilot projects for new technologies such as hydrogen powered rail projects to determine feasibility for broader application in the future. This approach not only allows for adequate testing of a new and mostly unproven technology (that is, for rail transportation) prior to a larger program-wide implementation, but also allows for time to develop public acceptability of the technology and overall industry maturity.

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From a procurement standpoint, there several ways that pilot projects can be approached and implemented. Commitments recently made by the Ontario government have discounted the possibility of undertaking Hydrail pilot projects prior to proceeding with the electrification of the entire GO network. Therefore, Hydrail pilot projects may be best suited for sections of the GO network that are not easily electrified for various reasons, including flooding and stakeholder concerns. These are sections where diesel locomotives may be the natural alternative if overhead electrification is not possible or desirable. This approach, although workable from a level of service perspective, is not believed to be aligned to the Province’s low emissions goals. Hydrail pilot projects may be procured separately or as a package under various models using more traditional approaches where full design is completed or various AFP approaches. These procurement options have not been analyzed in detail for this Report; however, risk transfer with the private delivery partner may be better suited for a packaged DBFOM, rather than more traditional design, bid, build (DBB). These potential pilot projects may also be considered for integration with the larger integrated DBFOM strategy, but further analysis and discussion with industry and stakeholders would be required before this approach was considered. Since Project Co. is expected to take over responsibility of the existing Metrolinx fleet currently servicing the GO network, this approach may provide the best opportunity for innovation and incorporation of leading asset management practices (that is, using the diesel locomotives until replacement is required for asset management reasons). The following are potential pros and cons of this approach (Table 4-53).

TABLE 4-53 RUNNING PILOT PROJECTS FOR HYDRAIL Pros Cons Testing of the Hydrail related technology would occur prior There is likely interface risk between the Hydrail pilot to a program-wide implementation sometime in the future, projects and the rest of the GO network if overhead which would lessen the risk profile for government electrification is implemented on the rest of the network This approach may lead to a separation of sections throughout the GO network, which could lead to inefficiencies; however, this may be at least partially mitigated with good planning. A more natural development of the hydrogen fuel industry The scale of pilot projects is smaller and economies of scale will occur if the pilot project is successful may be impacted on the rest of the network, which may lead to higher cost delivery of services Government reduces its risk of the technology not working Innovations, cost savings and other positive features of and service being significantly interrupted to a confined Hydrail, should they be realized, will be limited to smaller section(s) of the network sections of the network The timing of pilot projects can be aligned to the Duplication of operators, maintenance providers and diminishing useful life of existing diesel locomotives, which infrastructure to support the entire network will likely result, may be proven to be a good value for taxpayer money (i.e., as different approaches will be required for Hydrail and not abandoning good quality diesel locomotives overhead electrification immediately) 4.10.7 Timeline Considerations Many of the outstanding commercial and procurement related aspects of Hydrail will take considerable amounts of time to address. Although many of these issues can be addressed in parallel, others require a more sequential approach. For instance, a review and purchase of land to accommodate hydrogen generation and storage is only possible once it is known where capacity exists for both electricity on the grid and water for the hydrolysis process.

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The procurement model and approach to proceed with Hydrail (pilot project on a portion of the network vs. application for the entire network), should it be deemed to be a good option, is also likely to impact the timeline of the RER strategy. The current plan for procurement of overhead electrification of the GO network is:  RFQ – spring 2018 to summer 2018  RFP – summer 2018 to summer 2019  Financial close late 2019 It is unclear if preparations for accommodating Hydrail within this currently planned timeline could be achieved, especially since various Hydrail implementation/procurement options may still be chosen. If Hydrail is pursued as separate pilot projects, it more likely that the existing critical path for overhead electrification could be achieved. In any case, if Hydrail is to be considered alongside or shortly following the existing overhead electrification timeline, the following actions should be started in early 2018:  Further clarification and development of the regulatory framework to support Hydrail and the related supply chain  Continue working with industry (that is, train manufacturers) to better understand what is possible to facilitate the inclusion of hydrogen powered rolling stock  Continue engaging with potential investors to better understand their willingness to accept risk on new technology on a major infrastructure project  Develop and implement a labour force strategy to ensure adequate supply of qualified labour to support Hydrail once it is in operation  Broadening of PSOS to allow for Hydrail (only if it is being allowable as an innovation through the planned integrated DBFOM procurement)  Develop a supply and demand strategy for electricity and water to support hydrogen production along or near the GO network corridor  Develop a land acquisition study and follow up implementation strategy to accommodate Hydrail (that is, bidders are unlikely to want to take the risk of acquiring land to accommodate the hydrogen production and distribution supply chain when government has expropriation rights)  Ensure that the Hydrail option is aligned (or at least not prevented from being achieved) with existing Package 1 and 2 design work. This should be done in advance of procurements through design requirements, similar to how installation of four Overhead Catenary System (OCS) concrete bases are being installed during station developments to accommodate overhead electrification of the Go network. At some point in early 2018, a go/no-go decision needs to be made on how or if Hydrail will be approached to meet Metrolinx RER Strategy goals. This date may be further into the future if separate pilot projects are being pursued; however, a decision still needs to be made in early 2018 as to what the scope of these pilot projects will be because there will be implications for the larger integrated DBFOM procurement.

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4.11 Transition Plan This section describes how the Hydrail System could become operational within the RER program. 4.11.1 Strategy to Introduce Hydrail A DBFOM RFQ and RFP process is presently being prepared for the RER program. The timeline for this process is still under review but is presently planned to be launched at the end of Q1-2018, with the RFP issuance in Q4-2018. Given the significance of this procurement, a contract award for this scope of work is not anticipated until the end of Q1-2020. The DBFOM contract is expected to cover the infrastructure modifications required for RER independently of the rolling stock technology, for example track, signalling, communications, stations. It will also give the opportunity to the different proponents to propose their preferred electrification solution; either wired, with the installation of an overhead catenary system, or a wireless alternative that could be addressed by Hydrail. As a result, the DBFOM procurement process is likely to be a strong influencing factor in the decision concerning whether Hydrail is implemented. Considering the scenario that Hydrail is the preferred electrification solution of the successful DBFOM proponent, there are several important factors for consideration in determining how Hydrail could be brought into service: 1. Decisions about where and how the hydrogen is to be produced, and how the HFC-powered rail vehicles will be refuelled will influence how long it will take to design and implement the required static infrastructure:  As part of the scope of work that is described in the Next Steps section we are recommending the further study is undertaken in these areas;  However, the milestones of first vehicle testing, production vehicle testing and commissioning, and initial service on one corridor could all be achieved using temporary facilities and short- term supply contracts. 2. The design of a HFC-powered locomotive or EMU will also depend on decisions and progress relating to the specification and design of the:  RER train service plan  Rail vehicle performance requirements and technical specifications  Signalling system  Train protection system  Rail vehicle stabling and maintenance facilities. All of these factors are outside the scope of the Hydrail program to assess at this stage in terms of how they will be undertaken and what milestone dates are achievable. 3. The decision as to which corridor to use to introduce an initial Hydrail service will depend on:  The RER infrastructure upgrade plan and actual progress made against this plan  Which corridor represents the optimum choice in terms of benefits delivery from the enhanced performance of electric trains.

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As with point 2, these factors are outside the scope of the Hydrail program to assess at this stage in terms of how they will be undertaken and what milestone dates are achievable. In relation to considering the Hydrail System’s ability to transition into service, it is significant to understand that a Hydrail service can be commenced incrementally once individual rail vehicles are commissioned and approved for service, and a basic supporting fuelling and maintenance infrastructure is in place. This compares to the overhead catenary system where a whole corridor would need to be completed and commissioned before revenue services could commence. 4.11.2 Timescales On the assumption that the first set of factors do not impose a constraint on the ability of Hydrail to be implemented at its preferred pace, and that we can take advantage of an incremental start of service, the proposed transition plan for Hydrail is outlined in the schedule below (Figure 4-49).

FIGURE 4-49 TRANSITION PLAN SCHEDULE

Some of the key assumptions underlying this proposed transition plan are that:  Key learnings from the HFC Bi-level EMU Concept Design and the HFC Locomotive Concept Design projects are incorporated into the DBFOM process;  Key learnings from the HFC locomotive detailed design, build and test project are incorporated into the Hydrail Rail Vehicle Design project and the build and testing of the first Hydrail vehicles;  Key learnings from the Hydrail subsystems concept designs (as defined in the “Recommended Next Steps” section) are incorporated into the Hydrail Infrastructure Design and Build project;

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 Other activities particularly those relating to the definition of how railway operations would be managed for a Hydrail System and how regulatory approval would be achieved are successfully completed. On this basis, it is considered feasible that the production of HFC rail vehicles could commence in 2023 and that an initial service on one corridor could commence in mid-2024. If this initial service is then incrementally enhanced over the course of a year it would then be possible to introduce HFC rail vehicles into service on the other corridors in accordance with the rate at which they are manufactured.

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4.12 Risks and Opportunities The successful implementation of the Hydrail System would require significant and unique challenges to be managed. Successfully managing such a large program would be inherently ‘risky’ due to the uncertainty and complexity associated with integrating hydrogen technologies in a heavy rail context on such a large scale. The objective of this section is to explore and evaluate those sources of uncertainty and complexity which could have an impact on the cost, timing, performance and other benefits of the Hydrail System and to compare these as an alternative to the planned electrification solution. Our assessment classifies risks in three categories of when the risk might occur:  System Design Risks – these are risks that could occur during the Hydrail System design phase,  System Implementation Risks – these are risks that could occur during the Hydrail System implementation phase, and  System Operation Risks – these are risks that could occur during the operation of the Hydrail System. The risks have been evaluated in terms of:  Our assessment of the probability of the risk occurring based on our current level of knowledge of the risk – this is represented as high, medium, or low,  The significance of the impact that the risk would have on achieving the objectives of the Hydrail Program if this risk occurs – this is represented as high, medium, or low. The risk assessment also contains our recommendations of the actions that could be taken to mitigate the probability and/or significance of the risk. At the same time, we have also identified opportunities for Hydrail to generate benefits in addition to those assessed in the feasibility study. These Hydrail opportunities are described at the end of the section. 4.12.1 System Design Risks 4.12.1.1 Regulatory Framework for HFC Rail Vehicles There might be significant concerns raised by Transport Canada relating to the crashworthiness, refuelling, maintenance, and degraded service of the hybrid HFC subsystem on rail vehicle.  Type: System Design.  Probability of risk occurring: Medium - There are many codes and standards that will apply to the design of the fuel cell subsystems. There is also the experience of gaining regulatory approval of the Alstom train in Germany. However, there is a lack of experience of the use of hydrogen within Transport Canada and there is the potential for the process of obtaining safety case approval to be protracted.  Significance: High – If this risk occurs it could add a significant amount of time to the planned milestones of commencing Hydrail train services.  Mitigation: Proactive engagement with Transport Canada to discuss and develop a comprehensive safety risk assessment through out all the development stages of Hydrail. Parallel

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engagement with TSSA and CSA to help demonstrate the existing certification for individual HFC system components.  Comparative assessment with Electrification: There is less risk to electrification, since electric locomotives and EMUs operate on many rail systems. The common risk that would apply to both Hydrail and Electrification is in the use of UIC compliant EMUs on GO, which has traditionally operated FRA compliant passenger and freight locomotives. 4.12.1.2 Model-related Risks The development of the Hydrail Operational Simulation Model required making assumptions about future operations and costs, in addition to assumptions about system operations and train performance. There is a risk that these assumptions could be significantly too optimistic, resulting in higher than expected operating costs, more developmental risk, or poorer performance than anticipated.  Type: System Design  Probability of risk occurring - Low  The development of the Hydrail Operational Simulation Model involved engagement with subject matter experts in the industry and research institutions and universities. In addition to this, the components being modelled exist as individual units and are highly scalable. Input and reviews from multiple parties will have reduced the risk of too optimistic assumptions.  Significance – Medium  While there is uncertainty around some of the assumptions, a thorough sensitivity analysis around these assumptions has lowered the level of uncertainty. Additionally, contingency percentages are included in the operational simulation modelling estimates.  Mitigation: It is proposed to carry out further development work on the Operational Simulation Model as part of the “Recommmended Next Steps” activities defined in Section 6.  Comparative assessment with Electrification: There is a similar risk within the modelling that has been done for electrification in relation to the forecast capital and operating costs. However, this should be lower than for the Hydrail System because the scope is better defined and there will be fewer assumptions. 4.12.1.3 System Integration Complexity of the HFC Rail Vehicles There is a risk that the design period of the HFC rail vehicles is greater than planned due to unexpected complexities that emerge in integrating the hybrid HFC subsystem into the existing EMU and locomotive platforms.  Type: System Design  Probability of Risk Occurring – Medium The feasibility study report from Hydrogenics on the HFC locomotive has not identified any significant systems integration risks and we know from the Alstom Coradi iLint, the CRRC Gaoming project and other one-off rail vehicle projects that this is not an insurmountable problem. However, we also know that modern rail vehicles are complex machines where equipment needs to be installed in very confined spaces. Therefore, it would not be surprising if some system integration challenges are encountered during the design phase which require unplanned scope of work to resolve.

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 Significance – Medium If this risk occurs it could have a consequential impact in the start of the build phase and, therefore, on the start of revenue services. However, we would be confident that these types of issues could be resolved through focussed engineering effort which would not have a significant impact on the development, test and build durations of the HFC rail vehicles.  Mitigation: The current HFC Rail Vehicle Projects, within the Hydrail Program scope, are intended to be part of the process of mitigating this risk by investigating, at a conceptual level, how a hybrid HFC subsystem would be integrated into a locomotive and a bi-level EMU platforms. The outputs of this work are intended to inform the RER rail vehicle systems engineering strategy that will be adopted by the rail vehicle manufacturer.  Comparative assessment with Electrification: There is no significant risk to electrification, since electric locomotives and EMUs exist in the market and do not require any additional equipment to be integrated into them to meet the RER electrification requirements. 4.12.1.4 Operational Range of the HFC Rail Vehicles There is a risk that the HFC locomotive or the HFC EMU will need to be refueled with hydrogen within their daily operational hours to be able to operate the planned number of trips in the RER train service plan.  Type: System Design  Probability of Risk Occurring – Medium Assumptions have been made in the Operational Simulation model about the space that will be available on the rail vehicles for the storage of hydrogen. The HFC locomotive and HFC EMU concept design projects might identify that these assumptions are too optimistic and that the amount of hydrogen, in gas form, that can be carried should be reduced, which in turn will reduce the range that the rail vehicle can operate before refuelling.  Significance – Medium If this risk occurs it would have an impact on the operation of the Hydrail System as it would require refuelling of the rail vehicles to take place within the operating day. The impact of this on the proposed RER train service plan and fleet size is unclear; however, it would not be substantially different from the impact of the refuelling that takes place during the day for the current fleet of diesel locomotives.  Mitigation: It is planned to mitigate this risk by: a) setting the rail vehicle manufacturers, working on the concept designs, the objective of maximising the volume of compressed gas hydrogen that can be accommodated on their vehicles, without compromising functionality and safety b) optimising the train service patterns and associated duty cycles that a Hydrail rail service would operate to minimize the amount of hydrogen that would be needed for an all-day service without refuelling.  Comparative assessment with Electrification: There is no significant risk to electrification, since electric locomotives and EMUs do not carry their own fuel on-board and can draw as power as they need, when they need it, from the overhead catenary system.

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4.12.1.5 Performance of the HFC rail vehicles There is a risk that it might not be possible to design the HFC rail vehicles so that they can operate the proposed RER train service plan on each corridor.  Type: System Design  Probability of Risk Occurring – Medium The sizing of the components of the hybrid HFC subsystem for the HFC locomotive and the HFC EMU has been calculated to meet the acceleration and peak power demands needed to operate the RER train service plan. This sizing has been undertaken by CNL and has been corroborated independently by modelling from Hydrogenics as part of their HFC locomotive support services. However, HFC rail vehicles with the required performance characteristics have not been built before and therefore there could be unknown risks that emerge during the design phase that could reduce the forecast performance capability.  Significance – Medium If this risk occurs it is only likely to reduce the expected performance levels by a relatively small amount, which in turn should not significantly affect the BCR for the project.  Mitigation: It is planned to mitigate this risk by undertaking more detail calculations, during the next stage of the project, of the performance of the hybrid HFC subsystem based on a clearer definition of the required duty cycles for each corridor. We will also consider the opportunity (described below) of designing the hybrid HFC subsystem with a slightly reduced performance objective to determine the impact that this would have on system capital and operating cost compared to the resulting reduction in RER benefits.  Comparative assessment with Electrification: There is no significant risk to electrification, since the train service plan for RER has been designed to be achievable using currently available electric locomotives and BL EMUs. 4.12.1.6 Environmental Assessments The Hydrail System will require Environmental Assessments to be undertaken for the hydrogen production facilities. There is a risk that this process will take longer than planned, creating challenges in achieving the committed dates for RER service.  Type: System Design  Probability of Risk Occurring: Medium - The likelihood that this risk will occur is currently Medium as there has not yet been any engagement with the planning authorities.  Significance: Medium - If environmental compliance and approvals are not achieved by about 2022 it would have an impact on the commencement of construction of these facilities.  Mitigation: Proactive engagement will be required with the MOECC, local conservation authorities, and municipal and provincial governments to begin the Environmental Approval process.  Comparative Assessment with Electrification: Environmental assessments for the Electrification work is underway and engagement has already commenced with local authorities to meet RER dates. However, there could be objections raised from local residents to the network in relation to construction noise, vegetation removal and visual intrusion.

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4.12.1.7 Infrastructure Required for Hydrail The electrolyzer, storage and refuelling subsystems will need to be designed to allow for efficient operations of the Hydrail network. The detailed design of this infrastructure needs further investigation and there is a risk that a fundamental scope or process issue will be discovered during this work that will have a significant impact on the expected efficiency and cost of operation.  Type: System Design  Probability of Risk Occurring: Low - The Hydrail System uses standard off-the-shelf componentswhose performance characteristics are proven.  Significance: High - The impact of this risk is significant as it could have a significant impact on the functional and economic viability of Hydrail.  Mitigation: It is intended to mitigate this risk by undertaking concept designs of these subsystems as described in the “Recommended Next Steps” section.  Comparative Assessment with Electrification: This is a low risk for electrification. Overhead wires and signalling immunization will need to be installed. The risk is mitigated by the know-how that exists in the industry. 4.12.1.8 Technological Development of Hydrail Since a Hydrail System has not yet been implemented at the scale RER requires, there could be challenges related to the scaling of the HFC subsystems, and potential performance limitations due challenges in systems integration.  Type: System Design  Probability of Risk Occurring: Low - This is mainly a systems integration risk that will be approached through engineering design with major equipment manufacturers. The risk that scale effects could have a significant detrimental impact is low as the components are modular.  Significance: Medium - If system integration issues do occur, particularly with the rail vehicles and the refuelling facility it could delay the start of implementation or reduce the performance of the Hydrail System below expected levels.  Mitigation: The development of the concept designs and subsequent prototypes will allow a detailed analysis of the system integration and scalability. Engagement with major industry manufacturers and universities to test concepts in their testing facilities will help evolve the design to the requisite levels of performance and reliability.  Comparative Assessment with Electrification: There is a lower risk to electrification, since OCS equipment and electric rail vehicles use technology that have a high level of component development and systems integration. Locomotives and EMUs are certified and exist in the market.

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4.12.1.9 Private Sector Risk Assessment of Hydrail It is currently intended that the Hydrail System is included in the RER DBFOM procurement scope. Due to the unfamiliarity that many proponents will have with hydrogen and the Hydrail System they could consider it to contain a high level of risk, resulting in them applying a significant cost premium to it for the development, operation and maintenance of the system.  Type: System Design  Probability of Risk Occurring: Medium - The likelihood that this risk occurs will be driven by how the risk profile of Hydrail is seen to compare to that of Electrification, and how the risk transfer mechanisms are defined in the DBFOM contract.  Significance: High - There is a high level of significance related to this risk as it will be a fundamental driver as to whether the Hydrail System is preferred to Electrification.  Mitigation: It is intended to mitigate this risk by undertaking further development work on the definition and design of the Hydrail System across several areas, including: subsystems concept designs, hydrogen production locations, railway operations, capital and operating costs, transition plan, and codes and standards. The scope of this work is outlined in the Recommended Next Steps section.  Comparative Assessment with Electrification: Potential proponents might also see a high level of risk associated with Electrification in relation to the: capital cost of implementation, operating cost, and transfer of risks such as utilities diversions and operational disruption. 4.12.1.10 Implications to RER Scope of Work due to Hydrail There is a risk that the functional requirements of the Hydrail System might require significant additional infrastructure within the scope of work of RER.  Type: System Design  Probability of Risk Occurring: Low - The feasibility study has not identified areas of the operation of the Hydrail System that are likely to have a significant impact on the scope of the RER infrastructure. The area that this risk is most relevant to is the design of the stabling yards in relation to the: design of the refuelling storage and dispensing facilities, and design of station platforms for the operation of 12 carriage consists with 12 locomotives.  Significance: Medium - The objective of the refuelling system for Hydrail is to replicate the operational functionality of refuelling the current diesel fleet. However, the implications of refuelling a much larger fleet of trains than currently exists will make this process more complicated than at present.  Mitigation: A thorough study with Metrolinx Planning and Policy, and Fleet Operations will need to be conducted to better understand the RER service plan approach. Following this, a technical analysis will be conducted with Fleet Engineering to understand the impact of HFC locomotives and EMUs to achieve the RER level of service.  Comparative Assessment with Electrification: The scope of RER is currently being designed to meet the functional requirements of Electrification. The likelihood of additional infrastructure work needing to be undertaken within the scope of the Electrification program will relate to risks such as unexpected utilities diversions and existing infrastructure modifications.

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4.12.1.11 Impact on Hydrail Scope of Work due to RER There is a risk that the RER scope of work could have a negative impact on Hydrail.  Type: System Design  Probability of Risk Occurring: Medium - The definition of the RER scope of infrastructure and train services is still evolving and therefore it is likely that changes from the current definition will have an impact on Hydrail.  Significance: Medium - There may be constraints of the feasible locations for the hydrogen production and refuelling facilities. Additionally, train service patterns may affect the required performance characteristics and range of the HFC rail vehicles.  Mitigation: As part of the proposed “Recommended Next Steps” it will be important for the Hydrail team to continue to work closely with the RER Program team to understand evolutions in the RER infrastructure scope, fleet strategy and timetable.  Comparative Assessment with Electrification: There is no impact on electrification 4.12.1.12 New Emerging Technology by 2025 Technology developments in propulsion systems could create a feasible lower cost alternative to Hydrail. Continuing innovations in the rail industry could usurp the Hydrail option. As an example, battery-only trains are also being tested in various parts of the world. With the significant level of funding and research into battery technology from major automotive companies, a breakthrough in that sector is possible.  Type: System Design  Probability of Risk Occurring: Low - It has been suggested that battery-only trains could be a viable alternative to Hydrail. However, there are fundamental issues with the power to weight ratios of battery systems that mean they are unlikely to be an appropriate solution for a heavy demand commuter network like GO. In addition, the research improvements in battery technologies that are frequently publicized are unlikely to be commercially available within the time frames required by RER.  Significance: Low - Although battery only technology might become a viable propulsion system for rail vehicles in the future this is likely to be limited to light rail vehicles.  Mitigation: The Hydrail team will continue to monitor industry and technology trends to assess whether the likelihood of occurrence of this risk changes.  Comparative Assessment with Electrification: The same risk applies to electrification. Table 4-54 collates the risks identified above and orders them using a rough risk ranking score of Probability multiplied by Significance, based on High = 3, Medium = 2 and Low = 1. The risks that have score from 6 to 3 are of sufficient importance that their further investigation is included within the scope of activities outlined in the “Recommended Next Steps” section.

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TABLE 4-54 HYDRAIL SYSTEM DESIGN RISK MATRIX Risk Probability Significance Risk Score Regulatory Framework for HFC Rail Vehicles Medium High 6 Private Sector Risk Assessment of Hydrail Medium High 6 System Integration Complexity of the HFC Rail Vehicles Medium Medium 4 Operational Range of the HFC Rail Vehicles Medium Medium 4 Performance of the HFC Rail Vehicles Medium Medium 4 Environmental Assessments Medium Medium 4 Impact on Hydrail Scope of Work due to RER Medium Medium 4 Infrastructure Required for Hydrail Low High 3 Technological Development of Hydrail Low Medium 2 Model-related Risks Low Medium 2 Implications to RER Scope of Work due to Hydrail Low Medium 2 New Emerging Technology by 2025 Low Low 1

4.12.2 System Implementation Risks 4.12.2.1 Public Perception of Hydrogen Misconceptions by the public about the safety risk ofhydrogen might cause commuters and local neighbourhoods to resist the implementation of Hydrail.  Type: System Implementation  Probability of Risk Occurring: Medium – This is based on current perceptions of hydrogen. However, a focused public relations effort should be able to mitigate this risk.  Significance: Medium – Negative perceptions of safety risks could adversely impact on the location of hydrogen production and storage facilites and GO ridership levels.  Mitigation: Engage with Metrolinx public relations and communications teams to overcome these prejudices, using a comprehensive public engagement strategy.  Comparative Assessment with Electrification: Electrification does not have this same risk. 4.12.2.2 Uncertainty Regarding Rate at which HFC Rail Vehicles can be Introduced into Revenue Service There is a risk that the duration between the DBFOM contract award and the planned start of the enhanced RER services is insufficient to fully develop, test and deliver the required HFC rail vehicles.  Type: System Implementation  Probability of Risk Occurring: Medium - Since HFC technology of the scale required for Hydrail has not previously been integrated into a rail vehicle this risk relates to system integration, train control and safety regulation issues that might emerge as the rail vehicles are designed and tested.  Significance: High - This risk has high significance because the key objective of the RER Program is to introduce enhanced rail services on the GO network from 2025.

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 Mitigation: Metrolinx has already initiated the two HFC rail vehicle projects to mitigate this risk. The HFC Bi-level EMU Concept Design Project has the objective of obtaining assurance that a hybrid HFC system can be integrated into manufacturers existing EMU products. The HFC Locomotive Concept Design Project has a similar objective and in addition will further progress the systems integration development by proceeding with preliminary and detailed designs. It is intended that this work is completed during the DBFOM procurement process so that bidders can confidently plan for the production design and delivery of an HFC rail vehicle fleet within the required RER timescales.  Comparative Assessment with Electrification: The equivalent uncertainty in relation to the Electrification Program relates to the timescales for completing the electrification infrastructure on each GO corridor. If significant risks emerge in relation to corridor access, utilities diversions and infrastructure modifications then this could also delay the achievement of the 2025 target. 4.12.2.3 Ability of Market to Provide Equipment and Design Services There is a risk that hydrogen technology component vendors will have trouble scaling up to supply the quantity of hydrogen infrastructure required by the Hydrail System.  Type: System Implementation  Probability of Risk Occurring: Medium - Even though individual vendors will be able to anticipate that Hydrail is likely to procure a considerable volume of components they may not be able to scale-up within the time required by RER. However, the whole hydrogen market is expanding in parallel to the development of Hydrail so the risk is likely to be reduced.  Significance: Medium - A delay in the initial supply of key subsystem components would lead to a delay in the commencement of services and slow down the incremental roll-out.  Mitigation: Proactive engagement with the market and provincial government to share the ongoing development efforts. This will provide the hydrogen market with expectations, allowing them to ramp up on their ability to deliver services.  Comparative Assessment with Electrification: Electrification components are commoditized, and since there are major players with electric locomotives and EMUs which are certified and exist in the market, there are fewer uncertainties about the ability of the market to provide equipment and services related to electrification. 4.12.2.4 Zoning and Planning There might be objections raised by planning authorities and local communities to proposed locations for the hydrogen production facilities.  Type: System Implementation  Probability of Risk Occurring: Medium - The likelihood of this risk occurring will depend on the number of location options that are available and the success of the preceding public communication strategy.  Significance: Medium - If there are delays in obtaining planning consents it would still be possible to commence an initial Hydrail service through the purchase of hydrogen from existing industrial suppliers.

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 Mitigation: Proactive engagement will be required with the municipal and provincial governments to begin the planning work and obtain the zoning approvals required to set up the support infrastructure for Hydrail.  Comparative Assessment with Electrification: Electrification also has planning consent risks in relation to the siting of substations. Table 4-55 collates the risks identified above and orders them using a rough risk ranking score of Probability multiplied by Significance, based on High = 3, Medium = 2 and Low = 1. The risks that have a score from 6 to 3 are of sufficient importance that their further investigation is included within the scope of activities outlined in the “Recommended Next Steps” section.

TABLE 4-55 HYDRAIL SYSTEM IMPLEMENTATION RISK MATRIX Risk Probability Significance Risk Score Uncertainty Regarding Rate at which HFC Rail Vehicles can be Medium High 6 Introduced into Revenue Service Public Perception of Hydrogen Medium Medium 4 Ability of Market to Provide Equipment and Design Services Medium Medium 4 Zoning and Planning Medium Medium 4

4.12.3 System Operational Risks 4.12.3.1 Forecasting the Future Price of Electricity The actual average price differential between peak and off-peak rates might change from the forecast rates provided by IESO.  Type: System Operational  Probability of Risk Occurring: Medium - The electricity price forecasts used to calculate the operating costs of Hydrail and Electrification have been provided by IESO and are based on the 2017 Long Term Energy Plan for Ontario  Significance: High – If the differencebetween the price of electricity paid by Hydrail and that for Electrification narrows, this would weaken the economic case for Hydrail.  Mitigation: Engage with the provincial government to define, or pre-establish, the cost of electricity relating to Hydrail.  Comparative Assessment with Electrification: If the difference between the price of electricity paid by Hydrail and that for Electrification increases, this would weaken the economic case for Electrification. 4.12.3.2 Hydrail Operational Complexity There are uncertainties about how HFC rail vehicles will be brought into service at the start of each day and refuelled at the end of each day. There are also uncertainties around the type and frequency of maintenance and renewal operations of the HFC components. These could have a significant negative impact on the expected operational efficiency of the RER level of service.

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 Type: System Operational  Probability of Risk Occurring: Medium - The probability of there being a significant negative impact on the RER level of service from the adoption of HFC rail vehicles is not considered to be high as Metrolinx currently has experience of managing a fleet of rail vehicles that requires refuelling every day and that requires in-house maintenance activities to be carried out on the vehicles’ propulsion systems.  Significance: High - This is a risk that is important because one of the key factors in determining the viability of the Hydrail System is ensuring that it has a high level of operational efficiency  Mitigation: As part of the proposed “Recommended Next Steps” activities it is intended to undertake further analysis of the operational capabilities of the Hydrail System and how they align with the RER level of service.  Comparative Assessment with Electrification: This is a much lower risk for the Electrification Program as electric locomotives and EMUs have well proven operational and maintenance requirements. In addition, the electric rail vehicles do not require to be refuelled. 4.12.3.3 Maintenance Staff Capabilities It might be difficult to find sufficient numbers of staff with the specialized skills to maintain the Hydrail System components, both on the locomotive and at offsite facilities.  Type: System Operational  Probability of Risk Occurring: Low - The likelihood of this risk occurring is low because there is sufficient time to mitigate it and the demand for skilled hydrogen technicans will follow the incremental introduction of an HFC fleet.  Significance: Medium - The impact of this risk will be on train service performance.  Mitigation: Engage with Ontario Ministry of Advanced Education and colleges in Ontario to ensure that courses are available to train and certify existing and new staff as hydrogen technicians.  Comparative Assessment with Electrification: Electrification will have a similar risk, since the new electric locomotives and EMUs will require maintenance staff with new skills. 4.12.3.4 Hydrogen Production Failure There is a risk of a shortage of supply of hydrogen due to a failure in the hydrogen production subsystem or in the supply of electricity from the grid.  Type: System Operational  Probability of Risk Occurring: Low - The probability of this occurring is low as it is intended to store up to three days supply of hydrogen at each hydrogen production facility. If this is not sufficient at one particular location, contingency plans will be put in place to transport hydrogen from one of the other production facilities.  Significance: Medium - This is not a significant risk as there will be built-in supply buffers in the system to limit the severity of the impact.  Mitigation: As part of the proposed “Recommended Next Steps” activities it is intended to produce a concept design of a generic hydrogen production facility. Within the design process consideration will be given to mitigating this risk to an acceptable level.

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 Comparative Assessment with Electrification: There is an equivalent risk in the Electrification Program which relates to the reliability of supply of electricity. Redundancy has been built into the connection of the OCS with the electricity grid to reduce this risk to an acceptable level. 4.12.3.5 Reliability of HFC Trains There is a risk that the availability and performance of the HFC rail vehicles could be compromised due to failures of components in the rail vehicle subsystem.  Type: System Operational  Probability of Risk Occurring: Medium - A rail vehicle is a harsh environment particularly due to climatic conditions and vibration. However, there is a considerable amount of experience of operating HFC-powered buses where these conditions are probably worse than on a rail network. In addition, the HFC subsystem will be designed so that the failure of one component will not have a catastrophic impact on the operation of the rail vehicle. For example: the fuel cells will be arranged in parallel stacks so that a failure of one unit will only result in a reduced amount of output power and not the shut down of the complete fuel cell subsystem; even if the whole fuel cell subsystem becomes unavailable there will be sufficient power in the battery system to enable the rail vehicle to operate in degraded mode so that it can reach a place of safety; the battery subsystem will also be designed so that a failure in one battery will only lead to a reduction in peak power available to accelerate the train. It is likely that in this scenario that it will be possible to continue to operate the train at close to normal performance. Furthermore, the planned train consists will have the following redundancies: EMUs have multiple powered coaches so that the train should be able to continue to operate even if the system on coach fails; adopting a two locomotive consist for 12 carriages means that even if one locomotive fails it will still be possible for the consist to continue working.  Significance: High - This is a risk of significant importance because it is fundamental to the operational viability of the Hydrail System.  Mitigation: Gaining assurance about how the HFC rail vehicles will be able to continue to function is one of the factors that will be investigated as part of the HFC Bi-level Concept Design project and the HFC Locomotive project.  Comparative Assessment with Electrification: There are similar risks with the electric locomotives and EMUs. Even though there is a highlevel of reliability of the electrical components on an electric locomotive or an EMU, there is a lower level of sytem redundancy than with a HFC rail vehicle. In addition, any failure of the overhead contact wire on a section of corridor would lead to significant operational disruption. 4.12.3.6 Impact on Passengers of a Train Accident In the event of a train accident there is the potential that passengers could be hurt due to the ignition or explosion of leaking hydrogen.  Type: System Operational  Probability of Risk Occurring: Low - The likelihood of this is low because: when hydrogen escapes it disperses into the atmosphere very quickly; if a hydrogen leak does ignite then it burns with a flame rather than explodes; the hydrogen will be stored on the rail vehicles in multiple tanks so that it is unlikely that more than one tank would be damaged in an accident; the hydrogen will be stored at 700 bar in the storage tanks which will encourage the hydrogen to escape quickly; in the case of the HFC EMU the hydrogen tanks will be installed near the roof of the train where the gas

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can quickly escape in the event of tank rupture; in the case of the HFC locomotive the tanks will be isolated from the adjacent passenger coach by a fire proof barrier; the rail vehicle subsystem will be designed to achieve a high level of crashworthiness; the rail vehicle subsystem will be designed with automated shut-off systems that are designed to limit the amount of hydrogen that can escape.  Significance: High - Any risk relating to safety will be treated with the highest level of significance during the design of the HFC rail vehicles.  Mitigation: Gaining assurance about how the HFC subsystem will respond to an accident will be part of the activities that we propose to undertake in Q1 and Q2 2018. It will also feature as part of the HFC Bi-level Concept Design project and the HFC Locomotive project.  Comparative Assessment with Electrification: In the event of an electric rail vehicle accident, there could be a risk to passengers due to damaged overhead catenary infrastructure. 4.12.3.7 Implications to RER due to Hydrail There is a risk that the operation of the Hydrail System might have a negative impact on the ability to achieve the planned RER level of service.  Type: System Operational  Probability of Risk Occurring: Low - The feasibility study has not identified any area of the operation of the Hydrail System that is likely to have a significant impact on the operation of RER. The areas that this risk is most relevant to are: the performance and operation of a two-locomotive consist; and the refuelling process.  Significance: Medium - The objective of the design of the Hydrail System is to match the RER level of service in terms of terms of the RER train service plan. If this risk occurs it seems likely that the reduction in level of service will be small. This risk also generates an opportunity whereby a small reduction in train performance could lead to a significant reduction in Hydrail’s operating cost.  Mitigation: As part of the proposed “Recommended Next Steps” activities it is intended that the Hydrail team will develop a more refined assessment of the train service capability of the HFC rail vehicles and the operating processes of refuelling. We will also work with the RER Program team to model operating cost savings that could be achieved from a range of reductions in train performance and how this might impact the BCR for the Hydrail System.  Comparative Assessment with Electrification: This exact risk is unlikely to be experienced with electrification as electric locomotives and EMUs that are available for the major rail vehicle manufacturers have performance characteristics that have been used in the simulation modelling of RER. However, there might be the reverse risk if rail vehicles supplied have more performance characteristics than required for RER (acceleration, top speed). Table 4-56 collates the risks identified above and orders them using a rough risk ranking score of Probability multiplied by Significance, based on High = 3, Medium = 2 and Low = 1. The risks that have a score from 6 to 3 are of sufficient importance that their further investigation is included within the scope of activities outlined in the “Recommended Next Steps” section.

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TABLE 4-56 HYDRAIL SYSTEM OPERATIONAL RISK MATRIX Risk Probability Significance Risk Score Forecasting the Future Price of Electricity Medium High 6 Reliability of HFC Trains Medium High 6 Hydrail Operational Complexity Medium High 6 Impact on Passengers of a Train Accident Low High 3 Maintenance Staff Capabilities Low Medium 2 Hydrogen Production Failure Low Medium 2 Implications to RER due to Hydrail Low Medium 2 4.12.4 Opportunities 4.12.4.1 Incremental Service Introduction Electrification requires the infrastructure on each corridor to be completed before electrified services can commence. With the Hydrail System an electrified service can be introduced incrementally starting from a single HFC rail vehicle on a corridor and then building up to a full service over a period of time. The benefits of this approach are:  The possible earlier introduction of electrified services on any corridor than would be the case with electrification which would improve the revenue benefits profile for RER;  Because there is less up-front fixed CAPEX for the Hydrail System compared to Electrification the NPV for Hydrail is more aligned to the profile of the rolling stock delivery, whereas the NPV for Electrification is more aligned to the up-front CAPEX. This should create a comparative advantage for the Hydrail System in the business case analysis.  Most of the capital cost for Hydrail System is related to manufacture of the rolling stock and therefore this is spread over the production period a longer period over which the capital cost of a reduced dependency between the completion of RER infrastructure and the introduction of electric rolling stock onto the GO network which could be beneficial in terms of public relations. 4.12.4.2 Advantage of Using Surplus Electricity The Hydrail System will generally use surplus baseload electricity generated in the province to produce hydrogen and will therefore pay for its power using rates that will not include the GA factor. The OCS electrification option will largely use the higher day time rates of electricity that will also include the GA. Because the Hydrail System will use about 15 percent of the surplus power that is generated it potentially could have an impact on the size of the GA that is added to the bills of all Ontario power users.

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4.12.4.3 Remove Diesel Locomotive Services from the Milton and Richmond Hill Corridors The rail infrastructure of the Milton and Richmond Hill corridors are not owned by Metrolinx. As a result, it is not possible to install overhead electrification infrastructure on these corridors. However, the Hydrail System option provides the ability to operate electric train services on these two corridors. The benefits of this would be improved RER services being operated on these corridors and a reduction in greenhouse gas emissions for the GO network compared to electrification. However, there would be additional capital and operating costs for the Hydrail System which would need to be assessed against the revenue benefits of providing RER services on these corridors. 4.12.4.4 Hydrail as a Catalyst for the Implementation of a ‘Hydrogen Economy’ in Ontario One of the constraints to the broader adoption of hydrogen as a replacement to fossil fuels as an energy carrier is the current limited availability of hydrogen outside of industrial applications. An investment in the infrastructure of hydrogen production and storage could be used as a lever by the government of Ontario and/or the private sector to make hydrogen available to users outside of Metrolinx. There is the opportunity for Metrolinx to work with a broad cross-section of government departments to develop a strategy similar to that recently published by the South Australia government203 for a roadmap for a broader use of hydrogen across Ontario. The potential benefits of this are:  Sharing of the costs of the fixed infrastructure assets  Reductions in the use of fossil fuels as energy sources  Development of businesses and jobs with a hydrogen technology focus  The development of Ontario as a global leader in the implementation of hydrogen technologies  Adoption of hydrogen as an energy storage material in combination with renewable energy sources and the associated benefits in relation to the stabilization of the electricity grid in response to variations in demand. 4.12.4.5 Shared Cost of Fixed Infrastructure Hydrogen could also have other applications within Metrolinx that could then use the same hydrogen production infrastructure. Metrolinx is already considering the use of HFC-powered buses as replacements for its diesel bus fleet. There is the potential integrate this strategy with the development of the Hydrail System which could lead to a shared hydrogen production, storage and refuelling infrastructure.

203 http://ourenergyplan.sa.gov.au/hydrogen.html

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In addition, there is the potential to use HFCs as main power sources or back-up power sources for Metrolinx’s property portfolio. This could potentially lead to a reduction in operating costs or at least improved energy security. 4.12.4.6 Capture of Energy through Regenerative Braking All modern electric rail vehicles use their traction motors, working in reverse, as part of the vehicle’s braking system. This means that the traction motor is working as a generator. Regenerative braking is the ability to capture this electrical energy for a beneficial use. With rail vehicles operating in an overhead catenary system this energy is fed back into the grid via the vehicle’s pantograph. The amount of energy that is captured in this way is relatively small compared to the total potential energy that would be available because there is no resulting benefit to the operating of the vehicle and so vehicle’s electrical systems are not optimized for this purpose. With the Hydrail System we believe that there is an opportunity to capture a significant additional amount of the rail vehicle’s braking energy and to feed it into the batteries and utltracapacitors that are part of the hybrid HFC subsystem. We would do this by specifically focusing on the design of the rail vehicle’s electrical systems (batteries, utltracapacitors and fuel cell) to optimize the amount of energy that can be cost effectively captured (that is, within the constraints of space availability and equipment cost). By doing this it should be possible to optimize the design of the subsystem to minimize the volume of hydrogen that will be consumed on each trip. In this way, it should be possible to increase the overall range of the Hydrail rail vehicles from what we can be maximized and the minimize the amount of hydrogen that needs to be produced for the overall Hydrail System. We plan to investigate this opportunity as part of the HFC Bi-Level EMU and HFC Locomotive projects that will be undertaken during Q1 and Q2 2018.

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5 RER Program Electrification

This section describes the scope of the currently proposed by the RER Program, including the proposal for overhead electrification, and the issues that need to be resolved during preliminary design and implementation. 5.1 Current RER Program 5.1.1 Scope The Regional Transportation Plan for the Greater Toronto and Hamilton Area (GTHA), or The Big Move, identifies the need for a significant increase in rail service across the GO network. Accordingly, the RER program is being planned to provide more frequent, faster, and higher-capacity service204. In January 2010, a study of the electrification of the GO rail system was initiated as a future alternative to diesel trains currently in service. The objective of the Electrification Study was to provide information so that a decision about how GO trains will be powered in the future – using electricity, enhanced diesel technology, or other means – can be made, as this fleet propulsion upgrade has a key role in delivering the Big Move205. The IBC was published in 2015 and scoped the RER program by defining, analyzing, and reporting the feasibility of various scenarios for GO RER service and infrastructure206. In the RER business case, Scenario 1 (Do Minimum) is the base case that assumes a continuation of today’s peak-focussed service patterns and diesel technology. All other scenarios are compared to it. Scenario 2 (Two-Way All-Day) and Scenario 3 (10-Year Plan) consider more frequent all-day service, looking at the costs and benefits of all-diesel and some limited electrification. Scenario 4 (Full Build) is a maximum-build scenario, with frequent all-day service and overhead electrification on all corridors. These four scenarios were studied so that different levels of service (LOSs) and infrastructure could be assessed and compared to understand if and how they would achieve strategic objectives, how much they would cost to build and operate, and how effective they would be at generating benefits, all while considering deliverability constraints. Scenario 5 (10-Year Plan Optimized) was then developed based on available funds and a 10-year build period for delivery (Figure 5-1). This program includes electrification and frequent service on most inner corridors207. For the purposes of this feasibility report, Hydrail is assessed against RER Scenario 5.

204 Metrolinx. 2017. GO Rail Network Electrification Transit Project Assessment Process Environmental Project Report. Prepared by Morrison Hershfield Limited and Gannet Fleming Canada ULC. October 5. Accessed October 2017. http://www.gotransit.com/electrification/en/docs/technicalreports/GO percent20Rail percent20Network percent20Electrification percent20Environmental percent20Project percent20Report_Volume percent201.pdf. 205 Metrolinx. 2010. GO Electrification Study Final Report. Prepared by Delcan Arup Joint Venture. December. Accessed October 2017. http://www.gotransit.com/electrification/en/project_history/docs/ElectricificationStudy_FinalReport.pdf. 206 Metrolinx. 2015. GO RER Initial Business Case. Accessed October 2017. http://www.metrolinx.com/en/regionalplanning/projectevaluation/benefitscases/GO_RER_Initial_Business_Case_EN.pdf 207 ibid.

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To sum up, by 2024, the GO rail network is planned to:  Be expanded to enable electrified train service in core system areas at 15-minute frequencies or better  Offer up to four times the current number of train trips during off-peak hours  Offer twice the current number of trips during peak hours throughout the network208 The scope of the RER project, as described in Scenario 5, involves electrification of the following GO rail corridors: 1. Union Station Rail Corridor (Figure 5-2) – From Union Pearson (UP) Express Union Station to Don Yard Layover 2. Lakeshore West Corridor – From just west of Bathurst Street (Mile 1.20) to Burlington 3. Kitchener Corridor – From UP Express Spur 8 (at Highway 427) to Bramalea 4. Barrie Corridor – From Parkdale Junction (off Kitchener Corridor) to Allandale GO Station 5. Stouffville Corridor – From Scarborough Junction (off Lakeshore East Corridor) to Lincolnville GO 6. Station 7. Lakeshore East Corridor – From Don Yard Layover to Oshawa GO Station209 Electrification of the system is one of the components of the RER program. It is being undertaken in parallel with other projects to build all infrastructure needed to increase service210. The infrastructure must accommodate the busiest hour of service during the peak-hour period, as well as any track occupancy required by other rail operators (freight and intercity services). During the peak hours, the number of trains may vary slightly; therefore, the worst-case scenario, or high peak hour, was used to develop the infrastructure requirements for the 10-year plan (Scenario 5)211.

208 Metrolinx. 2017. GO Rail Network Electrification Transit Project Assessment Process Environmental Project Report. Prepared by Morrison Hershfield Limited and Gannet Fleming Canada ULC. October 5. Accessed October 2017. http://www.gotransit.com/electrification/en/docs/technicalreports/GO percent20Rail percent20Network percent20Electrification percent20Environmental percent20Project percent20Report_Volume percent201.pdf. 209 ibid. 210 ibid. 211 Metrolinx. 2015. GO RER Initial Business Case. Accessed October 2017. http://www.metrolinx.com/en/regionalplanning/projectevaluation/benefitscases/GO_RER_Initial_Business_Case_EN.pdf

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FIGURE 5-1 SCENARIO 5 EXTENT OF ELECTRIFICATION212

212 ibid.

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FIGURE 5-2 SCENARIO 5 PRELIMINARY INFRASTRUCTURE CONSIDERATIONS FOR THE UNION STATION RAIL CORRIDOR213

Figure 5-1 gives us an idea of the breadth of the civil works required to implement the electrification infrastructure. Further to the overhead catenary system itself, there are signal immunization services to be implemented, traction power stations to be built, modifications that need to be made to existing stations, and changes required for existing bridges and layover facilities. 5.1.2 Train Service Plan All-day EMU services would operate every 15 minutes to Aldershot, Bramalea, Aurora, Unionville, and Oshawa; with hourly services to Hamilton (diesel, express Oakville-Union), Barrie (EMU, express Aurora-Union), and Mount Joy (EMU, as an extension of one in four Unionville trains). Milton and Richmond Hill would remain peak-only diesel corridors214. Table 5-1 provides a summary of the Scenario 5 train service plan, by corridor. Figure 5-3 shows the peak periods, while Figure 5-4 shows off-peak periods.

213 ibid. 214 ibid.

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TABLE 5-1 SCENARIO 5 SUMMARY OF SERVICES215 Richmond Hill Lakeshore West Kitchener Do Minimum – Scenario 5 Electrification with Lakeshore East Milton EMUs to Bramalea; Barrie Peak-only Stouffville (10-year Plan EMUs; Diesel to Electrification with Do Minimum – Peak Peak-only Diesel to Electrification with Commuter Rail Electrification with Optimized) Hamilton EMUs Only as Existing Kitchener EMUs as Existing EMUs Peak Service – As Capacity added to Capacity added to Capacity Capacity Capacity added to Capacity Capacity added to existing plus match demand match demand constrained constrained beyond match demand added to match demand Bramalea; UPX match demand every 15 minutes (EMU) All-day service – Every 15 minutes Every 15 minutes Peak-only service Every 15 minutes Every 15 minutes Peak-only Every 15 minutes Inner Aldershot – Oshawa Aldershot – Oshawa Bramalea (EMU); UP Aurora (EMU) service Unionville (EMU) (EMU) (EMU) Express every 15 minutes All-day service - Hourly all-day - - Peak-only service Hourly all day - One train per hour Outer Hamilton (diesel); Barrie (EMU); extended to Mount Express from Express from Joy Oakville Aurora Notes: - = not applicable

215 ibid.

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FIGURE 5-3 SCENARIO 5 PROPOSED SERVICE CONCEPT – PEAK PERIODS216

216 ibid.

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FIGURE 5-4 SCENARIO 5 PROPOSED SERVICE CONCEPT – OFF-PEAK PERIODS217

5.1.3 Procurement of Rolling Stock Passenger rail rolling stock is traditionally built in fleets customized for a specific application. This is because, although there are standard technical platforms, railways differ sufficiently in local technical and environmental requirements. In comparison with automobile or even aircraft manufacture, production runs are considered small218. In Scenario 5, approximately 140 EMU cars would be required for the Lakeshore route, and approximately 30 cars for each additional electrified route. Procurement of a new rolling stock fleet is assumed to take 4 to 8 years, although it may be possible to reduce this timeframe. The process entails:  Development of the customer requirements (car size, configuration of doors, seats)  Definition of detailed technical requirements  Definition of procurement contracting structure and finance  Option of long-term maintenance contract with extended warranty  Tender preparation period

217 ibid. 218 ibid.

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 Tender evaluation, negotiation, and award  Fundraising and financial close (if privately financed)  Final design and approval  Establishment of manufacturing arrangements  Car manufacture  Testing and commissioning It is possible to get small fleets faster if there is an existing off-the-shelf design, and if trains can be purchased as an add-on to an existing order. Additional time may be required if:  There is no off-the-shelf design  The design is not already approved by regulatory authorities  The customer wishes to facilitate local manufacture  AFP methods are to be used219

219 ibid.

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5.2 RER Electrification Infrastructure Extent and Possible Scope Changes due to Hydrail Table 5-2 summarizes the key infrastructure requirements for the traditional electrification of the GO network, as well as the description of each category, and the extent of the required equipment and services. Information is also provided on the infrastructure required for Hydrail deployment.

TABLE 5-2 SUMMARY OF KEY INFRASTRUCTURE REQUIREMENTS FOR RER ELECTRIFICATION Required for RER Required for Category Type Description Electrification Hydrail

Line side OCS The overhead power distribution 250-km length of corridor No equipment system consists of:  Contact and supporting wires  Supporting gantries, foundations, anchors, guys, braces, and similar reinforcing attachments

Substations A typical traction power substation Four new facilities No includes power utility interface equipment, disconnect switches, circuit breakers, traction power transformers, switchgear, control equipment, and auxiliary system.

Maintenance Maintenance and renewal of the Regular cycle of No and renewal OCS and substation components preventative maintenance due to performance degradation, and renewal work design life, and failure. Ad hoc replacement of failed components

Implementation Utilities The need to relocate away from the The scope of work is not No diversions rail corridor existing utilities that explicitly identified in the physically or electrically interfere IBC with the OCS

Vegetation The installation and operation of the The scope of work is not No clearing OCS requires a 7-m vegetation explicitly identified in the clearing zone from the centre of the IBC outermost track.

Property A typical substation adjacent to the The scope of work is not No acquisition rail corridor would require an area of explicitly identified in the Property might approximately 45 m by 100 m, which IBC need to be may need to be acquired for this acquired for project. Hydrail, but there is more flexibility on location

Operational The impacts of undertaking The scope of work is not No disruption construction work in live rail explicitly identified in the corridors will include: IBC  Undertaking work during night- time and out of peak possessions where only a few hours of work can be completed on any one occasion, but t his style of work is

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TABLE 5-2 SUMMARY OF KEY INFRASTRUCTURE REQUIREMENTS FOR RER ELECTRIFICATION Required for RER Required for Category Type Description Electrification Hydrail inefficient and adds a significant overhead cost  Closing sections of track for extended periods of time enables the work to be carried out efficiently on that section, but it means that there are reduced services over that section  Closing sections of a corridor for extended periods of time enables extensive work to be undertaken as quickly as possible, but it means that replacement bus services need to be put into operation for that period

Infrastructure Modifications and rebuilding of Requires 39 interventions No modification bridges and station canopies to gain to modify stations, 19 sufficient vertical clearance for OCS bridge clearance installation interventions, and 2 bridge rebuild interventions

Electrical Modifications to the signal system A cost for this of $703 No immunization and other electrical systems to million has been included of signalling immunize them against the effects of in the IBC and other electromagnetic interference systems

Rail vehicle Electric Electric locomotives will be used to 35 units (in 2024) Yes locomotives replace the existing diesel Hydrail requires locomotives to pull the existing an electric unpowered BL carriages; t he electric locomotive for locomotives will have enhanced every six performance characteristics to meet carriages RER service requirements. EMUs Might be used as part of the RER 84 four-car sets (2024) Yes fleet to provide the additional peak Hydrail may and off-peak services that are require additional defined in RER. unpowered coaches to obtain the required seating capacity

Maintenance The periodical preventive Comprehensive non- Partially maintenance activities required for mechanical refurbishment External the efficient use of rail vehicles every 8 years mechanical and includes daily cleaning, regular electrical maintenance and inspection, and the components replacement of mechanical related to the components. It also includes the pantograph are additional effort to maintain rail not required vehicles (cleaning, brakes, air dryers, pantograph carbon strips, and motors) due to winter weather.

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TABLE 5-2 SUMMARY OF KEY INFRASTRUCTURE REQUIREMENTS FOR RER ELECTRIFICATION Required for RER Required for Category Type Description Electrification Hydrail

Workforce Professional qualification training The scope of work is not Yes training required for staff who will be explicitly identified in the Staff will need to operating and maintaining the IBC be trained in the electric rail vehicles. maintenance of hybrid HFC systems

Notes: IBC = Initial Business Case m = metre km = kilometre OCS = Overhead Contact System

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6 Recommended Next Steps

This section recommends actions arising from the findings within this report, in relation to the further development of the Hydrail System, in relation to the broader questions that inter-relate with the Provincial government, and in relation to the development of the RER DBFOM. 6.1 Actions to Further Develop Hydrail The proposed next steps for the development of the Hydrail System are focussed on the need to maintain alignment between the development of Hydrail and the preparation activities for the RER DBFOM procurement. The primary objective of the proposed next steps is to enable the design of the whole Hydrail System to be taken forward to conceptual design level so that by the time the DBFOM bidders start to prepare their bids they will have access to high quality information about the design and operation of the Hydrail System. This will enable the DBFOM bidders to more accurately assess the risks and benefits of Hydrail in comparison with electrification than would otherwise be the case. In particular, it is proposed that further work is undertaken in those areas of the Hydrail System where the DBFOM bidders are likely to want a greater level of certainty than currently exists, at the completion of the feasibility study. These are:  Refine the Hydrail System design in terms of system size, based on a more accurate representation of the system configuration in the Operational Simulation model;  Comission concept designs for a HFC EMU, a HFC Locomotive and the hydrogen production, hydrogen storage and hydrogen fuelling subsystems;  Identify preferred options for location of hydrogen production facilities for each corridor;  Confirm how the Hydrail System would function as an operational railway, particularly in areas such as maintenance and refuelling;  Confirm the capital and operating cost estimates of the whole Hydrail System based on further engagement with component vendors and a more formal approach to estimating infrastructure and vehicle delivery costs;  Confirm how the Hydrail System could be implemented through its development and build phases and particularly the transition plan of Hydrail into revenue service across the GO network;  Develop a Safety Case roadmap for Hydrail based on consultation with Transport Canada and organizations responsible for maintaining and developing hydrogen related safety standards;  Build and operate a small-scale prototype of the Hydrail System including an HFC Locomotive. 6.1.1 System Size The definition of the Hydrail System presented in this feasibility study is based on modelling work that simulates how the whole system will operate every day. The Operational Simulation Model has been specifically designed to simulate the performance of each of Hydrail’s subsystems and the design is based on the following principles:  The fleet mix and train service pattern defined as Scenario 5 of the IBC for RER has been used to calculate the peak and average power requirements for train trips on each GO corridor;

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 This data is used to size (power and physical dimensions) the fuel cell and batteries on the rail vehicles;  This in turn determines how much hydrogen is required to operate the train for each trip, which enables the total volume of hydrogen that is needed each day to be calculated;  From this the size of the electrolyzer components has been calculated, and  From this the amount of electrical power required each day for the Hydrail System has been calculated. At each step in this process, assumptions have been made about the:  RER GO network infrastructure and train services from 2025 onwards, and  Functional performance of each of the components in the Hydrail subsystems It has been necessary to make these assumptions because:  The scope of RER has been developing in parallel to the Hydrail feasibility study, and  Our access to data on forecast component functional performance has been based on estimates from a limited number of industry sources. It is considered by the Hydrail team that many of the assumptions in the model are quite conservative and therefore it is the team’s view that it would be beneficial to undertake further work to improve the accuracy of the model’s outputs. We intend to do this by:  Improving the sophistication of the model’s algorithms to more accurately simulate the power requirements of the rail vehicles;  Cross-referencing the algorithms in the model with those being used by the rail vehicle manufacturers who are participating in the HFC Bi-Level EMU Concept Design and HFC Locomotive Concept Design projects, and  Obtaining access to actual component performance data from a range of manufacturers. 6.1.2 Subsystem Concept Designs Even though the feasibility study concludes that there are no technology-related flaws with Hydrail and that all elements required to assemble this system already exist elsewhere in similar applications, the scale of Hydrail is bigger than anything that has currently been implemented. As a consequence, there are technical areas of the Hydrail System definition where the levels of uncertainty need to be reduced so that the risk profile of these areas is comparable to those of the overhead catenary system solution. By undertaking subsystem concept designs a much more precise sizing of all the components of the overall Hydrail System will be achieved. For example, it would enable us to demonstrate how the expected fuelling time can be achieved and to assess the way in which a Hydrail network could be operated and maintained. This reduces these risks so that the DBFOM bidders will be better able to assess the risks and benefits of Hydrail in comparison with electrification.

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Therefore, we intend to initiate engineering concept design studies of: 1. A HFC bi-Level EMU. A procurement process is already underway to commission a number of rail vehicle manufacturers to produce concept designs that integrates a hybrid fuel cell system into their existing bi-level EMU models. The output of this work will provide valuable information on whether the performance of the HFC bi-level EMU will meet the RER requirements, the range of the vehicle between refueling, the likely unit price of the vehicle and the phases in the development of production models; 2. A HFC Locomotive. A procurement process has started to commission a number of rail vehicle manufacturers to produce concept designs that integrates a hybrid fuel cell system into their existing electric locomotive models. The output of this work will provide the same range of useful information as for the HFC bi-level EMU; 3. A hydrogen production and storage facility of a size that would be needed for one of the GO corridors. This will provide us with equipment layout information and component sizing and an understanding of how the facility will be connected to the electricity grid; 4. A hydrogen refuelling and dispensing facility of a size that would be needed to refuel an HFC EMU fleet and an HFC locomotive fleet. This will also provide us with equipment layout information and component sizing and an understanding of how the facility will operate in its interface with the rail vehicles. In particular, it would be designed to achieve the objective of a refuelling time that meets the fleet operation and maintenance expectations of Metrolinx. We intend to undertake this work by assembling a team of consultants, government agencies and universities that we have already engaged with during the feasibility study who have specialist knowledge and capabilities in these areas. This work wouldbe project managed by the existing Metrolinx Hydrail team. 6.1.3 Hydrogen Production Location Identification One of the key variables in the configuration of the Hydrail System are the proposed locations for the hydrogen production facilities. The factors that will need to be considered in deciding on these locations include:  The area required for the facility (this has been covered by the work described above)  The locations for rail vehicle stabling facilities in the RER program  Land that is currently available within Metrolinx’s ownership that could be suitable for such a facility  Land that is outside Metrolinx’s ownership but is close to the proposed rail vehicle stabling facilities  Land that is suitable for such a facility that is located at some distance from the rail network and would be suitable to enable transportation of hydrogen by truck or pipeline to the rail network  The potential to expand the facility for hydrogen production use beyond that required for Metrolinx’s Hydrail  The planning and permitting constraints that would relate to any identified land  The cost of purchase and/or remediation of any identified land We intend to undertake work that will identify a range of options for the hydrogen production locations to enable the Hydrail system to function in both its Scenario 5 and full network

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT configurations. We will then assess these options using the criteria of capital cost, operating cost and planning feasibility and determine the optimized solution. The team undertaking this work will include Metrolinx property staff and RER fleet maintenance planning staff. 6.1.4 Operational Functionality Although the feasibility study has not identified any flaws in how GO would operate using a Hydrail System, there are operational processes that need to be considered in more detail to give DBFOM bidders sufficient assurance that it is feasible to operate. These processes include:  Cyclical maintenance and renewal regimes for the rail vehicle subsystem  Refuelling the trains as part of the end of day processes  Management of degraded rail vehicle operability due to failure of a component within the hybrid HFC subsystem  Response to degraded rail services that prevents access to a refuelling facility  Start of day and end of day routines for the rail vehicle subsystem  Operational and maintenance routines for the hydrogen production, storage and transportation subsystems We intend to create system diagrams for each of these processes so that it is clear how a Hydrail System would integrate with the railway operational processes that DBFOM bidders will be familiar with from operating railway systems based on overhead catenary system of electrification. 6.1.5 Cost Estimates The feasibility study has identified all the key capital and operating cost components in the Hydrail System. The cost values that have been used in the Operational Simulation Model have been obtained for information provided by discussions with industry sources and have been validated against published data. As a result of the further system sizing work, concept design work and hydrogen production facility location work that we have identified above it will be possible to undertake a more formal cost estimating exercise of the capital and operating costs. This will also be accompanied by a quantified risk assessment to more accurately evaluate the forecast cost distribution for different risk parameters. As part of this process there will be a further evaluation of the forecast prices of electricity that it is appropriate to use in the calculation of the Hydrail System’s operating cost. 6.1.6 Implementation Plan Section 4.11 of this report provides an initial view of how the Hydrail System could transition into initial operation. As stated in that section there are many interdependencies of a physical and a timing nature between the RER program’s infrastructure upgrades and the Hydrail System. We intend to work with the RER planning team so that we can create a more detailed transition scenario that integrates with the proposed sequence of infrastructure work and identifies:  Which corridor would be best suited for the initial testing of the HFC rail vehicles  Which corridor would be best suited for the initial revenue service

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 The preferred sequence of corridors that would then introduce the service and how this would relate to the incremental build of the hydrogen production, storage and dispensing facilities 6.1.7 Safety Case Roadmap Section 4.6 of this report provides an overview of the existing codes and standards that apply to hydrogen systems and identifies the need to undertake work that will:  Assess the risks relating to the operation of the Hydrail System  The development of further codes and standards for the operation of the Hydrail System particularly in relation to the refuelling subsystem and the rail vehicle subsystem During the feasibility study the Hydrail team has commenced engagement with Transport Canada and held initial discussions with them about evaluating the safety risk of the Hydrail System concept. In taking forward this area of work the Hydrail team intends to form a working committee that will include Transport Canada, TSSA, CSA, the Canadian Hydrogen Installation Code Standards Committee and equivalents in the United States. The objective of this group will be to develop a pathway for the development of a full suite of codes and standards that will apply to Hydrail. 6.1.8 Prototype Hydrail System Irrespective of how much systems modelling and concept design work is undertaken the complete viability of the Hydrail System can only be demonstrated by designing, building and operating an example of the complete end to end system. At the conclusion of the above activities Metrolinx intends to:  Commission the building of a single prototype HFC Locomotive that can enter revenue service  Commission the development and prototyping of the refueling and hydrogen production subsystems that can work with the prototype HFC Locomotive. Operating this prototype Hydrail System over an extended period will enable Metrolinx to learn valuable lessons concerning Hydrail System’s operations, performance and reliability which can then be fed back into the design and implementation planning of a full Hydrail System.

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6.2 Actions to Align the Hydrail System with Provincial Government Policy 6.2.1 Electricity Price Policy As outlined in Section 4.4, the calculation of the net present value of the operating cost of the Hydrail System is sensitive to the forecast hourly prices of electricity from 2025 onwards. For the Hydrail System to retain its BCR equivalence to the conventional overhead electrification system, the differential between the average off-peak price of electricity to the average peak price of electricity needs to remain at the level used in this analysis (which is: off-peak = 0.4 x peak). Therefore, any narrowing of the differential between the price of electricity paid by Hydrail and that for conventional electrification would weaken the economic case for Hydrail. Due to the many variables that could influence the price of off-peak electricity in the future this is considered to be a highly significant risk (as described in 4.12.3.1). As a consequence, this risk needs to be mitigated to avoid DBFOM bidders including a substantial risk premium into their operating cost calculations for the Hydrail System. A recommended next step is therefore for Metrolinx to engage with the provincial government to determine if it is possible to define, or pre-establish, the cost of electricity relating to the Hydrail System. 6.2.2 Hydrogen Economy As outlined in Section 4.9.1, there are opportunities for the Hydrail System to be a catalyst for the broader adoption of hydrogen in the Ontario economy. As described in Section 4.12.4.4, the benefits of this Hydrogen Economy concept could be:  Sharing of the costs of implementing the fixed infrastructure assets  Reductions in the use of fossil fuels as energy sources  Development of businesses and jobs with a hydrogen technology focus  The development of Ontario as a global leader in the implementation of hydrogen technologies  Adoption of hydrogen as an energy storage material in combination with renewable energy sources and the associated benefits in relation to the stabilisation of the electricity grid in response to variations in demand. Taking forward the development of those opportunities, which are beyond Metrolinx’s transportation mandate, will require consideration and guidance from the provincial government, and potentially part of a broader “hydrogen roadmap”. A recommended next step is therefore to work with the provincial government to develop a cross-government business case for an Ontario Hydrogen Economy.

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6.3 Actions to Integrate the Hydrail System into the DBFOM Procurement Process As stated at the start of Section 6.1 one of the objectives of the “Recommended Next Steps” is to provide high quality information on the Hydrail System to the DBFOM bidders. As such the Hydrail team will work with the Metrolinx team that is managing the DBFOM procurement process over the course of 2018 to ensure that the activities to further develop the Hydrail System concept are aligned with the DBFOM’s timescales and objectives.

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7 References

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TABLE 7-1 REFERENCES Reference Document Title Eudy, L., and M. Post, M. BC Transit Fuel Cell Bus Project Evaluation Results: Second Report. Technical Report NREL/TP- 2014. 5400-62317. National Renewable Energy Laboratory. September Fox, Conrad, Planner Personal communication (email) Nirmal Gnanapragasam Canadian Nuclear Laboratories. Resource Integration, September 22. IESO 2017a. Fox, Conrad, Planner Personal communication with Nirmal Gnanapragasam Canadian Nuclear Laboratories. Resource Integration, IESO. 2017b. Fuel Cell and Hydrogen “Hamburg's Hydrogen Buses and New Refuelling Station.” Clean Hydrogen in European Cities (FCH). 2016. Newsletter. January 13. Accessed October 2017. http://chic-project.eu/newsletters/draft-chic- newsletter-122011/infrastructure-development-draft-chic-newsletter-122011/hamburgs- hydrogen-buses-in-operation Fuel Cell and Hydrogen Who We Are. Accessed October 2017. http://www.fch.europa.eu/page/who-we-are. Joint Undertaking (FCHJU). 2017. Gondal, I.A. 2016. "12 – Hydrogen transportation by pipelines." Compendium of Hydrogen Energy, Volume 2: Hydrogen Storage, Transportation and Infrastructure. pp. 301-322. Accessed October 2017. http://dx.doi.org/10.1016/B978-1-78242-362-1.00012-2 Government of South A Hydrogen Roadmap for South Australia. September. Accessed November 2017. Australia. 2017. https://service.sa.gov.au/cdn/ourenergyplan/assets/hydrogen-roadmap-8-sept-2017.pdf Greimel, Hans. 2017. "Kia fuel cell vehicle to arrive in 3 years. Hyundai brand to launch technology first." Automotive News. April 3. Accessed November 2017. http://www.autonews.com/article/20170403/OEM04/304039933/kia-fuel-cell-vehicle-to- arrive-in-3-years Greimel, Hans, and Naoto "Japan dreams of a hydrogen society. As automakers join effort, will they lead the world or be Okamura. 2017. left behind?" Automotive News. April 24. Accessed November 2017. http://www.autonews.com/article/20170424/OEM06/304249965/japan-dreams-of-a- hydrogen-society Grigoriev, S.A., V.I. “High-pressure PEM water electrolysis and corresponding safety issues.” International Journal Porembskiy, S.V. of Hydrogen Energy. Vol. 36, Issue 3. pp. 2721-2728. February. Accessed October 2017. Korobtsev, V.N. Fateev, F. https://ac.els-cdn.com/S0360319910005392/1-s2.0-S0360319910005392- Auprêtre, and P. Millet. main.pdf?_tid=e9606254-b5a1-11e7-8c40- 2011. 00000aab0f6c&acdnat=1508509447_5473dd3ec2299723689bbebef6dc8fcc

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H2 Mobility. 2017b. Missing Hydrogen Infrastructure. Accessed November 2017. Hillmansen, S. 2003. The application of fuel cell technology to rail transport operations. London, England: Department of Mechanical Engineering, Imperial College of Science, Technology and Medicine. Hoffrichter, Andreas. Hydrogen as an Energy Carrier for Railway Traction. Doctoral thesis. The Birmingham Centre 2013. for Railway Research and Education Electronic, Electrical and Computer Engineering College of Engineering and Physical Sciences. The University of Birmingham. April Hoffrichter, Andreas, Conceptual propulsion system design for a hydrogen-powered regional train. Accepted on Stuart Hillmansen, and April 11, 2015. Edgbaston, Birmingham: Birmingham Centre for Railway Research and Clive Roberts. 2015. Education, University of Birmingham. House of Commons “Rail Electrification.” Briefing Paper SNO5907 July 27 p. 10. Library. 2017.

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TABLE 7-1 REFERENCES Reference Document Title Hua, T.Q., R.K. Ahluwalia, “Technical assessment of compressed hydrogen storage tank systems for automotive J.-K. Peng, M. Kromer, S. applications.”. International Journal of Hydrogen Energy. Volume 36, Issue 4, February. pp. Lasher, K. McKenney, K. 3037-3049. Law, and J. Sinha. 2011. Hydrogen Council. 2017a. How hydrogen empowers the energy transition. January. Accessed October 2017. http://hydrogeneurope.eu/wp-content/uploads/2017/01/20170109-HYDROGEN-COUNCIL- Vision-document-FINAL-HR.pdf Hydrogen Council. 2017b. A sustainable pathway for the global energy transition. November. Accessed December 2017. http://hydrogencouncil.com/wp-content/uploads/2017/11/Hydrogen-scaling-up-Hydrogen- Council.pdf Hydrogenics. 2017a. Fuel Cells. Accessed October 2017. www.hydrogenics.com/technology-resources/hydrogen- technology/fuel-cells/. Hydrogenics. 2017b. "Hydrogenics Signs Purchase and License Agreement valued at over 50M USD for 1,000 Fuel Cell Bus Power Modules." News & Updates. June 8. Accessed November 2017. http://www.hydrogenics.com/2017/06/08/hydrogenics-signs-purchase-and-license- agreement-valued-at-over-50m-usd-for-1000-fuel-cell-bus-power-modules/ Independent Electricity Ontario Planning Outlook. September 1. Accessed October 2017. http://www.ieso.ca/sector- System Operator (IESO). participants/planning-and-forecasting/ontario-planning-outlook. 2016a. Independent Electricity Ontario Transmission System. December 15. System Operator (IESO). 2016b. Independent Electricity IESO Report: Energy Storage. March. Accessed October 2017. http://www.ieso.ca/- System Operator (IESO). /media/files/ieso/document-library/energy-storage/ieso-energy-storage-report_march- 2016c. 2016.pdf Independent Electricity “What We Do.” About the ISEO. Accessed October 5, 2017. http://ieso.ca/en/learn/about-the- System Operator (IESO). ieso/what-we-do. 2017a. Independent Electricity “Generator Output and Capability (GOC) Tables.” Data Directory. Accessed October 2017. System Operator (IESO). http://ieso.ca/en/power-data/data-directory 2017b. Independent Electricity “HOEP_2002-2016 table.” Data Directory. http://ieso.ca/en/power-data/data-directory System Operator (IESO). 2017c. International Energy Technology Roadmap – Hydrogen and Fuel Cells. Accessed October 2017. Agency (IEA). 2015. https://www.iea.org/publications/freepublications/publication/TechnologyRoadmapHydrogen andFuelCells.pdf Johnson Matthey Plc. "History." FuelCellToday. Accessed October 2017. http://www.fuelcelltoday.com/history. 2017. Kenworth. 2017. Kenworth Advances Low - Zero Emission Prototype Projects on T680 Day Cab Drayage Trucks for Southern California Ports. News Releases. May 2. Accessed November 2017. https://www.kenworth.com/news/news-releases/2017/may/advanced-prototype-projects/ Kent, Stephen, Dimantha Future Railway Powertrain Challenge Fuel Cell Electric Multiple Unit (FCEMU) Project. FCEMU Gunawardana, Tom Project - Phase 1 Report - Issue 1. University of Birmingham, Hitachi Rail, Fuel Cell Systems Chicken, and Rob Ellis. Limited. June. 2016.

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TABLE 7-1 REFERENCES Reference Document Title Marcinkoski, Jason, Jacob DOE Hydrogen and Fuel Cells Program Record 15015. September 30. Accessed November Spendelow, Adria Wilson, 2017. https://www.hydrogen.energy.gov/pdfs/15015_fuel_cell_system_cost_2015.pdf. and Dimitrios Papageorgopoulos Fuel Cell System Cost - 2015. Market Intelligence and Grid Integrated Electrolysis. Prepared for Next Hydrogen. October 31. Data Analysis Corporation (MIDAC). 2016. Market Intelligence and Grid Integrated Electrolysis – Facilitating Carbon Emission Reductions in the Transportation, Data Analysis Corporation Industrial and Residential Sectors. October 31. Accessed October 2017. (MIDAC) and https://tinyurl.com/ybptfola NextHydrogen. 2016. Meegahawatte, Danushka, Analysis of a fuel cell hybrid commuter railway vehicle. Birmingham: Birmingham Centre for Stuart Hillmansen, Clive Rail Research and Education, University of Birmingham; and Coventry: Warwick Manufacturing Roberts, Marco Falco, Group, International Manufacturing Centre, University of Warwick. February 1. Andrew McGordon, and Paul Jennings. 2010. Melaina, M. W., O. “Blending Hydrogen into Natural Gas Pipeline Networks: A Review of Key Issues.” National Antonia, and M. Penev. Renewable Energy Laboratory technical report, NREL/TP-5600-51995. March. 2013. Metrolinx. 2010. GO Electrification Study Final Report. Prepared by Delcan Arup Joint Venture. December. Accessed October 2017. http://www.gotransit.com/electrification/en/project_history/docs/ElectricificationStudy_FinalR eport.pdf. Metrolinx. 2015. GO RER Initial Business Case. Accessed October 2017. http://www.metrolinx.com/en/regionalplanning/projectevaluation/benefitscases/GO_RER_Initi al_Business_Case_EN.pdf Metrolinx. 2017. GO Rail Network Electrification Transit Project Assessment Process Environmental Project Report. Prepared by Morrison Hershfield Limited and Gannet Fleming Canada ULC. October 5. Accessed October 2017. http://www.gotransit.com/electrification/en/docs/technicalreports/GO%20Rail%20Network%2 0Electrification%20Environmental%20Project%20Report_Volume%201.pdf National Audit Office. Modernising the Great Western railway. HC 781. November 9. p. 33. 2016. National Energy Board “Who we are.” About Us. Government of Canada. December 1. Accessed October 3, 2017. (NEB). 2016. http://neb-one.gc.ca/bts/whwr/index-eng.html. National Institute of NIST Calculates High Cost of Hydrogen Pipelines, Shows How to Reduce It. July 20. Accessed Standards and October 2017. https://www.nist.gov/news-events/news/2015/07/nist-calculates-high-cost- Technology (NIST). 2015. hydrogen-pipelines-shows-how-reduce-it National Organisation "Structure." About NOW. Accessed October 2017. https://www.now-gmbh.de/en/about- Hydrogen and Fuel Cell now/struktur Technology (NOW). 2017. Natural Resources Canada About Electricity. June 29, 2016. Accessed October 3, 2017. (NRC). 2016. http://www.nrcan.gc.ca/energy/electricity-infrastructure/about-electricity/7359. Natural Resources Canada Photovoltaic and solar resource maps. (Note that high tilt minimizes seasonal variation.) March (NRC). 2017. 20. Accessed October 10. http://www.nrcan.gc.ca/18366

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TABLE 7-1 REFERENCES Reference Document Title National Renewable Hydrogen Station Compression, Storage, and Dispensing Technical Status and Costs. Energy Laboratory (NREL). Independent Review published for the U.S. Department of Energy Hydrogen and Fuel Cells 2014. Program. Technical Report NREL/BK-6A10-58564. Contract No. DE-AC36‐08GO28308. May. Accessed October 2014. https://www.nrel.gov/docs/fy14osti/58564.pdf National Transportation Auxiliary Power Unit Battery Fire Japan Airlines Boeing 787-8, JA829J. AIR-14-01. November Safety Board. 2014. 21. Accessed October 2017. https://www.ntsb.gov/investigations/AccidentReports/Pages/AIR1401.aspx Nel ASA. 2017. Nel ASA: Enters Korean hydrogen market through JV with Deokyang. June 30. Accessed November 2017. http://mb.cision.com/Main/115/2300162/695161.pdf Nikola Motor Company. "Nikola One Truck Revealed Tonight @ 7:00 p.m. MST Class 8 zero-emission hydrogen-electric 2016. truck in production by 2020." News Releases. December 1. Accessed November 2017. https://nikolamotor.com/pdfs/December_1_Release.pdf Office of Energy Efficiency State of the States: Fuel Cells in America in 2016. Washington, D.C.: U.S. Department of & Renewable Energy. Energy. November. Accessed October 2017. 2016. https://energy.gov/eere/fuelcells/downloads/state-states-fuel-cells-america-2016 Office of Energy Efficiency DOE Shows Fuel Cells Used in Maritime Applications Can Increase Efficiency by 30%. & Renewable Energy. Washington, D.C.: U.S. Department of Energy. July 21. Accessed October 2017. 2017. energy.gov/eere/fuelcells/articles/doe-shows-fuel-cells-used-maritime-applications-can- increase-efficiency-30 Ontario Energy Board About us. Accessed October 5, 2017. https://www.oeb.ca/about-us. (OEB). 2012-2017a. Ontario Energy Board “Licensed companies and licensing information.” Industry. Accessed October 5, 2017. (OEB). 2012-2017b. https://www.oeb.ca/industry/licensed-companies-and-licensing-information. Ontario Ministry of Energy Achieving Balance - Ontario’s Long-Term Energy Plan. Accessed October 2017. (Ministry). 2013. http://www.ieso.ca/en/sector-participants/planning-and-forecasting/long-term-energy-plan. Ontario Ministry of Energy About the Ministry. Accessed October 10, 2017. http://www.energy.gov.on.ca/en/about/. (Ministry). 2016. September 26. Ontario Ministry of Electric Vehicle Incentive Program (EVIP). October 3. Accessed October 2017. Transportation. 2017. http://www.mto.gov.on.ca/english/vehicles/electric/electric-vehicle-incentive-program.shtml Pacific Northwest National International Hydrogen Vehicles. Spreadsheet data. Accessed October 2017. Laboratory (PNNL) and http://hydrogen.pnl.gov/sites/default/files/data/International_Hydrogen_Fueled_Vehicles_8.xl U.S. Department of sx Energy (DOE). 2016a. Pacific Northwest National U.S. Hydrogen Vehicles. Spreadsheet data. Accessed October 2017. Laboratory (PNNL) and http://hydrogen.pnl.gov/sites/default/files/data/US_Hydrogen-Fueled Vehicles_6.xlsx U.S. Department of Energy (DOE). 2016b. Pacific Northwest National Resource Center: North American Merchant Hydrogen Plant Production Capacities (1000 Laboratory (PNNL) and kg/day or larger). Accessed October 2017. U.S. Department of https://h2tools.org/sites/default/files/data/North%20America_merchant_hydrogen_plants_Jan Energy (DOE). 2016c. 2016_MTD%2B.xlsx. Panfilov, M. 2016. "4 – Underground and pipeline hydrogen storage." Compendium of Hydrogen Energy, Volume 2: Hydrogen Storage, Transportation and Infrastructure. pp. 91-115. Accessed October 2017. http://dx.doi.org/10.1016/B978-1-78242-362-1.00004-3

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TABLE 7-1 REFERENCES Reference Document Title Parks, G. R. Boyd, J. Hydrogen Station Compression, Storage, and Dispensing Technical Status and Costs. Technical Cornish, and R. Remick. Report NREL/BK-6A 10-58564. Golden, Colorado: National Renewable Energy Laboratory. 2014. May. Accessed November 2017. https://www.nrel.gov/docs/fy14osti/58564.pdf. Praxair Technology, Inc. Advanced Hydrogen Liquefaction Process. Contract Number: DE-FG36-08GO18063. Project ID 2011. PD018. Presented at the DOE annual Merit Review Meeting. Joe Schwartz, presenter. Tonawanda, New York: Praxair. May 10. Accessed October 2017. https://www.hydrogen.energy.gov/pdfs/review11/pd018_schwartz_2011_p.pdf Reed, Stanley. 2017. “Hamburg Is Ready to Fill Up With Hydrogen. Customers Aren’t So Sure.” Business Day. New York Times. July 4. Accessed October 2017. https://www.nytimes.com/2017/07/04/business/hydrogen-cars-trains-planes-hamburg.html Rivkin, C., R. Burgess, and “Hydrogen Technologies Safety Guide.” National Renewable Energy Laboratory technical W. Buttner. 2015. report, NREL/TP-5400-60948. January Sabihuddin, S., A. E. "A Numerical and Graphical Review of Energy Storage Technologies." I. Taniguchi, ed. Kiprakis, and M. Mueller. Energies. ISSN 1996-1073. December 29. Accessed October 2017. www.mdpi.com/1996- 2014. 1073/8/1/172/pdf Scott, David Sanborn. Smelling Land. The Hydrogen Defense Against Climate Catastrophe. April 21. Canadian 2008. Hydrogen Association. Sherif, S.A., D. Yogi Handbook of Hydrogen Energy. July 29. CRC Press. Goswami, Elias K. Stefanakos, and Aldo Steinfeld, eds. 2014. Smartrailworld.com. 2017. An Asian first as China will deliver new hydrogen light rail service. March 12. Accessed October 2017. https://www.smartrailworld.com/an-asian-first-as-china-will-deliver-the-first-hydrogen- train Stack Exchange Inc. 2017. "How durable is a supercapacitor." Electrical Engineering. Accessed October 2017. https://electronics.stackexchange.com/questions/26366/how-durable-is-a-supercapacitor Stuart, A., Technical Personal communication with Nirmal Gnanapragasam Canadian Nuclear Laboratories. Manager of the October 17. Electrolyser Corporation. 2017. The Asahi Shimbun "Cost of hydrogen tanks cut by 30% for stations for fuel-cell vehicles." Asia & Japan Watch. Company. 2017. March 12. Accessed November 2017. http://www.asahi.com/ajw/articles/AJ201703120003.html The EC Network of Biennial Report on Hydrogen Safety (Version 1.2). February 21. Accessed December 2017. Excellence for Hydrogen http://www.hysafe.org/BRHS?op=map#ind265 Safety "HySafe." 2007. The International Council Developing hydrogen fueling infrastructure for fuel cell vehicles: A status update. Briefing on Clean Transportation prepared by Aaron Isenstadt and Nic Lutsey. October. Accessed October 2017. (ICCT). 2017. http://theicct.org/sites/default/files/publications/Hydrogen-infrastructure-status-update_ICCT- briefing_04102017_vF.pdf The Maritime Executive World's First Hydrogen-Powered Cruise Ship Scheduled. October 2. Accessed October 2017. (MarEx). 2017. http://maritime-executive.com/article//worlds-first-hydrogen-powered-cruise-ship-scheduled. Toronto Hydro. 2017. "Toronto Hydro is testing the world’s first underwater compressed air energy storage project in Lake Ontario, near Toronto Island." Underwater Energy Storage. Accessed November 2017. https://www.torontohydro.com/sites/electricsystem/gridinvestment/powerup/pages/compress edairenergystorageproject.aspx

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TABLE 7-1 REFERENCES Reference Document Title Toyota. 2017. “Toyota Opens a Portal to the Future of Zero Emission Trucking.” News Releases. April 19. Accessed November 2017. http://corporatenews.pressroom.toyota.com/releases/toyota+zero+emission+heavyduty+truc king+concept.htm U.S. Department of Hydrogen Fuel Cells. DOE Hydrogen Program. October. Accessed October 2017. Energy (DOE). 2006. https://www.hydrogen.energy.gov/pdfs/doe_fuelcell_factsheet.pdf U.S. Department of "Section iii.E.3, Fiber-Reinforced Polymer Pipelines for Hydrogen Delivery." FY 2007 Annual Energy (DOE). 2008. Progress Report, DOE Hydrogen Program. Accessed October 2017. https://www.hydrogen.energy.gov/pdfs/progress07/iii_e_3_smith.pdf U.S. Department of Fuel Cell Animation. Office of Energy Efficiency & Renewable Energy. Accessed December 15, Energy (DOE). 2017. 2017. https://energy.gov/eere/fuelcells/fuel-cell-animation U.S. Energy Information “Measuring Electricity.” Energy Explained. U.S. Department of Energy (DOE). February 10. Administration (EIA). Accessed September 24, 2017. 2017. https://www.eia.gov/Energyexplained/index.cfm?page=electricity_measuring United Nations The Hydrogen economy, a non-technical review. Paris: Division of Technology, Industry and Environment Programme Economics (DTIE), Energy Branch. (UNEP). 2006. United Nations The Paris Agreement. October 12. Accessed November 2017. Framework Convention on http://unfccc.int/paris_agreement/items/9485.php Climate Change. 2017. van Biert, L., M. Godjevac, “A Review of Fuel Cell Systems for Maritime Applications.” Journal of Power Sources. 327, pp. K. Visser, and A. 345-364. Purushothaman Vellayani. 2016 Zoulias, Emmanuel, Elli A Review of Water Electrolysis. Pikermi, Greece: Centre for Renewable Energy Sources (CRES). Varkaraki, Nicolaos http://hydrogenoman.com/docs/click%20on%20the%20attached.pdf Lymberopoulos, Christodoulos N. Christodoulou, and George N. Karagiorgis. 2004.

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Appendix A – Symposium Feedback

A.1. Introduction A Hydrail Symposium was conducted by Metrolinx to solicit, gather and analyze feedback from qualified members of the public, key stakeholders in the Hydrogen industry and private sector companies that are active in the Hydrogen space. Feedback was solicited in 5 key areas: safety, implementation, environment, energy and workforce. The key objectives and challenges facing Metrolinx for each of these categories was gathered from the perspective of the audience. The common themes around each of these areas are highlight below. Safety The Key Objectives identified in the safety category include:  Ensuring adequate training for the entire workforce is conducted as the workforce will need to be very familiar with the technology to operate and maintain the system, particularly rail operation. This is best done through a formal and structured training program  Ensuring codes, standards and regulations that are already in place are well known within the study and key areas of deficiency are identified  Providing proper knowledge transfer to the public through a public education campaign that shows hydrogen being safe to use; and developing the appropriate methodology of making this communication effective  Adopting risk assessments to tie in with the communications strategy and comparing to other energy systems so a proper risk benefit analysis can be conducted The Key Challenges identified in the safety category include:  Controlling misinformation about Hydrail. In terms of public perception, understanding of hydrogen is low and this could possibly be the biggest challenge to making it work from a safety perspective. Getting the public to understand the technology will be very difficult since perception of safety issues will have to be separated from real safety issues. This will require the support of media and key government officials  Working with the government and regulatory bodies to develop adequate regulations will be another challenge since the integration of hydrogen on a rail vehicle has never been done on the RER scale before Implementation The Key Objectives identified in the implementation category include:  Implementing a pilot project immediately with both small and large scale-testing, with a phased-in approach. This way, the system can be slowly adjusted to accommodate RER, learn lessons along the way to meet the 2024/25 deadline. The phased-in approach also reduces risk  Develop and maintain stakeholder and government involvement, as well as partnerships with other organizations

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 Investing the time and effort to nail down the mechanics of refueling (frequency, cost, and who will operate) and gather all analytics prior to implementing to deliver on time and on budget. The process should not be rushed The Key Challenges identified in the implementation category include:  Delivering on time as per the provincial government promise (which affect public perception) and maintaining reliability are crucial since Metrolinx will only have one chance at a first impression  Managing costs and expectations from planning, to initiation, to full life cycle is thought to be difficult  Finding a one-size-fits-all solution for refuelling/hydrogen production given GTHA’s varied geography, track/station layouts is thought to be another hurdle that could dramatically increase costs  Implementing/protecting the program if the minister or government changes is to be looked at so efforts and investments are not wasted Environment The Key Objectives identified in the environment category include:  Clearly communicating the environmental benefits of hydrogen to the public, in comparison with overhead catenary and capturing all pertinent data including air quality, avoiding tree cutting, GHG reduction, and noise reduction  Managing life cycle costs to ensure all decisions are based on lifetime costs and carbon usage. The Key Challenges identified in the environment category include:  Managing the life cycle cost and expectations including a full life cycle analysis if needed  Incentivizing people out of their cars and into these new transit options  Coordination of fueling, particularly relating to where to put nodes and hitch stations  Contextualizing the efficiency question and explaining “how using more energy can be a good thing” Energy The Key Objectives identified in the energy category include:  Ensuring the efficient utilization of excess power and contextualizing the future availability of off- peak power  Thorough analysis of costs involved and similar options which need actual life cycle costs, speed, infrastructure, testing (there is a lack of understanding surrounding whether or not Hydrail will help bring down costs). This would include explaining the changing dynamics of electricity i.e. the more infrastructure that uses electricity during off peak, the more the price will increase, and the need for new, clean electricity generation which will be expensive  Define efficiency for a better understanding of what it entails  Have a holistic approach: impact to the grid as a whole  Comparison of power to create energy of power for vehicle vs energy for locomotives

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The Key Challenges identified in the energy category include:  Market changes which affect feasibility of project and the geographical challenges to identify if the program will change from region to region  Managing costs and expectations particularly relating to the transparency needed in electricity pricing and the coordination across ministries to develop a long-term policy that will remain in place even with the potential change of government Workforce The Key Objectives identified in the workforce category include:  Positioning Ontario as an innovative leader in this space and ensuring infrastructure production is local (hire local, build local)  Providing adequate training and skills development to this new workforce (new training scheme will be required)  Moving the concept along in universities, community colleges and the trades  Ensuring the supply chain capacity is ready to meet demand The Key Challenges identified in the workforce category include:  Ensuring a skilled (local) workforce is ready on time. Questions about if the expertise is being exported and if so, if it is sustainable, should be answered  Managing union agreements effectively to avoid waste  Overcoming public doubt and uncertainty about economic benefits  Managing costs and expectations particularly relating to subsidizing labour force and procurement and the impact this has on taxation and on the cost benefits module Other Other Key Objectives included:  Defining “all-in” costs and lack of transparency about how much the lifecycle costs will be managed and funded  Ensuring public consultations with the people who are really affected which include:  Ensuring the public has accurate information  Proactive outreach to emphasize work that has been done, public education  Showcasing Canada as a world leader in hydrogen technology  Educating media to avoid negative news stories based on ill-formed opinions Other Key Challenges included:  Challenges relating to procurement challenge including whether to allow international businesses/competition and how that might impact the local economy  Managing expectations in terms of implementation timing and if it is possible to implement the Hydrail System by 2025  Hard to quantify areas such as improvement of the rider experience and if the average user cares if the train is powered by hydrogen

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Appendix B – Hydrail Safety Review

B.1. Introduction The objective of this hydrogen safety review is to assess the hydrogen hazards for the Hydrail System to identify unresolved safety issues or gaps in the exiting hydrogen installation standards and codes that would make it unfeasible to use HFC-powered trains. The scope of this work is to perform a preliminary hydrogen safety review for the Hydrail concept that consists of the following six system components (shown in Figure B-1): 1. Hydrogen production 2. Hydrogen storage (production site) 3. Hydrogen distribution 4. Hydrogen refill (storage) 5. Hydrogen dispensing 6. Hydrogen vehicle This safety review will identify the main parts, failures, consequences, potential hazards and preventative measures. Assessment of the severity or frequency for each failure is outside the scope of work. The work scope also includes a review of the legal, regulatory & standards that pertain to the Hydrail System. FIGURE B-1 HYDRAIL SYSTEM COMPONENTS AND SCENARIOS FOR THE GO TRANSIT NETWORK

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B.2. Hydrogen Properties Relevant to Hydrogen Safety B.2.1. Forms of Hydrogen Hydrogen, the simplest and lightest element on the periodic table, is composed of only one proton and one electron. Pure hydrogen exists in the form of hydrogen molecules. It coexists in two different forms, ortho (nuclear spins aligned) and para (spins anti-aligned) hydrogen, whose partition is dependent on the temperature. Normal hydrogen at room temperature is 75 percent ortho and 25 percent para. Hydrogen can exist in gaseous, liquid, or slush forms. The normal boiling and melting points of hydrogen is 20.3 K and 14.1 K, respectively, at the absolute pressure of 101.325 kPa. B.2.2. Physical Properties of Hydrogen The physical properties of hydrogen relevant to safety are summarized as follows220:  At standard temperature and pressure, hydrogen is a colourless, tasteless, odorless, non-toxic, and non-corrosive gas. It is the lightest gas, being 1/14 as dense as air. It is positively buoyant above a temperature of 22 K, i.e., over almost the entire temperature range of its gaseous state.

 Because of its small size, small molecular weight and low viscosity, H2 has an enhanced propensity to leak. Rates of any leakage are enhanced by a factor of 50 higher than for water and 10 for nitrogen.  In a pure hydrogen environment, hydrogen molecules collide with each other and bonds can be broken. H+ can penetrate barrier diaphragms. At elevated temperatures and pressures, hydrogen can cause severe decarburization and embrittlement for steels. This is a serious concern in any situation involving storage or transfer of H2 under pressure.  Liquid hydrogen (LH2) is a colourless, odourless, and non-corrosive liquid. It is relatively unreactive. It is categorized as a cryogenic fluid (<-73°C). Any liquid hydrogen splashed on to the skin or in the eyes can cause serious burns by frostbite or hypothermia. LH2 will rapidly boil or flash at all temperatures above its boiling point of 20 K. When evaporated from open LH2 pools, cold H2 is more viscous than ambient gas and thus more prone to the formation of a flammable mixture with air. In confined areas, when LH2 is heated up to ambient conditions, the local atmosphere may change drastically due to the volume increase. B.2.3. Gas Mixing

H2 by itself is harmless, save for asphyxiation. It must be mixed with air in the right proportion to form combustible mixtures. The severity of combustion is strongly dependent upon the hydrogen concentration in air. H2 mixing in air is by two transport processes; mass diffusion and convection. Diffusion is the transport process in which the rate of transport of hydrogen is directly proportional to, and in the opposite direction of, the hydrogen concentration gradient in the hydrogen-air mixture. Diffusion will reduce the hydrogen concentration gradients and over time will result in a uniform distribution. Convection is the transport process where the gas mixture is moved in the opposite direction of the pressure gradient. This movement of gases has local differences in momentum and velocity (magnitude and direction) which creates eddies and turbulences that result in mixing of the gas

220 The EC Network of Excellence for Hydrogen Safety "HySafe." 2007. Biennial Report on Hydrogen Safety (Version 1.2). February 21. Accessed December 2017. http://www.hysafe.org/BRHS?op=map#ind265.

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT constituents. There are two types of convection. The first is forced convection whereby the gases are moved by active systems such as a fan (part of a ventilation system) or a strong wind. The other type of convection is called free convection which is due to buoyancy that results from local gas density differences. With hydrogen being significantly lighter than air, the buoyancy forces are very strong, helping to move the hydrogen upwards. As it moves upwards, it mixes with the entrained air and becomes diluted, spreading outwards. This strong positive buoyancy of hydrogen is a favourable safety feature in unconfined areas, but can cause a hazardous situation in (partially) confined spaces, where the hydrogen can accumulate, e.g., underneath a roof. The rapid mixing of hydrogen with air can lead to flammable mixtures very quickly, but on the other hand dilute mixtures to the non- flammable range quickly too. B.2.4. Combustion Owing to its small molecule size, hydrogen is particularly prone to leakage within a system or to the surroundings. A potential fire hazard always exists when hydrogen is present and an oxidant exists due to its reactivity. A hydrogen flame is colourless. Any visibility is caused by impurities. The hydrogen properties that make it more prone to combustion are summarized as follows221:  Almost all metals and non-metals react with hydrogen at high temperatures.

 Mixtures containing 4 to 75 percent H2 by volume in air or up to 94 percent in oxygen are flammable. The detonable range is given to be 18 - 59 percent H2 in air, however, the range was found to depend on the system size.

 The minimum ignition energy is 0.02 mJ for H2-air mixtures, much lower than hydrocarbon-air mixtures. A weak spark or the electrostatic discharge by a flow of pressurized H2 gas or by a person (~10 mJ) would suffice for an ignition.  The burning velocity is 2.6 m/s for stoichiometric H2 in air and 11.8 m/s in pure oxygen, much higher than other hydrocarbon fuels because of its fast chemical kinetics and high diffusivity. Higher burning velocities produce rapid pressure rises and greater chance for a transition from deflagration to detonation (DDT).  Hydrogen produces more heat per unit mass (LHV = 120,000 kJ/kg) than any other automotive fuel, but a relatively low heating value per unit of volume unless compressed or liquefied.  At one atmosphere, the quenching distance is about 0.06 cm for hydrogen compared to 0.2 cm for propane.

Combustion of premixed H2-air mixtures can occur as a deflagration or detonation. Both forms are often regarded as an "explosion”. When hydrogen is leaked in the form of a jet, typically at a failed static or dynamic seal, the jet of hydrogen will mix with air and possibly form a jet fire (or so-called diffusion flame or standing flame). The characteristics of each combustion form are defined as follows:  A deflagration is a subsonic wave with typical velocities on the order of several meters per second. It is also an expansion wave with both pressure and density decreasing across the reaction front. The propagation of a deflagration is caused by the diffusion and convection of heat and intermediate reaction species from the flame to the unburned gas. The deflagration pressure is spatially uniform and bounded by the adiabatic isochoric (constant volume) complete combustion (AICC) pressure. For stoichiometric H2-air mixtures, the AICC pressure of confined deflagration

221 Melaina, M. W., O. Antonia, and M. Penev. 2013. “Blending Hydrogen into Natural Gas Pipeline Networks: A Review of Key Issues.” National Renewable Energy Laboratory technical report, NREL/TP-5600-51995. March.

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is 8.3 atm at ambient temperature and pressure. In contrast, the deflagration overpressure of an unconfined hydrogen-air gas cloud is in the order of 10 kPa.  A detonation, the most energetic form of combustion, is a supersonic wave, with typical velocities on the order of a few kilometers per second. It is a compression shock wave with pressure and density increasing across the wave. It is caused by heating of the unburned gas via a shock wave (created by the energy release in the reaction zone) to temperatures capable of causing ignition in the unburned gas. As a result, the reaction front is coupled to the shock wave and they propagate at the same velocity. The detonation velocity for hydrogen is in the range of 2000 m/s and the pressure ratio across a detonation wave is approximately 15 for stoichiometric H2-air mixture. A detonation can be initiated directly via strong ignition sources, such as high energy explosives, strong shock waves and high voltage discharges. However, it is more often initiated by a process that starts from a deflagration and accelerates to a fast flame and transition to detonation (so-called DDT).  Diffusion flames take place when fuel and oxidizer are physically separate so that the energy release is limited primarily by the mixing process. The fuel and oxidizer mixing may occur in two ways: (1) molecular diffusion, where mixing is relatively slow and (2) turbulent mass transfer or eddy diffusion, where mass transfer is much more rapid. Flame length is an essential measure of jet fire, which is the distance that all the jet fluid has mixed and reacted with the atmosphere. B.2.5. Material Interaction Hydrogen is relatively inert towards most solid materials that may be used to contain it. However, it is such a small molecule, it can penetrate many materials at normal temperatures. In some materials, this means it permeates and can be lost from a container. In other materials, the hydrogen can enter the material structure and change its properties. Most metallic and ceramic materials are relatively impervious to hydrogen, whereas many polymers are to some degree permeable. B.2.5.1 Hydrogen Embrittlement The mechanism of hydrogen embrittlement in structural metals is not well-understood, but it is related to the ability of hydrogen to dissociate or move around in and between the metal crystal structures. A few metals have structures that allow significant permeation of hydrogen at ambient or modest temperatures. Some of these are commonly used for containing gases and can suffer significant loss of ductility when exposed to hydrogen or if hydrogen is incorporated during fabrication. This effect is dependent on the metal microstructure, metal stress, certain impurities (metal or hydrogen), temperature and hydrogen pressure. High-strength steel is the most common material of particular concern; whereas, mild steel, austenitic stainless steel, aluminum, and copper alloys are considered to be largely safe from the effect when not exposed at high temperature. The main means of avoiding hydrogen embrittlement is by careful selection of materials and designs that limit stress concentrations. Embrittlement is most often a result of incorporation of hydrogenated compounds during welding and heat treatment rather than simple exposure to H2. B.2.5.2 Hydrogen Permeation Hydrogen can diffuse through some engineering polymers at rates sufficient to be of concern from the point of view of flammability or loss of gas. The range of permeability is very broad and can vary by at least 2 orders of magnitude between different types of polymers, but typically elastomers are significantly more permeable than rigid materials. There is normally no chemical interaction; the process is purely physical—a combination of solubility and diffusivity. In practice, the concerns will be

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT mostly at mechanical piping connections with elastomer seals (e.g. flanges) or in very high-pressure H2 storage vessels made with polymeric materials. B.3. Hazard Assessment of Hydrail System Components B.3.1. Hydrogen Production For the Hydrail project, hydrogen production is by low-temperature electrolysis of water in a large industrial installation. Water electrolysis is a very well-established technology, with very well understood process components and methods of controlling the hazards. From the electrolysis unit, the hydrogen will be compressed for storage as gas, or compressed, cooled and liquefied for storage as liquid. This, too, is a well-established industrial process. An industrial plant specifically for the sole purpose of hydrogen production is well positioned to be engineered with active and passive features to minimize hydrogen hazards for all operational and failure modes. It is standard procedure to perform a formalized hazards and operability study, Failure Modes and Effects Analysis, or both during the design of a new plant. The major concern is flammability of hydrogen and most of the hydrogen-related safety features are designed first to limit the ability of hydrogen to mix with air, then to ensure any unwanted mixing stays below the lower flammability limit and finally to avoid the presence of sources of ignition. Table B-1 briefly lists the failures, hazards and mitigation measures for hydrogen production. B.3.2. Hydrogen Storage (Production Site) B.3.2.1 Gaseous Hydrogen Gaseous storage of hydrogen is assumed to be in relatively low pressure compressed gas tanks. Weight is not an issue, so it seems logical to rule out Class III and IV, which are more expensive. Type I is the lowest cost, and generally consists of a seamless steel or aluminum tank with a maximum pressure of 25 MPa. Type II consists of a seamless metallic tank, but hoop wrapped with fibre resin to increase its maximum pressure to 45-80 MPa. Type II is more costly than Type I because of the fibre resin wrap. A quick internet search found the largest commercially available hydrogen storage tank had a capacity of showed that commercially available hydrogen storage tanks have a 15 m3 capacity (30 MPa). To meet the hydrogen storage requirements for the Hydrail project will require hundreds of these tanks. Hundreds of 30 MPa storage tanks (commercially available 30 MPa hydrogen storage tanks have a maximum capacity of about 15 m3) will be needed to store the thousands of cubic metres of hydrogen required by the Hydrail project. This will require a significant amount of piping and valving to move the hydrogen to all these distributed tanks. These tanks will also need valves (including check valves) to allow each tank to be isolated, so that in the event a pressurization event occurs for one tank and the pressure relief device or temperature/pressure relief device activates, only the affected tank will release its content. An assessment of the hazards for gaseous hydrogen storage at the production site is shown in Table B-2. Many of the failures leads to a release of hydrogen from either the storage tank or the attached components (e.g. pipes, fittings, pressure relief devices). This hydrogen release can result in a formation of a combustible cloud. The hydrogen release can also result in a standing flame at the

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT release point. Large sudden releases can also result in over-pressurization of a confined space. The general preventative measures to protect from the potential hazards for a hydrogen release are:  Located in a confined space:  Periodic inspection and leak testing  Barriers to protect against external impacts  Exclusion zone . No ignition sources . No obstructions to aid in flame acceleration/DDT . Limited personnel access  Ventilation is required to guard against hydrogen accumulation. However, Ventilation may not be sufficient for large sudden releases. Blow-out panels (needed for protection against pressurization) will need to be located to aid in venting of hydrogen.  Blow out panels to protect the confined space against pressurization due to large sudden releases of H2 or pressurization due to combustion.  Hydrogen detection and warning system  Pressure monitoring and warning system for unexpected depressurization of the component  Located in an unconfined space:  Protect from environment to ensure its mechanical integrity.  Periodic inspection and leak testing  Barriers to protect against external impacts  Exclusion zone . No ignition sources . No obstructions to aid in flame acceleration/DDT . Limited personnel access  Pressure monitoring and warning system for unexpected depressurization of the component Two other failure mechanisms need further discussion. The first is the possible introduction of air into the system to form a combustible hydrogen-air mixture within the tank/pipes. The preventative measure is to monitor for the presence of oxygen (or air) in the tanks/pipes. The second failure is related to the temperature and pressure relief devices used to protect the storage tanks from failure due to over-pressurization. They are designed to remain open once activated. Their preventative measures include limiting the vent size to adequately provide pressure protection, but also to limit the size of the hydrogen cloud. As well, the vent should be directed away from personnel, energy sources and control/safety systems. These TPRD/PRD will also require protection against ice build-up. B.3.2.2 Liquid Hydrogen Liquid hydrogen is stored at low (cryogenic, -245°C) temperatures and at pressures of 0.6 MPa. The liquid hydrogen storage is a Dewar, double-walled, vacuum-insulated vessel made of steel alloys. The inherent heat transfer from the surroundings, through the vessel walls will cause the hydrogen to evaporate/boil inside the tank. This build-up of hydrogen causes a pressure rise inside the vessel. The

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H2 is vented to maintain a vessel pressure below its normal operating pressure (about 0.6 MPa). The amount of hydrogen released vented is called boil-off. The main components of a liquid hydrogen tank are:  Double-walled, vacuum insulated vessel made of steel alloys  Shut-off devices  Boil-off system  Pressure relief devices (PRDs)  The interconnecting piping and fittings between the components NASA stores its liquid hydrogen in a 3,218 m3 vacuum bottle, which is more than 5 times the estimated amount of liquid hydrogen required for the Hydrail project. This indicates that all liquid hydrogen needed for the Hydrail project can be stored in one vessel. This would make a liquid hydrogen storage facility much simpler logistically. However, a failure of one component can result in the discharge of the entire volume of liquid hydrogen. An assessment of the hazards for liquid hydrogen storage at the production site is shown in Table B-3. A release of liquid hydrogen would vaporize upon contacting the outside environment (its vaporization rate will be dependent upon the rate of heat transfer to the liquid hydrogen) to form a relative cold H2 cloud with a possibility to form a heavier than air hydrogen cloud that can remain grounded. As well, the lower temperatures of the H2 will reduce its buoyancy and diffusion with air. Asphyxiation is more of a possibility, even in unconfined space. The resulting hydrogen cloud can also be combusted. The preventative measures for liquid hydrogen release includes:  Common:  Periodic inspection  Barriers to protect against external impacts  Exclusion zone . No ignition sources . No obstructions to aid in flame acceleration/DDT . Limited personnel access  Liquid hydrogen liquid level monitoring and warning system for unexpected loss of liquid hydrogen  Liquid hydrogen temperature monitoring and warning system for unexpected rise in temperature.  Select materials that are less susceptible to hydrogen embrittlement (low carbon, low allow and low strength steels are less susceptible)  Isolation from heat sources  Direct liquid hydrogen flow to safe areas

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 Located in a confined space:  Ventilation may not be sufficient. Blow-out panels (needed for protection against pressurization) will need to be located to aid in venting of hydrogen.  Blow out panels to protect against pressurization due to high expansion ratio for liquid hydrogen to gas.  Hydrogen detection and warning system  Located in an unconfined space:  Protect from environment to ensure its mechanical integrity. Underlying these preventative measures is the importance of maintaining the integrity of the vacuum insulation between the inner and outer walls of the liquid hydrogen storage tank. If the release path is connected to the gas space of the liquid storage system, then gaseous hydrogen will be released, but limited to the boil-off rate. The same potential hazards and preventative measures for gaseous hydrogen storage would apply. B.3.3. Hydrogen Distribution Hydrogen can be transported and distributed from a centralized production site to the consumer by compressed gas using pipelines or by compressed gas or liquid using ships, railways or road tankers. Hydrogen pipeline delivery is considered a cost-effective way to move hydrogen from its production location to end users, though usually only at large volumes. The cost to construct a large-scale, dedicated hydrogen pipeline system can be very high depending on the distance and capacity. An alternative delivery pathway for large volume and long distance is to use the existing natural gas pipelines by blending hydrogen with the natural gas222 . The pipeline delivery system usually consists of compressor stations, transmission (mains) and distribution (customers) lines, regulators and meters. The potential hazards associated with transport of gaseous hydrogen using existing natural gas pipelines are summarized in Table B-4. The primary prevention measures for the pipeline associated with fire or explosion are:  Regular in-line inspection  Leak detection or cathodic protection monitoring system  Sufficient venting in confined service areas

 Limited H2 fraction in the blends with natural gas (i.e., less than 50 percent). Road transport of gaseous hydrogen is presently carried out using trucks with steel cylinders of up to 90 litres at 200 – 250 bar pressure or large seamless cylinders called “tubes” of up to 3000 litres at 200 – 250 bar. For transport in larger scale, pressure of up to 500-600 bars or even higher may be employed. However, a 40-ton truck can only carry 400 kg compressed hydrogen because of the weight of a 200 bar pressure vessel. The gaseous hydrogen distribution by trailers consists of pressurized tubes, connection hose and PRD. The potential hazards associated with transport of pressurized gaseous hydrogen by tube trailers are summarized in Table B-5. Liquid hydrogen road transport using a cryogenic tank is carried out using trucks which can exceed a capacity of 60,000 litres. However, liquefaction process is both time consuming and energy demanding. Liquid hydrogen is difficult to store over a long period (loss by vaporization) and the

222 Rivkin, C., R. Burgess, and W. Buttner. 2015. “Hydrogen Technologies Safety Guide.” National Renewable Energy Laboratory technical report, NREL/TP-5400-60948. January.

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DATE: 02/02/2018 HYDRAIL FEASIBILITY STUDY REPORT insulated tank may be large and bulky. The liquid hydrogen delivery system consists of storage tanks (inner and outer tanks), connecting hose, heat exchanger and pressure regulating valves. The potential hazards associated with transport of liquid hydrogen by road are summarized in Table B-6. The primary prevention measures for both delivery methods associated with fire or explosion are:  Regular inspection of the storage tanks and PRD  Sufficient driver training for unloading and re-fill and operating procedure

 H2 detection system in the loading and staging area  Separation distance between loading vehicles and from H2 fill to gasoline storage B.3.4. Hydrogen Refill (Local storage at refuelling site) B.3.4.1 Gaseous Hydrogen The Hydrail project proposes to store gaseous hydrogen at refilling stations at 87.5 MPa. This can be accommodated by TYPE II and IV gaseous hydrogen storage tanks. Type II consists of a seamless metallic tank, hoop wrapped with fibre resin to increase its maximum pressure to 45-80 MPa (literature suggests that the maximum pressure for Type II tanks are unlimited). Type IV hydrogen storage tanks employ a non-metallic liner (e.g. plastic as a permeation barrier) wrapped in a fibre/epoxy matrix (for strength). Literature search indicates that most of the research/development of Type IV tanks are for use in cars, with working pressure of 70 to 80 MPa. These maximum pressures for Type II and IV tanks may not meet the Hydrail requirement to store gaseous hydrogen at 87.5 MPa. Thus, a booster compressor would be required to meet the pressure needed to fill the 70 MPa onboard storage tanks (on the trains). Type IV tanks are significantly lighter than Type II, but with a significantly higher cost. The weight of the storage tanks is not a factor for stationary hydrogen storage at a refilling station. Thus, it is recommended that gaseous hydrogen be stored in Type II hydrogen storage tanks at the refilling stations. Hazards associated with Type II gaseous hydrogen storage is already covered in Table B-2 and discussed in Section 3.2.1. The only difference being the higher-pressure tanks will result in higher hydrogen release rates from a break (in the tank wall) as compared to the gaseous hydrogen stored in lower pressures storage tanks at production sites. B.3.4.2 Liquid Hydrogen Liquid storage at the hydrogen refilling station is essentially the same as liquid hydrogen storage at the production site, except for a lower storage volume. Thus, the hazards assessment for liquid hydrogen storage (production site) shown in Table B-3 and discussed in Section 3.2.2 would apply for liquid hydrogen storage at the refilling station. B.3.5. Hydrogen Dispensing The fueling dispenser contains controls, fuel metering, and a connection from the fueling hose Error! Reference source not found.]. It draws fuel from the hydrogen refill storage tanks and the controls determine the final fill pressure on the vehicle. The dispenser meters the quantity of fuel transferred to achieve the design pressure. The potential hazards associated with dispensing gaseous hydrogen are summarized in Table B-7 and in Table B-8 for liquid hydrogen. The primary prevention measures for fire or explosion for dispensing are:  Regular inspection of the cascade control, dispensing hose and nozzle, and emergency shut offs  Leak check prior to fill  Isolation vales for breakaway connection and shut off valves for dispenser

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B.3.6. Hydrogen Vehicle (On-train use of hydrogen) The passenger train can be driven by either a single locomotive with fuel storage, fuel cells and batteries aboard, a single locomotive and a fuel tender, or an EMU consisting of separately driven units with fuel storage, fuel cells, and batteries aboard each. The hazards associated with each part of the power generation system on a train are not significantly different from the case for stationary systems such as already discussed for hydrogen storage and distribution. However, combining the equipment necessary for powering the train in a small space creates additional hazards and making them mobile with passengers nearby further complicates the safety considerations. If the greatest concern is for the large amount of hydrogen stored in the tanks, this may advocate for a design that uses a fuel tender to separate the fuel from the engine and the passengers. It may also lead to the use of gaseous storage with multiple independently isolatable tanks to limit the volume of hydrogen released from a tank rupture. In addition, compressed hydrogen stored in roof compartments helps ensure that any release is most likely to vent away from people. The potential hazards associated with the three parts of the power system are summarized in Table B-9 to Table B-11. B.3.7. Summary The potential hazards for the different component failures for the Hydrail system are outlined in Sections 3.1 to 3.6. Although there are potential hazards associated with the use of hydrogen, preventative measures are available that can be employed to prevent or mitigate the impact of the potential hazards. Thus, there are no unresolvable safety issues surrounding the use of hydrogen for the Hydrail system. Many of the failures leads to release of hydrogen that leads to formation of combustible hydrogen-air mixtures with the potential for a fire or explosion. Safety analysis will need to be performed to study hydrogen dispersion and combustion for these failures/accidents. This will require the use of qualified computer codes that are supported by validation against relevant experimental datasets.

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TABLE B-1 HAZARD ASSESSMENT OF HYDROGEN PRODUCTION Main Parts or Process Failure Consequence Potential Hazard Preventative Measure Electrolyzer unit Leak of hydrogen Unwanted release of  Combustion or explosion  Design for high integrity hydrogen  asphyxiation due to formation of a  Zone classification hydrogen cloud  Unconfined (outdoor) location or appropriately ventilated confinement Over-pressurization Unwanted release of  Combustion or explosion of hydrogen  Follow pressure code for design hydrogen  Rupture of a pressure system  Functioning PRD that is properly maintained  Zone classification  Unconfined (outdoor) location or appropriately ventilated confinement Improper operation or Mix of hydrogen and  Explosion  Adherence to purging protocols maintenance air inside system  Design for explosion pressure Freezing conditions Cell or vessel rupture  Combustion or explosion of hydrogen  Emergency heating or freeze-protection with unwanted  Rupture of a pressure system release of hydrogen Purification system Impure hydrogen  No immediate hazard  Redundancy malfunction produced  Possible safety system malfunction from  Reliable purity monitoring unexpected moisture  Possible damage to fuel cells in trains

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TABLE B-2 HAZARD ASSESSMENT OF GASEOUS HYDROGEN STORAGE (PRODUCTION SITE) Main Parts or Process Failure Consequence Potential Hazard Preventative Measure Storage tank Small opening Slow release of Located in a confined space: Common: (crack or hole) hydrogen  Combustion of a hydrogen cloud  Periodic inspection and leak testing The small leak formed in a confined space  Barriers to protect against external impacts may be difficult to  Asphyxiation due to formation of  Exclusion zone detect. a hydrogen cloud in a confined o No ignition sources space o Limited personnel access  Standing flame  Pressure monitoring and warning system for unexpected Located in an unconfined space: depressurization of the component  Standing flame Located in a confined space:  Adequate ventilation to prevent accumulation of hydrogen  Hydrogen detection and warning system Located in an unconfined space:  Protect from environment to ensure its mechanical integrity. Storage tank Large opening Rapid release of Located in a confined space: Common: (crack or hole) hydrogen  Combustion of a hydrogen cloud  Periodic inspection formed in a confined space  Barriers to protect against external impacts  Asphyxiation due to rapid  Exclusion zone formation of a hydrogen cloud in o No ignition sources a confined space o No obstructions to aid in flame acceleration/DDT  Over-pressurization of a confined space o Limited personnel access  Standing flame  Pressure monitoring and warning system for unexpected depressurization of the component Located in an unconfined space: Located in a confined space:  Combustion of a hydrogen cloud formed in an unconfined space  Ventilation is required to guard against hydrogen (duration and size of cloud will accumulation. be limited by H2 transport to the  Blow out panels to protect confined space against environment) pressurization due to large sudden releases. Blow out  Asphyxiation due to rapid panels should be located to assist in hydrogen venting formation of a hydrogen cloud  Hydrogen detection and warning system near the release. Located in an unconfined space:

 Standing flame  Protect from environment to ensure its mechanical integrity.

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TABLE B-2 HAZARD ASSESSMENT OF GASEOUS HYDROGEN STORAGE (PRODUCTION SITE) Main Parts or Process Failure Consequence Potential Hazard Preventative Measure Storage tank Hydrogen Release of Same potential hazards as small and Same preventative measures as small and large opening (crack embrittlement hydrogen large opening (crack or hole) failures or hole) failures in the storage tank, with one additional causing failure of in the storage tank. preventative measure: tank wall.  Select materials that are less susceptible to hydrogen embrittlement (low carbon, low allow and low strength steels are less susceptible) Storage tank Hydrogen Very slow leak of None Unconfined location or appropriately vented confinement permeation hydrogen Storage tank Presence of Combustible Ignition of hydrogen-air mixture  Monitor oxygen content in the storage tank and pipes oxygen inside the hydrogen air within the tank.  No ignition sources inside the tank storage tank223 mixture within the tank Pipes Crack/break in Release of Same potential hazards as small and Same preventative measures as small and large opening (crack pipe wall224 hydrogen, limited large opening (crack or hole) failures or hole) failures in the storage tank. to the critical flow in the storage tank. through the pipe diameter

Pipes Leak in pipe wall Release of H2 Same potential hazards as small Same preventative measures as small opening (crack or hole) or fittings opening (crack or hole) failure in the failure in the storage tank. storage tank.

223 Air ingress due to an accident, tank was not purged of air, or air was added to the hydrogen supply line 224 Failure can be due to hydrogen embrittlement, corrosion due to exposure to the elements, over pressurization or external forces

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TABLE B-2 HAZARD ASSESSMENT OF GASEOUS HYDROGEN STORAGE (PRODUCTION SITE) Main Parts or Process Failure Consequence Potential Hazard Preventative Measure Pipes/Valves/TP Flow Components Upstream component protected by  Foreign material exclusion program RD/PRD blockage225 upstream of the a PRD or Pressure relief valve:  Valve failure can introduce foreign materials into the blockage will  Same potential hazards as for hydrogen transport system pressurize. activation of a TPRD/PRD device.  Prevent moisture building in the hydrogen transport system Upstream component not protected or ensure hydrogen transport system are above freezing by a PRD or pressure relief point of water. valve226:  The upstream device will over- pressurize and fail. Same potential hazards as small and large opening (crack or hole) failures in the storage tank. TPRD/PRD Activation and Release of The potential hazards are the same Same preventative measures as small and large opening (crack TPRD/PRD are also false hydrogen as for small and large opening (crack or hole) failures in the storage tank, with these additional assumed to be activation (when or hole) failures in the storage tank preventative measures: piped to be pressure is at or in an unconfined space.  Sizing of venting rate from TPRD/PRD to limit the size of the discharged into below design hydrogen cloud during discharge. pressure) the  Direction of the vent should be away from people (and environment. other energy sources and control/safety systems)  Protection from environment (e.g. ice buildup)  Periodic functionality testing (this may not be possible as these devices are designed to remain open once they are activated).  Warning system for activation of TPRD/PRD

225 Foreign material inside the pipe (valves, TPRD/PRD) or pipe walls are crushed together. 226 For example, the flow blockage occurs on the downstream piping of a TPRD/PRD (which is protecting the storage tank)

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TABLE B-2 HAZARD ASSESSMENT OF GASEOUS HYDROGEN STORAGE (PRODUCTION SITE) Main Parts or Process Failure Consequence Potential Hazard Preventative Measure TPRD/PRD Fails to activate Tank over- Same potential hazards as small and Same preventative measures for activation of TPRD/PRD, with when needed pressurizes until large opening (crack or hole) failures the following additional preventative measure: either the tank wall in the storage tank, with the  Protection from missiles for surrounding cracks or a fitting following additional potential personnel/equipment. fails. hazards:  Protection from pressure pulse for surrounding  Catastrophic failure of a Type I personnel/equipment. or II storage tank resulting in: 1. Pressure pulse can damage nearby humans and equipment 2. Projectiles Pressure gauge Incorrect pressure Tank or pipes are Same potential hazards as for The preventative measures are the same as for TPRD/PRD, with reading over-pressurized TPRD/PRD. one additional preventative measures: and TPRD/PRD  Periodic inspection/testing of pressure gauge activates Valves on Fail open Tank will continue Same potential hazards as for The preventative measures are the same as for TPRD/PRD, with supply side to be filled until its TPRD/PRD. one additional preventative measures: pressure is equal to  Periodic inspection/testing of valve the supply line pressure. Worst case scenario is the TPRD/PRD activates. Valve on supply Fail closed None – system (left blank) Periodic inspection/testing of valve side designed for valve to be closed. Valves on Fail open Unwanted If the discharge end is open, then If the discharge end is open, then the preventative measures for demand side discharge of the potential hazards for the the discharge end is the same as the preventative measures for hydrogen (possibly discharge end is the same as the small and large opening (crack or hole) failures in the storage in a location with potential hazards for small and large tank, with the following additional preventative measures: people) opening (crack or hole) failures in  Redundant valves (e.g. two valves need to be opened to the storage tank. allow hydrogen flow)  Exclusion zone to limit personnel may not be possible as regular work may occur at the discharge end. So, additional

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TABLE B-2 HAZARD ASSESSMENT OF GASEOUS HYDROGEN STORAGE (PRODUCTION SITE) Main Parts or Process Failure Consequence Potential Hazard Preventative Measure safety systems will need to be in place to protect against unexpected hydrogen discharges. Fittings for Leak leak of hydrogen Same potential hazards as small Same preventative measures as small opening (crack or hole) valves/ gauges/ opening (crack or hole) failure in the failure in the storage tank, with the following additional PRV/TPRD/PRD storage tank. preventative measures:  Leak testing  Fittings and threaded sections can be wrapped with hydrogen detection tape (tape changes colour when it comes into contact with hydrogen).

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TABLE B-3 HAZARD ASSESSMENT OF LIQUID HYDROGEN STORAGE (PRODUCTION SITE) Main Parts or Process Failure Consequence Potential Hazard Preventative Measure Double-walled Leak of liquid Leakage of Common Hazards: Common: vacuum hydrogen from liquid hydrogen  Formation of a pool of liquid  Periodic inspection insulated liquid hydrogen to the hydrogen  Barriers to protect against external impacts vessel storage tank environment227  Cryogenic temperatures  Exclusion zone  Heavier than air hydrogen cloud o No ignition sources  Reduced buoyancy forces (and o No obstructions to aid in flame acceleration/DDT also lower diffusion rate) would o Limited personnel access slow dilution and dispersion  Liquid hydrogen liquid level monitoring and warning system for  Asphyxiation due to formation of unexpected loss of liquid hydrogen a low hanging hydrogen cloud  Liquid hydrogen temperature monitoring and warning system  A pool of liquid hydrogen will for unexpected rise in temperature. condense and solidify air constituents such as water vapour  Select materials that are less susceptible to hydrogen to produce oxygen-enriched embrittlement (low carbon, low allow and low strength steels zones to form shock-explosive are less susceptible) mixtures.  Isolation from heat sources Located in a confined space:  Direct liquid hydrogen flow to safe areas  Combustion of a hydrogen cloud Located in a confined space: formed in a confined space  Ventilation may not be sufficient. Blow-out panels (needed for Located in an unconfined space: protection against pressurization) will need to be located to aid  Combustion of a hydrogen cloud in venting of hydrogen. formed in an unconfined space  Blow out panels to protect against pressurization due to high (duration and size of cloud will be expansion ratio for liquid hydrogen to gas. limited by H2 transport to the  Hydrogen detection and warning system environment) Located in an unconfined space:  Protect from environment to ensure its mechanical integrity.

227 Liquid hydrogen will vaporize when exposed to ambient temperatures. It can also result in a heavier than air hydrogen cloud which can remain grounded. Failure of both walls of the vessel will also eliminate the vacuum insulation.

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TABLE B-3 HAZARD ASSESSMENT OF LIQUID HYDROGEN STORAGE (PRODUCTION SITE) Main Parts or Process Failure Consequence Potential Hazard Preventative Measure Double-walled Leak of gaseous Leakage of The potential hazards are the same The preventative measures are the same as for a small opening in vacuum hydrogen from gaseous as for a small opening in the storage the storage tank for gaseous hydrogen (Table B-4), except it does insulated liquid hydrogen hydrogen to the tank for gaseous hydrogen not require: vessel storage tank 228 environment (Table B-4)  Pressure monitoring and warning system for unexpected depressurization of the component. Additional preventative measures include:  Liquid hydrogen liquid level monitoring and warning system for unexpected loss of liquid hydrogen  Liquid hydrogen temperature monitoring and warning system for unexpected rise in temperature. Double-walled Opening in inner Leak of liquid The potential hazards are the same The preventative measures are the same as failure “Leak of liquid vacuum wall below the hydrogen to the as for failure “Leak of liquid hydrogen hydrogen from liquid hydrogen storage tank”. insulated liquid hydrogen environment229 from liquid hydrogen storage tank”. vessel level Double-walled Opening in inner Leak of gaseous The potential hazards are the same The preventative measures are the same as for failure “Leak of vacuum wall – above hydrogen to the as for failure “Leak of gaseous gaseous hydrogen from liquid hydrogen storage tank”. insulated liquid hydrogen environment230 hydrogen from liquid hydrogen vessel level storage tank”. Double-walled Hydrogen Failure of the The potential hazards are the same Select materials that are less susceptible to hydrogen vacuum embrittlement tank wall as for through vessel opening or embrittlement (low carbon, low allow and low strength steels are insulated opening in the inner wall. less susceptible) vessel Double-walled Hydrogen Very slow leak None Unconfined location or appropriately vented confinement vacuum permeation of hydrogen insulated vessel

228 Leakage of gaseous hydrogen will be limited by the boil-off rate. Failure of both walls of the vessel will also eliminate the vacuum insulation. 229 Liquid hydrogen in the vacuum space will vaporize and pressurize the vacuum space and activate the vacuum space pressure relief device. This will also result in loss of vacuum. 230 Leak of gaseous hydrogen into vacuum space will result in loss of vacuum. If pressure in the vacuum space rises sufficiently, it will activate the vacuum jacket pressure relief device and release gaseous hydrogen to the environment.

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TABLE B-3 HAZARD ASSESSMENT OF LIQUID HYDROGEN STORAGE (PRODUCTION SITE) Main Parts or Process Failure Consequence Potential Hazard Preventative Measure Double-walled Presence of Combustible Ignition of hydrogen-air mixture  Monitor oxygen content in the storage tank and pipes vacuum oxygen inside the hydrogen air within the tank.  No ignition sources. insulated storage tank231 mixture within vessel the tank Double-walled Loss of vacuum Increased boil- If the vessel pressure cannot be The preventative measures are the same as for failure “Leak of vacuum insulation232 off and venting maintained by Boil-off system, then gaseous hydrogen from liquid hydrogen storage tank”. insulated the pressure relief devices activates vessel and release hydrogen to the environment at the boil-off rate. The potential hazards are the same as for failure “Leak of gaseous hydrogen from liquid hydrogen storage tank” Pipes Crack/break in Release of The potential hazards are the same The preventative measures are the same as for failure “Leak of pipe wall233 liquid hydrogen as for failure “Leak of liquid hydrogen liquid hydrogen from liquid hydrogen storage tank”. which will from liquid hydrogen storage tank”. vaporize when exposed to ambient temperatures Pipes Loss of insulation Condensation Fire is possible when liquid oxygen  Inspection of pipe insulation of oxygen on comes into contact with organic  Remove organic matter away from pipes. exposed pipe matter surface Pipes and Leak in pipe wall Release of The potential hazards are the same The preventative measures are the same as for failure “Leak of fittings or fittings liquid hydrogen as for failure “Leak of liquid hydrogen liquid hydrogen from liquid hydrogen storage tank”. which will from liquid hydrogen storage tank”. vaporize when exposed to ambient temperatures

231 Tank was not purged of air, or air was added to the hydrogen supply line. 232 Loss of vacuum insulation can be due to leakage of air into the vacuum space which result in free convection heat transfer between the two walls (with a differential temperature difference of about 250°C. Loss of vacuum can also be due to contact between inner and outer walls to provide a direct path for conduction heat transfer. 233 Failure can be due to hydrogen embrittlement, corrosion due to exposure to the elements, over pressurization or external forces.

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TABLE B-3 HAZARD ASSESSMENT OF LIQUID HYDROGEN STORAGE (PRODUCTION SITE) Main Parts or Process Failure Consequence Potential Hazard Preventative Measure Boil-Off System Boil-off valve fails Tank pressurizes The potential hazards are the same The preventative measures are the same as for failure “Leak of to open and pressure as for failure “Leak of liquid hydrogen liquid hydrogen from liquid hydrogen storage tank”. Additional relief devices from liquid hydrogen storage tank”. preventative measure includes: are activated  Inspection and testing of boil-off system. and releases H2

Boil-Off System Boil off system Release of H2 The potential hazards are the same The preventative measures are the same as for failure “Leak of fails to oxidize the as for failure “Leak of liquid hydrogen liquid hydrogen from liquid hydrogen storage tank”. Additional hydrogen from liquid hydrogen storage tank”. preventative measure includes:  Inspection and testing of boil-off system.

Pressure relief Activation and Release of H2 The potential hazards are the same The preventative measures are the same as for activation of devices for also False as for activation of TPRD/PRD for a TPRD/PRD for a gaseous hydrogen storage tank (Table B-4). inner vessel activation (when gaseous hydrogen storage tank (liquid pressure is at or (Table B-4) hydrogen less than design storage). pressure) Pressure relief Fails to activate Inner vessel Hydrogen build-up in the vacuum  Maintenance and inspection of PRD devices for when needed burst disk opens jacket.  Periodic functionality testing (this may not be possible as these inner vessel and vacuum devices are designed to remain open once they are activated). (liquid insulation is hydrogen lost234 storage). Pressure relief False activation Results in See potential hazard for loss of  Maintenance and inspection of PRD devices for another failure vacuum insulation.  Periodic functionality testing (this may not be possible as these Outer vessel (loss of vacuum devices are designed to remain open once they are activated). (protecting the insulation) vacuum jacket). Pressure relief Activation (due to Release of Liquid hydrogen release: Common: devices for gaseous or leak of H2 or  The potential hazards are the  Sizing of venting rate from PRD to limit the size of the hydrogen Outer vessel liquid hydrogen liquid from the same as for failure “Leak of liquid cloud during discharge. (protecting the inner vessel) hydrogen from liquid hydrogen vacuum jacket).  Direction of the vent should be away from people (and other storage tank”. energy sources and control/safety systems) Gaseous hydrogen release:

234 Inner vessel over-pressurizes, activates burst disk and discharges hydrogen into the vacuum space. This results in another failure – loss of vacuum insulation.

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TABLE B-3 HAZARD ASSESSMENT OF LIQUID HYDROGEN STORAGE (PRODUCTION SITE) Main Parts or Process Failure Consequence Potential Hazard Preventative Measure  The potential hazards are the  Protection from environment (e.g. ice buildup) same as for failure “Leak of  Periodic functionality testing (this may not be possible as these gaseous hydrogen from liquid devices are designed to remain open once they are activated). hydrogen storage tank”.  Warning system for activation of TPRD/PRD Liquid hydrogen release:  The preventative measures are the same as for failure “Leak of liquid hydrogen from liquid hydrogen storage tank”. Gaseous hydrogen release:  The preventative measures are the same as for failure “Leak of gaseous hydrogen from liquid hydrogen storage tank”. Pressure relief Fails to activate Tank over- Liquid hydrogen release: Common: devices for when needed pressurizes and  The potential hazards are the  Maintenance and inspection of PRD Outer vessel 235 fails same as for failure “Leak of liquid  Periodic functionality testing (this may not be possible as these (protecting the hydrogen from liquid hydrogen devices are designed to remain open once they are activated). vacuum jacket). storage tank”. Liquid hydrogen release: Gaseous hydrogen release:  The preventative measures are the same as for failure “Leak of  The potential hazards are the liquid hydrogen from liquid hydrogen storage tank”. same as for failure “Leak of Gaseous hydrogen release: gaseous hydrogen from liquid hydrogen storage tank”.  The preventative measures are the same as for failure “Leak of gaseous hydrogen from liquid hydrogen storage tank”. Liquid level Liquid level Overfill the Could lead to pressurization of the Periodic inspection of liquid level indicator indicator indicator gives hydrogen liquid hydrogen storage container. incorrect storage hydrogen liquid container level. Valves on Valves on liquid Tank will Liquid hydrogen release: Common: liquid hydrogen fill fails continue to be  The potential hazards are the  Maintenance and inspection of valve hydrogen fill open when filled until its same as for failure “Leak of liquid  Monitor liquid fill level inside the tank hydrogen fill pressure is hydrogen from liquid hydrogen equal to the storage tank”.

235 When the outer wall fails, there will be a sudden release of the hydrogen gas to depressurize the tanks. Then hydrogen gas will be released at a steady rate that depends on the heat transfer to the liquid hydrogen.

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TABLE B-3 HAZARD ASSESSMENT OF LIQUID HYDROGEN STORAGE (PRODUCTION SITE) Main Parts or Process Failure Consequence Potential Hazard Preventative Measure return valve is supply line Gaseous hydrogen release:  Independent shutoff valve controlled by liquid level inside the closed. pressure. Worst  The potential hazards are the tank. case scenario is same as for failure “Leak of Liquid hydrogen release: the PRD gaseous hydrogen from liquid  The preventative measures are the same as for failure “Leak of activates, hydrogen storage tank”. liquid hydrogen from liquid hydrogen storage tank”. releasing hydrogen Gaseous hydrogen release:  The preventative measures are the same as for failure “Leak of gaseous hydrogen from liquid hydrogen storage tank”. Valves on Fail closed None – system (left blank) (left blank) liquid designed for hydrogen fill valve to be closed.

Hydrogen fill Fail open H2 flow down None – hydrogen return line is (left blank) return valve the fill return designed to receive hydrogen during line liquid hydrogen fill.

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TABLE B-4 HAZARD ASSESSMENT OF GASEOUS HYDROGEN DISTRIBUTION BY PIPELINES

Main Parts or Process Failure Consequence Potential Hazard Preventative Measure

Pipeline Pipeline failure due to: Leak of H2 Gas buildup in confined  Sufficient venting in confined service areas  Corrosion service areas, leading to  Leak detection or monitoring device fire or explosion  Material defect and aging  Regular in-line inspection (pipe seam, welds, gasket,  Cathodic protection monitoring system control relief equipment)  Limit H2 fraction in the blends (i.e., <50  Embrittlement percent)  Permeation

Pipeline Pipe rupture due to: Large release of H2 Fire or explosion  Shut off the main valve  Natural force (landslide, frost (limited by critical  Separation distance from the mainline to the heave, earthquake) flow for the pipe public diameter)  Third party, mechanical damage Meters Malfunction or failure Inaccurate flow rate No safety hazard Regular calibration and testing

Regulators Failure or malfunction leads to Leak of H2 through Fire or explosion Regular calibration and testing pressurize of downstream pining PRD

Emergency shut off Fail to close in a pipe rupture Large release of H2 Fire or explosion Regular service and testing valves accident

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TABLE B-5 HAZARD ASSESSMENT OF GASEOUS HYDROGEN DISTRIBUTION BY TUBE TRAILERS Main Parts or Process Failure Consequence Potential Hazard Preventative Measure

Trailer tube Tube failure due to Release of H2 to atmosphere Potential fire  H2 leak detectors road vibration  Unloading inspection  Isolation dampers to protect tank from road vibrations

Trailer tube Piping failure due to Release of H2 to the atmosphere Potential fire or explosion  Driver training vehicle impact during  Separation distance between vehicles unloading or staging  Sufficient staging area

Trailer tube Tube failure due to Release of H2 to the atmosphere Potential fire or explosion  Design should consider stations dispensing external fire both hydrogen and gasoline

 Separation distance from the H2 fill to any gasoline storage

Connection hose Leaks during Release of H2 Potential fire  Leak check when making connections attachment or  Driver training detachment  Unloading checklist/procedure

PRD Unintended open Release of H2 to atmosphere Potential fire or explosion  PRD vent through a stack on the trailer  Regular inspection and testing

PRD Fail to open in an Release of H2 to atmosphere Potential fire or explosion Regular inspection and testing of PRD accident (i.e., fire) due to tube failure

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TABLE B-6 HAZARD ASSESSMENT OF LIQUID HYDROGEN DISTRIBUTION BY ROAD Main Parts or Process Failure Consequence Potential Hazard Preventative Measure

Outer tank Mechanical failure due to road Leak of liquid H2 Potential fire  Unloading inspection vibration  H2 leak detectors  Isolation dampers to protect tank from road vibrations

Outer tank Piping failure due to vehicle impact Leak of liquid H2 Potential fire/explosion  Driving training while unloading  Separation distance of vehicles from unloading

Connecting hose Mechanical failure or improper Leak of liquid H2 Cryogenic burn  Wear Nomex suit in handling connection Potential fire/explosion connections  Leak check prior to unloading

Connecting hose Not vented prior to disconnect Leak of liquid H2 Cryogenic burn  Driver training (human error) Potential fire/explosion  Unloading checklist or procedure for cryogenics

Inner storage tank Loss of vacuum between inner and Release of gaseous H2 from Potential fire  PRD vents at elevated location outer vessel PRD

Storage tank Overfill (human error or instrument Release of liquid H2 from PRD Potential fire  PRD vents at elevated driver training failure)  Procedures for unloading cryogenics  Verification of fill level Storage tank Loss of vacuum from the liquid Release from PRD or blow Potential fire  PRD vents at elevated location storage tank jacket vacuum rupture disc and vent the  High pressure indication on storage entire contents tank Storage tank Boil off due to low filling Release from PRD  Wider storage pressure range in LH2 tank  Identify alternate use of boil off

Heat exchanger Fail to function leads to icing on Cold H2 vapor blows through Potential fire  Stack vents at elevated location outside causes loss of heating compressor seals vents to  Low temperature shutoff switch or stack valve in the vaporizer discharge piping

Pressure regulating Fail to function Release of H2 due to damage Potential fire  Low pressure switch shuts down valve of compressor seals compressor

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TABLE B-7 HAZARD ASSESSMENT OF GASEOUS HYDROGEN DISPENSING

Main Parts or Process Failure Consequence Potential Hazard Preventative Measure

Dispensing piping Piping rupture due to vehicle Release of H2 Potential fire or explosion Barriers around dispenser impact

Dispensing cascade PRD on dispenser and Release of H2 from PRD due to Potential fire or explosion Regular inspection and testing control storage tank fails overpressure of vehicle fuel tank

Dispensing hose Break due to mechanical Release of H2 Potential fire or explosion Regular inspection and testing failure

Dispensing hose Rupture due to drive-away Release of H2 Potential fire or explosion Isolation valves for breakaway while connected with the connection nozzle

Dispensing nozzle Mechanical failure, improper Leak of H2 Potential fire Leak check prior to fill and or improper connection, detection system

Dispensing nozzle Leak after disconnect due to Leak of H2 Potential fire Shut off valve for dispenser mechanical failure

Emergency shutoffs Malfunction Release of H2 in an accident Fire or explosion Regular inspection and testing

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TABLE B-8 HAZARD ASSESSMENT OF LIQUID HYDROGEN DISPENSING

Main Parts or Process Failure Consequence Potential Hazard Preventative Measure

Dispensing piping Piping rupture due to vehicle Release of liquid H2 Potential fire or Barriers around dispenser impact explosion

Dispensing cascade PRD on dispenser and storage Release of liquid H2 from PRD Potential fire or Regular inspection and testing control tank fails due to overpressure of fuel tank explosion

Dispensing hose Break due to mechanical failure Release of liquid H2 Cryogenic burn, Regular inspection and testing Potential fire or explosion

Dispensing hose Rupture due to drive-away Release of liquid H2 Potential fire or Isolation valves for breakaway connection while connected with the nozzle explosion

Dispensing nozzle Mechanical failure (O-ring Leak of liquid H2 Cryogenic burn,  Detection system damage) or improper potential fire  Leak check prior to fill and personnel connection barrier

Dispensing nozzle Vent lever open while filling Leak of liquid H2 Cryogenic burn, potential Three‐way valve to flow H2 only when filling fire

Dispensing nozzle Leak after disconnect due to Leak of liquid H2 Potential fire Shut off valve for dispenser mechanical failure

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TABLE B-9 HAZARD ASSESSMENT OF FUEL CELL ON BOARD Main Parts or Process Failure Consequence Potential Hazard Preventative Measure Fuel Cell unit Leak of hydrogen Unwanted  Fire or explosion  Design for high integrity release of  Zone classification hydrogen  Fire-resistant confinement with appropriate ventilation PRD failure Overpressure or  Blast or missiles from rupture of pressure  Regular inspection and testing release of system hydrogen  Fire or explosion Fuel cell membrane Mix air and  Fire or explosion  Shut down fuel supply on detection of break break hydrogen  Component fire Insulation or isolation Live components  Electrocution  Trained personnel breakdown  Burn  Multiple barriers  Minimize working voltage Low temperature Freeze-up  Blast or missiles from rupture of pressure  Insulation system  Emergency heating  Fire or explosion  Freeze-tolerant design Impact damage Release  Blast or missiles from rupture of pressure  Design for impact tolerance hydrogen system  Isolation from personnel  Fire or explosion

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TABLE B-10 HAZARD ASSESSMENT OF GASEOUS AND LIQUID FUEL STORAGE ON BOARD Main Parts or Process Failure Consequence Potential Hazard Preventative Measure Hydrogen tanks Leak of hydrogen Unwanted  Combustion or explosion  Design for high integrity release of  asphyxiation due to formation of a hydrogen  Zone classification hydrogen cloud  Fire-resistant confinement with appropriate ventilation PRD PRD failure Overpressure or  Blast or missiles from rupture of pressure  Regular inspection and testing release of system hydrogen  Fire or explosion Liquid tanks Loss of cryo-insulation Overpressure or  Blast or missiles from rupture of pressure  Regular inspection and testing (vacuum) release of system  Overpressure vent to safe location hydrogen  Fire or explosion System Impact damage Unwanted  Combustion or explosion  Design for high integrity release of  Blast or missiles from rupture of pressure  Zone classification hydrogen & system  Fire-resistant confinement with appropriate sparks  asphyxiation due to formation of a hydrogen ventilation cloud  Design for impact resistance  Multiple separate tanks to limit volume of release System External fire Overpressure or  Blast or missiles from rupture of pressure  Overpressure vent to safe location release of system  Heat-resistant confinement with appropriate hydrogen  Fire or explosion ventilation  Vented hydrogen

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TABLE B-11 HAZARD ASSESSMENT OF FUEL AND POWER MANAGEMENT SYSTEM Main Parts or Process Failure Consequence Potential Hazard Preventative Measure Fuelling system Leak of hydrogen Unwanted  Combustion or explosion  Design for high integrity release of  asphyxiation due to formation of a hydrogen  Zone classification hydrogen cloud  Unconfined (outdoor) location or appropriately ventilated confinement Impact damage Release of  Combustion or explosion  Effective fire rated separations on-board hydrogen  Battery fire Shorted batteries PRD PRD failure Overpressure or  Rupture of pressure system  Regular inspection and testing release of  Fire or explosion hydrogen

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Appendix C – Ontario Rail Sector

This section provides an overall description of Ontario’s rail sector, including its geography, organizational structure, and bilateral arrangements in the context of regulations and legislation. This sets the background for the sections on system design, regulations and standards, and implementation. C.1.1. Rail Market and Regulatory Overview The Ontario Rail Market is served by a multitude of different passenger and freight service providers that can be grouped in different sectors, as follows:  National Operators: VIA Rail (VIA), CP, and CN  International Services: Amtrak, CN, CP, and CSX Corporation  Regional Passenger and Freight Operators: Ontario Northland Railway and KWG Resources (KWG)  Regional Passenger Operators: GO, Union Pearson (UP) Express, Algoma Central Railway, and Moose Consortium Inc. (Moose)  Local and Regional Freight Operators: Cando Ltd, Essex Terminal Railway, Goderich Exeter Railway, Huron Central Railway, Ontario Southland Railway, Ottawa Valley Railway, Port Colborne Harbour Railway, Southern Ontario Railway, Vale Railway (Vale), and VIP Rail  Tourist Services: Agawa Canyon Tour Train, Credit Valley Explorer, Huntsville & Lake of Bays Railway, Port Stanley Terminal Railway, and many other operators dedicated to a single operating site  Metros and Trams: Toronto Transit Commission (TTC) Metro and streetcars or light rail vehicles (LRVs), Ottawa O-train light rapid transit (LRT), and in the near future, the Confederation Line and other upcoming LRV service expansion in Waterloo Some of those service providers may be able to operate under special operating conditions or adaptation of existing rules, but this is only possible if they operate on their own dedicated rail network, have no interaction with other rolling stock equipment, or both. This is not the case for Metrolinx RER, one of the largest infrastructure programs ever undertaken by the Government of Ontario that will transform how people move across the Greater Toronto and Hamilton Area (GTHA). As demonstrated on Figure , the GO rail network already interacts with multiple rail network and rolling stock technologies.

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FIGURE C-1 GO RAIL NETWORK OPERATOR MAP

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As such, any new equipment that needs to be introduced on this corridor, including new passenger coaches or new powered cars (diesel, electric, hybrid hydrogen, or any other propulsion mode), will need to meet a list of existing Canadian regulatory requirements, standards, and recommended practices. For example, as a minimum, rolling stock equipment will need to be designed to comply with the following:  Railway Safety Act (RSA), including locomotive emissions regulations  Transport Canada standards, including:  Transport Canada Railway Locomotive Inspection and Safety Rules  Transport Canada TC-O-0-26 Railway Passenger Car Inspection and Safety Rules  Rules for the Installation and Testing of Air Reservoirs (Other than on Locomotive)  Railway Freight and Passenger Train Brake Inspection and Safety Rules  Rules Respecting Track Safety (TC E-54)  Standards Respecting Railway Clearances (TC E-05)  Railway Safety Appliance Standards Regulations, Canadian Transport Commission General Order Number (No.) O-10  Canadian Transportation Agency (CTA) standards  Canada Labour Code  Canadian Environmental Protection Act  Canada Occupational Safety and Health Regulations (OSHA)  Onboard Trains Occupational Health and Safety  Accessibility for Ontarians with Disabilities Act (AODA)  CSA standards Because some of the equipment operated on the GO network has been designed with United States (U.S.) standards, and because those requirements are not necessarily covered by Canadian regulations, the U.S. ADA, as well as the following U.S. organizations’ standards, or portions of them, would also be applicable to new equipment design:  American Public Transportation Association (APTA)  National Fire Protection Association (NFPA)  U.S. Environmental Protection Agency  FRA  Association of American Railroads (AAR)  ASTM International (ASTM)  In addition to these requirements, Metrolinx may also have their own sets of O&M guidelines or specific requirements that will also need to be considered for all new rolling stock equipment.

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C.1.2. The GO Transit Network Since May 1967, GO has evolved from a single GO train line along Lake Ontario’s shoreline into an extensive network of train lines and bus routes. GO operates seven train lines - Lakeshore West, Milton, Kitchener, Barrie, Richmond Hill, Stouffville, and Lakeshore East - serving 64 stations over 488 route-kilometres (km), as illustrated on Figure . GO also operates an air-rail link, called the UP Express. This service operates every 15 minutes between Union Station and Pearson Airport, with a journey time of 25 minutes.

FIGURE C-2 GO TRANSIT OPERATIONAL LINES

Although GO owns most of its operating network, it also needs to operate on infrastructure owned and operated by CN and CP, as previously depicted on Figure (refer to Section 4.1.1). Table C-1 presents the track ownership for all corridors operated by GO, expressed in kilometres of tracks for each segment. Over the entire 488-km network, 390 km, or 80 percent, of GO operates on infrastructure it owns. Lakeshore East, Barrie, Stouffville, and UP Express are 100 percent owned, meaning there are no additional requirements before new equipment can be tested or enter into passenger revenue service on those corridors, as described in Section 4.1.1. This is not the case for Lakeshore West, Milton, Kitchener, and Richmond Hill corridors that need to be operated on infrastructure owned by either CN or CP, or both. For those cases, additional reviews, inspections, and approvals will be required by the owner(s) of the infrastructure before the equipment would be allowed to operate. CN transports more than $250 billion worth of goods annually for a wide range of business sectors, ranging from resource products, to manufactured products, to consumer goods, across a rail network of approximately 32,000 route-km spanning Canada and mid-America.

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The following list illustrates the type of data and test results required by equipment manufacturers before any passenger train equipment can be considered for operation on any CN rail lines:  Dimensional data  Wheelset and suspension standards  Clearance outline  Journal bearing heat detection  Track-train dynamics  Track circuit shunting and detection of wheel sets, and activation of signals  Truck curving force performance  Brake equipment  Curve negotiation  Safety appliances  Vertical track impact forces  Propulsion system  Structural strength  Prior service experience  Coupling compatibility Similar considerations are also required for CP.

TABLE C-1 TRACK OWNERS FOR EACH GO TRANSIT OPERATED CORRIDOR GO CN CP Total Line (km) Lakeshore West 51.4 8.3 4.5 64.2 Lakeshore East 50.1 0.0 0.0 50.1 Milton 7.4 0.0 42.8 50.2 Kitchener 81.5 21.0 0.0 102.5 Barrie 101.2 0.0 0.0 101.2 Richmond Hill 25.6 20.8 0.0 46.4 Stouffville 48.7 0.0 0.0 48.7 UP Express 24.5 0.0 0.0 24.5 Total 390.4 50.1 47.3 487.8

This partial ownership by the freight railroads limits the expansion capability beyond the current RER electrification scenario, as shown on Figure , to a completely electrified solution. The need to carry double-stacked containers on the freight railroads is the primary reason why those sections of the network cannot be electrified.

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FIGURE C-3 RER CURRENT ELECTRIFICATION SCENARIO236

The network is also shared with VIA and Amtrak. Although they do have access to a portion of the network, and some of the Union Station tracks and platforms are dedicated for their operation, because they do not own any of this infrastructure, they do not impose any specific requirements to the rolling stock technology that can be operated on GO. VIA is currently considering replacing its existing aging fleet in the Quebec-Windsor corridor. Given the current electrification projects in the Montreal and Toronto area, and potential construction of new electrified tracks to offer high-frequency intercity rail service, VIA is also considering the procurement of a trainset that could operate in diesel and electric modes. If electrification was not implemented in the Toronto area, this could modify or simplify the technology that VIA is presently specifying, and would require operation in diesel mode in the Toronto area.

236 Metrolinx. 2015. GO RER Initial Business Case. Accessed October 2017. http://www.metrolinx.com/en/regionalplanning/projectevaluation/benefitscases/GO_RER_Initial_Business_Case_EN.pdf

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Appendix D – Summary of Inputs for Socio Economic Impacts with Key Assumptions

D.1. RER Electrification Table D-1 indicates the OPEX divided into the IO categories for the model.

TABLE D-1 OPEX BREAKDOWN FOR RER ELECTRIFICATION SOCIO-ECONOMIC IMPACTS Operating Total Costs 237 Costs ($M) Breakdown SUPC Crew Costs 3,869.52 100 percent PRM500000 Wages and salaries Labour PRM600000 Employers' social contributions

Diesel Fuel 1,483.08 100 percent ENE324112 Diesel and biodiesel fuels Material Electricity for 1,562.39 100 percent ENE221100 Electricity Traction Material Rolling Stock 5,927.45 70 percent PRM500000 Wages and salaries Maintenance Labour PRM600000 Employers' social contributions

30 percent MPG3241A8 Lubricants and other petroleum refinery products Materials MPG325500 Paints, coatings and adhesive products MPG326107 Motor vehicle plastic parts Glass (including automotive), glass products and glass MPG327A02 containers MPG332303 Metal windows and doors MPG332A05 Other architectural metal products MPG332402 Boilers, tanks and heavy gauge metal containers MPG332600 Springs and wire products Threaded metal fasteners and other turned metal products MPG332700 including automotive Hand tools, kitchen utensils and cutlery (except precious MPG332A01 metal) MPG332A02 Metal valves and pipe fittings MPG332A08 Fabricated metal products, n.e.c. MPG335909 Other electrical equipment and components MPG336502 Parts of railway rolling stock MPG336900 Other transportation equipment and related parts

237 Input structure for IO industry BS485100 - Urban transit systems, based on the 2014 Supply and use tables for Ontario. For all costs except for Infrastructure Maintenance materials.

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TABLE D-1 OPEX BREAKDOWN FOR RER ELECTRIFICATION SOCIO-ECONOMIC IMPACTS Operating Total Costs 237 Costs ($M) Breakdown SUPC Infrastructure 3,397.96 70 percent PRM500000 Wages and salaries Maintenance Labour 238 PRM600000 Employers' social contributions

9 percent MPG212310 Stone metal and MPG212320 Sand, gravel, clay, and refractory minerals grading gravel MPG331100 Iron and steel basic shapes and ferro-alloy products MPG331201 Iron and steel pipes and tubes (except castings) MPG331202 Wire and other rolled and drawn steel products MPG331303 Basic and semi-finished products of aluminum and alloys MPG331501 Ferrous metal castings MPG332101 Forged and stamped metal products MPG332301 Prefabricated metal buildings and components MPG332302 Fabricated steel plates and other fabricated structural metal MPG332A05 Other architectural metal products MPG332402 Boilers, tanks and heavy gauge metal containers MPG332500 Builders, motor vehicle and other hardware Threaded metal fasteners and other turned metal products MPG332700 including automotive MPG332A08 Fabricated metal products, n.e.c.

9 percent MPG334209 Other communications equipment communicati on/ signaling equipment 12 percent MPG335902 Communication and electric wire and cable electrical MPG335903 Wiring devices

wiring User 1,092.73 100 percent PRM800000 Gross operating surplus Charges - Other Plant & Roadway Other 14,231.70 66 percent PRM500000 Wages and salaries Labour PRM600000 Employers' social contributions

8 percent MPS541100 Legal services Contractors/ Accounting, tax preparation, bookkeeping and payroll professional MPS541200 services fees MPS541300 Architectural, engineering and related services MPS541400 Specialized design services

238 Input structure for IO industry BS23D000 - Repair construction, based on the 2014 Supply and use tables for Ontario

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TABLE D-1 OPEX BREAKDOWN FOR RER ELECTRIFICATION SOCIO-ECONOMIC IMPACTS Operating Total Costs 237 Costs ($M) Breakdown SUPC Computer systems design and related services (except MPS541503 software development) MPS541600 Management, scientific and technical consulting services MPS541800 Advertising, public relations and related services MPS541901 Photographic services MPS541909 Other professional, scientific and technical services

2 percent MPS524102 Accident and sickness insurance services insurance MPS524103 Automotive insurance services MPS524104 Property insurance services MPS524105 Liability and other property and casualty insurance services

19 percent ENE221100 Electricity electricity 4 percent ENE211102 Natural gas Gas 1 percent MPS221301 Water delivered by water works and irrigation systems water Operating 35,094 100 percent PRM800000 Gross operating surplus Surplus Other

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Table D-2 indicates the capital costs divided into the IO categories for the model:

TABLE D-2 CAPEX BREAKDOWN FOR RER ELECTRIFICATION SOCIO-ECONOMIC IMPACTS Capital 239 Costs Total Costs Breakdown SUPC Infrastructure $4,917 30 percent PRM500000 Wages and salaries Labour PRM600000 Employers' social contributions

55 percent MPG111400 Nursery and floriculture products Materials ENE211102 Natural gas ENE211103 Natural gas liquids and related products ENE212100 Coal MPG212310 Stone MPG212320 Sand, gravel, clay, and refractory minerals MPG21239C Non-metallic minerals (except diamonds) ENE221100 Electricity MPS221301 Water delivered by water works and irrigation systems MPS221302 Sewage and dirty water disposal and cleaning services MPS23D000 Repair construction services MPG31A005 Textile products, n.e.c. MPG31B001 Men's, women's, boys' and girls' clothing MPG31B003 Clothing accessories MPG31B005 Footwear MPG31B006 Suitcases, handbags and other leather and allied products MPG321101 Hardwood lumber MPG321102 Softwood lumber MPG321104 Other sawmill products and treated wood products MPG321201 Veneer and plywood MPG321203 Reconstituted wood products MPG321901 Wood windows and doors Prefabricated wood and manufactured (mobile) buildings MPG321904 and components MPG321908 Wood products, n.e.c. MPG322102 Paper (except newsprint) MPG322201 Paperboard containers MPG322202 Paper office supplies MPG322204 Sanitary paper products MPG322209 Other converted paper products

239 Investment in Infrastructure and Property uses Input structure for IO industry BS23C100 - Transportation engineering construction, based on the 2014 supply and use tables for Ontario except for Electrification.

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TABLE D-2 CAPEX BREAKDOWN FOR RER ELECTRIFICATION SOCIO-ECONOMIC IMPACTS Capital 239 Costs Total Costs Breakdown SUPC MPG323001 Printed products ENE324111 Gasoline ENE324112 Diesel and biodiesel fuels ENE324113 Light fuel oils ENE324115 Heavy fuel oils MPG3241A8 Lubricants and other petroleum refinery products MPG3241A1 Asphalt (except natural) and asphalt products MPG325101 Petrochemicals MPG325102 Industrial gases MPG325106 Other basic inorganic chemicals MPG325105 Basic organic chemicals, n.e.c. MPG325400 Pharmaceutical and medicinal products MPG325500 Paints, coatings and adhesive products MPG325601 Soaps and cleaning compounds MPG325900 Chemical products, n.e.c. MPG326103 Plastic and foam building and construction materials MPG326105 Foam products (except for construction) MPG326106 Plastic bottles MPG326107 Motor vehicle plastic parts MPG326109 Plastic products, n.e.c. MPG326201 Tires MPG326202 Rubber and plastic hoses and belts MPG326209 Rubber products, n.e.c. MPG327301 Cement MPG327302 Ready-mixed concrete MPG327303 Concrete products MPG327A01 Clay and ceramic products and refractories Glass (including automotive), glass products and glass MPG327A02 containers MPG327A09 Non-metallic mineral products, n.e.c. MPG331100 Iron and steel basic shapes and ferro-alloy products MPG331201 Iron and steel pipes and tubes (except castings) MPG331202 Wire and other rolled and drawn steel products MPG331303 Basic and semi-finished products of aluminum and alloys MPG331501 Ferrous metal castings MPG332101 Forged and stamped metal products

CPG-PGM-RPT-245 329 Revision B

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TABLE D-2 CAPEX BREAKDOWN FOR RER ELECTRIFICATION SOCIO-ECONOMIC IMPACTS Capital 239 Costs Total Costs Breakdown SUPC MPG332301 Prefabricated metal buildings and components MPG332302 Fabricated steel plates and other fabricated structural metal MPG332303 Metal windows and doors MPG332A05 Other architectural metal products MPG332401 Light gauge metal containers, crowns and closures MPG332402 Boilers, tanks and heavy gauge metal containers MPG332500 Builders, motor vehicle and other hardware MPG332600 Springs and wire products Threaded metal fasteners and other turned metal products MPG332700 including automotive Hand tools, kitchen utensils and cutlery (except precious MPG332A01 metal) MPG332A02 Metal valves and pipe fittings MPG332A03 Ball and roller bearings MPG332A08 Fabricated metal products, n.e.c. MPG333101 Agricultural, lawn and garden machinery and equipment MPG333102 Logging, mining and construction machinery and equipment MPG333200 Other industry-specific machinery MPG333300 Commercial and service industry machinery Industrial and commercial fans, blowers and air purification MPG333401 equipment Heating and cooling equipment (except household MPG333402 refrigerators and freezers) MPG333601 Turbines, turbine generators, and turbine generator sets MPG333609 Other engine and power transmission equipment MPG333901 Pumps and compressors (except fluid power) MPG333902 Material handling equipment MPG333909 Other miscellaneous general-purpose machinery MPG334100 Computers, computer peripherals and parts MPG334201 Telephone apparatus MPG334209 Other communications equipment MPG334A05 Medical devices MPG334A06 Measuring, control and scientific instruments MPG334409 Other electronic components MPG335101 Electric light bulbs and tubes MPG335102 Lighting fixtures MPG335203 Small electric appliances

CPG-PGM-RPT-245 330 Revision B

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TABLE D-2 CAPEX BREAKDOWN FOR RER ELECTRIFICATION SOCIO-ECONOMIC IMPACTS Capital 239 Costs Total Costs Breakdown SUPC MPG335204 Major appliances MPG335301 Power, distribution and other transformers MPG335302 Electric motors and generators Switchgear, switchboards, relays and industrial control MPG335303 apparatus MPG335901 Batteries MPG335902 Communication and electric wire and cable MPG335903 Wiring devices MPG335909 Other electrical equipment and components Motor vehicle electrical and electronic equipment and MPG336320 instruments MPG336330 Motor vehicle steering and suspension components MPG336340 Motor vehicle brakes and brake systems Medical, dental and personal safety supplies, instruments MPG339100 and equipment MPG339904 Office supplies (except paper) MPG339905 Signs MPG339909 Other miscellaneous manufactured products Custom work manufacturing services (except printing, MPS3X0000 finishing textiles and metals)

15 percent MPS541300 Architectural, engineering and related services Design Costs Electrification $2,091 30 percent PRM500000 Wages and salaries 240 Labour capex PRM600000 Employers' social contributions

20 percent is MPG335902 Communication and electric wire and cable for the overhead Catenary 19 percent is MPG334209 Other communications equipment for signal immunization 8 percent is MPG335301 Power, distribution and other transformers for the electrification substation (transformers) 8 percent is ENE211102 Natural gas for regular ENE211103 Natural gas liquids and related products construction

240 Investment in Electrification uses Input structure for IO industry BS23C300 - Electric power engineering construction, based on the 2014 Supply and use tables for Ontario.

CPG-PGM-RPT-245 331 Revision B

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TABLE D-2 CAPEX BREAKDOWN FOR RER ELECTRIFICATION SOCIO-ECONOMIC IMPACTS Capital 239 Costs Total Costs Breakdown SUPC ENE212100 Coal MPG212310 Stone MPG212320 Sand, gravel, clay, and refractory minerals MPG21239C Non-metallic minerals (except diamonds) ENE221100 Electricity MPS221301 Water delivered by water works and irrigation systems MPS221302 Sewage and dirty water disposal and cleaning services ENE221303 Steam and heated or cooled air or water MPS23D000 Repair construction services MPG31A005 Textile products, n.e.c. MPG31B001 Men's, women's, boys' and girls' clothing MPG31B005 Footwear MPG31B006 Suitcases, handbags and other leather and allied products MPG321102 Softwood lumber MPG321104 Other sawmill products and treated wood products MPG321202 Wood trusses and engineered wood members MPG321203 Reconstituted wood products MPG321901 Wood windows and doors Prefabricated wood and manufactured (mobile) buildings MPG321904 and components MPG321908 Wood products, n.e.c. MPG322102 Paper (except newsprint) MPG322201 Paperboard containers MPG322202 Paper office supplies MPG322204 Sanitary paper products MPG322209 Other converted paper products MPG323001 Printed products ENE324111 Gasoline ENE324112 Diesel and biodiesel fuels ENE324113 Light fuel oils ENE324115 Heavy fuel oils MPG3241A8 Lubricants and other petroleum refinery products MPG3241A1 Asphalt (except natural) and asphalt products MPG325101 Petrochemicals MPG325105 Basic organic chemicals, n.e.c. MPG325400 Pharmaceutical and medicinal products

CPG-PGM-RPT-245 332 Revision B

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TABLE D-2 CAPEX BREAKDOWN FOR RER ELECTRIFICATION SOCIO-ECONOMIC IMPACTS Capital 239 Costs Total Costs Breakdown SUPC MPG325500 Paints, coatings and adhesive products MPG325601 Soaps and cleaning compounds MPG325900 Chemical products, n.e.c. MPG326103 Plastic and foam building and construction materials MPG326107 Motor vehicle plastic parts MPG326109 Plastic products, n.e.c. MPG326201 Tires MPG326202 Rubber and plastic hoses and belts MPG326209 Rubber products, n.e.c. MPG327301 Cement MPG327302 Ready-mixed concrete MPG327303 Concrete products MPG327A01 Clay and ceramic products and refractories Glass (including automotive), glass products and glass MPG327A02 containers MPG327A09 Non-metallic mineral products, n.e.c. MPG331201 Iron and steel pipes and tubes (except castings) MPG331202 Wire and other rolled and drawn steel products MPG331303 Basic and semi-finished products of aluminum and alloys Basic and semi-finished products of non-ferrous metals and MPG331406 alloys (except aluminum) MPG331501 Ferrous metal castings MPG332101 Forged and stamped metal products MPG332301 Prefabricated metal buildings and components MPG332302 Fabricated steel plates and other fabricated structural metal MPG332303 Metal windows and doors MPG332A05 Other architectural metal products MPG332401 Light gauge metal containers, crowns and closures MPG332402 Boilers, tanks and heavy gauge metal containers MPG332500 Builders, motor vehicle and other hardware MPG332600 Springs and wire products Threaded metal fasteners and other turned metal products MPG332700 including automotive Hand tools, kitchen utensils and cutlery (except precious MPG332A01 metal) MPG332A02 Metal valves and pipe fittings MPG332A03 Ball and roller bearings

CPG-PGM-RPT-245 333 Revision B

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TABLE D-2 CAPEX BREAKDOWN FOR RER ELECTRIFICATION SOCIO-ECONOMIC IMPACTS Capital 239 Costs Total Costs Breakdown SUPC MPG332A08 Fabricated metal products, n.e.c. MPG333101 Agricultural, lawn and garden machinery and equipment MPG333102 Logging, mining and construction machinery and equipment MPG333200 Other industry-specific machinery MPG333300 Commercial and service industry machinery Industrial and commercial fans, blowers and air purification MPG333401 equipment Heating and cooling equipment (except household MPG333402 refrigerators and freezers) MPG333601 Turbines, turbine generators, and turbine generator sets MPG333609 Other engine and power transmission equipment MPG333901 Pumps and compressors (except fluid power) MPG333902 Material handling equipment MPG333909 Other miscellaneous general-purpose machinery MPG334100 Computers, computer peripherals and parts MPG334201 Telephone apparatus MPG334A05 Medical devices MPG334A06 Measuring, control and scientific instruments MPG334409 Other electronic components MPG335101 Electric light bulbs and tubes MPG335102 Lighting fixtures MPG335203 Small electric appliances MPG335204 Major appliances MPG335302 Electric motors and generators Switchgear, switchboards, relays and industrial control MPG335303 apparatus MPG335901 Batteries MPG335903 Wiring devices MPG335909 Other electrical equipment and components Motor vehicle electrical and electronic equipment and MPG336320 instruments MPG336330 Motor vehicle steering and suspension components MPG336340 Motor vehicle brakes and brake systems Medical, dental and personal safety supplies, instruments MPG339100 and equipment MPG339904 Office supplies (except paper) MPG339905 Signs

CPG-PGM-RPT-245 334 Revision B

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TABLE D-2 CAPEX BREAKDOWN FOR RER ELECTRIFICATION SOCIO-ECONOMIC IMPACTS Capital 239 Costs Total Costs Breakdown SUPC MPG339909 Other miscellaneous manufactured products Custom work manufacturing services (except printing, MPS3X0000 finishing textiles and metals)

15 percent MPS541300 Architectural, engineering and related services Design Costs Property $281 60 percent N/A Property 35 percent is Real estate brokerage and other services related to real for MPS531A00 estate consultants MPS541100 Legal services Accounting, tax preparation, bookkeeping and payroll MPS541200 services MPS541400 Specialized design services Computer systems design and related services (except MPS541503 software development) MPS541600 Management, scientific and technical consulting services MPS541800 Advertising, public relations and related services MPS541901 Photographic services MPS541909 Other professional, scientific and technical services

5 percent is MPS524103 Automotive insurance services for insurance MPS524104 Property insurance services MPS524105 Liability and other property and casualty insurance services

Carparking $740 30 percent PRM500000 Wages and salaries Labour PRM600000 Employers' social contributions

55 percent MPG111400 Nursery and floriculture products Materials MPG212310 Stone MPG212320 Sand, gravel, clay, and refractory minerals MPG3241A1 Asphalt (except natural) and asphalt products MPG327301 Cement MPG327302 Ready-mixed concrete MPG334209 Other communications equipment

15 percent MPS541300 Architectural, engineering and related services Design Costs Fleet $6,751 100 percent Locomotives, railway rolling stock, and rapid transit Material MPG336501 equipment

$2,599 30 percent PRM500000 Wages and salaries Labour PRM600000 Employers' social contributions

CPG-PGM-RPT-245 335 Revision B

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TABLE D-2 CAPEX BREAKDOWN FOR RER ELECTRIFICATION SOCIO-ECONOMIC IMPACTS Capital 239 Costs Total Costs Breakdown SUPC Other 13 percent is MPG334209 Other communications equipment network for the CBTC CAPEX signaling system 30 percent MPG23B001 Industrial buildings for construction of buildings 12 percent MPG111400 Nursery and floriculture products for parking MPG212310 Stone MPG212320 Sand, gravel, clay, and refractory minerals MPG3241A1 Asphalt (except natural) and asphalt products MPG327301 Cement MPG327302 Ready-mixed concrete

15 percent MPS541300 Architectural, engineering and related services Design Costs

CPG-PGM-RPT-245 336 Revision B

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D.2. Hydrail Table D-3 has the OPEX divided into the IO categories for the model for only the OPEX that are different in the Hydrail Model:

TABLE D-3 OPEX BREAKDOWN FOR HYDRAIL SOCIO-ECONOMIC IMPACTS Operating Costs Total 241 (Millions) Costs Breakdown SUPC Electricity for $3,820.00 100 percent Material ENE221100 Electricity Traction Infrastructure $4,313.81 70 percent Labour PRM500000 Wages and salaries 242 Maintenance PRM600000 Employers' social contributions

305.8 mil on MPG212310 Stone communication/ MPG212320 Sand, gravel, clay, and refractory minerals signaling equipment from RER maintenance Iron and steel basic shapes and ferro-alloy (same $ as RER) MPG331100 products Iron and steel pipes and tubes (except MPG331201 castings) Wire and other rolled and drawn steel MPG331202 products Basic and semi-finished products of MPG331303 aluminum and alloys MPG331501 Ferrous metal castings MPG332101 Forged and stamped metal products Prefabricated metal buildings and MPG332301 components Fabricated steel plates and other MPG332302 fabricated structural metal MPG332A05 Other architectural metal products Boilers, tanks and heavy gauge metal MPG332402 containers Builders, motor vehicle and other MPG332500 hardware Threaded metal fasteners and other turned metal products including MPG332700 automotive MPG332A08 Fabricated metal products, n.e.c.

305.8 mil MPG334209 Other communications equipment communication/ signaling equipment (same $ as RER)

241 Input structure for IO industry BS485100 - Urban transit systems, based on the 2014 Supply and use tables for Ontario. For all costs with the exception of Infrastructure Maintenance materials. 242 Input structure for IO industry BS23D000 - Repair construction, based on the 2014 Supply and use tables for Ontario

CPG-PGM-RPT-245 337 Revision B

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TABLE D-3 OPEX BREAKDOWN FOR HYDRAIL SOCIO-ECONOMIC IMPACTS Operating Costs Total 241 (Millions) Costs Breakdown SUPC 10 percent on MPG333200 Other industry-specific machinery electrolyzer 12 percent on fuel cells MPG335901 Batteries

5 percent on storage Boilers, tanks and heavy gauge metal tanks MPG332402 containers

4 percent on fuel MPG212310 Stone stations MPG212320 Sand, gravel, clay, and refractory minerals MPG31A005 Textile products, n.e.c. MPG31B005 Footwear Suitcases, handbags and other leather and MPG31B006 allied products MPG321102 Softwood lumber Other sawmill products and treated wood MPG321104 products MPG321201 Veneer and plywood Wood trusses and engineered wood MPG321202 members MPG321203 Reconstituted wood products MPG321901 Wood windows and doors Prefabricated wood and manufactured MPG321904 (mobile) buildings and components MPG321908 Wood products, n.e.c. MPG322102 Paper (except newsprint) MPG322201 Paperboard containers MPG322202 Paper office supplies MPG322209 Other converted paper products MPG323001 Printed products ENE324111 Gasoline ENE324112 Diesel and biodiesel fuels ENE324113 Light fuel oils ENE324115 Heavy fuel oils Lubricants and other petroleum refinery MPG3241A8 products Asphalt (except natural) and asphalt MPG3241A1 products MPG325101 Petrochemicals MPG325102 Industrial gases MPG325105 Basic organic chemicals, n.e.c. MPG325400 Pharmaceutical and medicinal products MPG325500 Paints, coatings and adhesive products MPG325601 Soaps and cleaning compounds MPG325900 Chemical products, n.e.c.

CPG-PGM-RPT-245 338 Revision B

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TABLE D-3 OPEX BREAKDOWN FOR HYDRAIL SOCIO-ECONOMIC IMPACTS Operating Costs Total 241 (Millions) Costs Breakdown SUPC MPG326102 Plastic films and non-rigid sheets Plastic and foam building and construction MPG326103 materials MPG326104 Plastic profile shapes MPG326109 Plastic products, n.e.c. MPG326202 Rubber and plastic hoses and belts MPG326209 Rubber products, n.e.c. MPG327301 Cement MPG327302 Ready-mixed concrete MPG327303 Concrete products MPG327A01 Clay and ceramic products and refractories Glass (including automotive), glass MPG327A02 products and glass containers MPG327A04 Lime and gypsum products MPG327A09 Non-metallic mineral products, n.e.c. Iron and steel basic shapes and ferro-alloy MPG331100 products Iron and steel pipes and tubes (except MPG331201 castings) Wire and other rolled and drawn steel MPG331202 products Basic and semi-finished products of MPG331303 aluminum and alloys MPG331501 Ferrous metal castings MPG332101 Forged and stamped metal products Prefabricated metal buildings and MPG332301 components Fabricated steel plates and other MPG332302 fabricated structural metal MPG332303 Metal windows and doors MPG332A05 Other architectural metal products Boilers, tanks and heavy gauge metal MPG332402 containers MPG332500 Builders, motor vehicle and other hardware MPG332600 Springs and wire products Threaded metal fasteners and other turned MPG332700 metal products including automotive Coating, engraving, heat treating and MPS332800 similar metal processing services Hand tools, kitchen utensils and cutlery MPG332A01 (except precious metal) MPG332A02 Metal valves and pipe fittings MPG332A03 Ball and roller bearings

CPG-PGM-RPT-245 339 Revision B

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TABLE D-3 OPEX BREAKDOWN FOR HYDRAIL SOCIO-ECONOMIC IMPACTS Operating Costs Total 241 (Millions) Costs Breakdown SUPC MPG332A08 Fabricated metal products, n.e.c. Agricultural, lawn and garden machinery MPG333101 and equipment Logging, mining and construction MPG333102 machinery and equipment MPG333200 Other industry-specific machinery Commercial and service industry MPG333300 machinery Industrial and commercial fans, blowers MPG333401 and air purification equipment Heating and cooling equipment (except MPG333402 household refrigerators and freezers) Metalworking machinery and industrial MPG333500 moulds Turbines, turbine generators, and turbine MPG333601 generator sets Other engine and power transmission MPG333609 equipment Pumps and compressors (except fluid MPG333901 power) MPG333902 Material handling equipment Other miscellaneous general-purpose MPG333909 machinery Computers, computer peripherals and MPG334100 parts MPG334201 Telephone apparatus MPG334209 Other communications equipment MPG334A05 Medical devices Measuring, control and scientific MPG334A06 instruments MPG334409 Other electronic components MPG335101 Electric light bulbs and tubes MPG335102 Lighting fixtures MPG335203 Small electric appliances MPG335204 Major appliances MPG335301 Power, distribution and other transformers MPG335302 Electric motors and generators Switchgear, switchboards, relays and MPG335303 industrial control apparatus MPG335901 Batteries Communication and electric wire and MPG335902 cable MPG335903 Wiring devices

CPG-PGM-RPT-245 340 Revision B

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TABLE D-3 OPEX BREAKDOWN FOR HYDRAIL SOCIO-ECONOMIC IMPACTS Operating Costs Total 241 (Millions) Costs Breakdown SUPC Other electrical equipment and MPG335909 components Motor vehicle electrical and electronic MPG336320 equipment and instruments Motor vehicle steering and suspension MPG336330 components MPG336340 Motor vehicle brakes and brake systems MPG337101 Wood kitchen cabinets and counter tops MPG339904 Office supplies (except paper) MPG339905 Signs Other miscellaneous manufactured MPG339909 products Custom work manufacturing services (except printing, finishing textiles and MPS3X0000 metals)

2 percent insurance MPS524102 Accident and sickness insurance services MPS524103 Automotive insurance services MPS524104 Property insurance services Liability and other property and casualty MPS524105 insurance services

19 percent electricity ENE221100 Electricity

4 percent Gas ENE211102 Natural gas

1 percent water Water delivered by water works and MPS221301 irrigation systems

Operating $31,920 100 percent Other PRM800000 Gross operating surplus Surplus

Table D-4 has the OPEX divided into the IO categories for the model for only the CAPEX that are different in the Hydrail Model.

CPG-PGM-RPT-245 341 Revision B

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TABLE D-4 CAPEX BREAKDOWN FOR HYDRAIL SOCIO-ECONOMIC IMPACTS Capital Costs Total (Millions) 243 Costs Breakdown SUPC Electrification $5,237 25 percent Labour PRM500000 Wages and salaries capex244 PRM600000 Employers' social contributions

15 percent is for electrolyzer MPG333200 Other industry-specific machinery

18 percent is for fuel cells MPG335901 Batteries

7 percent is for storage tanks Boilers, tanks and heavy gauge metal MPG332402 containers

5 percent is for fuelling MPG23B001 Industrial buildings stations 30 percent Design Costs Architectural, engineering and related MPS541300 services

Fleet $6,443 100 percent Material Locomotives, railway rolling stock, and MPG336501 rapid transit equipment

243 Investment in Infrastructure and Property uses Input structure for IO industry BS23C100 - Transportation engineering construction, based on the 2014 Supply and use tables for Ontario with the exception of Electrification. 244 Investment in Electrification uses Input structure for IO industry BS23C300 - Electric power engineering construction, based on the 2014 Supply and use tables for Ontario.

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Appendix E – List of Contacted Organizations

Organization HQ location Main focus of the business Air Liquide Paris, France Production and distribution of gaseous assets (argon, oxygen, nitrogen, helium and hydrogen) to large industries and healthcare sectors Air Products Allentown, Pennsylvania, US Supply of LNG process technology and equipment; atmospheric and process gases and related equipment to manufacturing markets (including refining and petrochemical, metals, electronics, and food and beverage) Bae Systems - HybriDrive London, UK Hybrid electric power and propulsion transit solutions Ballard Burnaby, BC Fuel cell power solutions for transit, automotive, rail, infrastructure and defence sectors

BC Ministry of Energy and Mining Fort St John, BC BC's electricity, alternative energy, mining and petroleum resources sectors Change Energy Services Oakville, ON End-to-end compressed gas fuelling solutions Clean Fuel Systems Brampton, ON Hydrogen systems integration CSA Mississauga, ON Development of codes and standards CUTRIC Toronto, ON Canadian urban transit and innovation Electrovaya Mississauga, ON Development and manufacture of portable lithium-ion battery power solutions for the automotive, power grid, medical and mobile device sectors Enbridge Gas Toronto, ON Natural Gas Distribution General Motors Detroit, Michigan, US Design, manufacturing, market and distribution of vehicles and vehicle parts Hexagon Composites Aalesund, Norway Supply of composite pressure cylinders and systems for gas applications HTEC Vancouver, BC Build and operation of renewable electrolysis and industrial by-product streams facilities for hydrogen production Hydrogen Business Council - Canadian hydrogen industry Hydrogenics Mississauga, ON Industrial and commercial hydrogen generation, fuel cells and energy storage solutions Independent Electricity System Toronto, ON Ontario Electricity System Operation Operator (IESO)

Infrastructure Ontario Toronto, ON Renewal of major public sector infrastructure in Ontario (including land development and real estate)

ITM South Yorkshire, UK Integrated hydrogen solutions manufacturing National Research Council Ottawa, ON Market-driven research and development National Resources Canada Ottawa, ON Development of public policy focussed on the use of national natural resources (including energy, mining, forest, climate change etc.)

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Organization HQ location Main focus of the business Next Hydrogen Mississauga, ON Water electrolysis Ontario Power Generation Toronto, ON Electricity generation in the Province of Ontario Powertech Labs Surrey, BC Testing and research of utility generation, transmission and distribution power systems Queens University Kingston, ON Academic research Ryerson University Toronto, ON Academic research Transport Canada Ottawa, ON Development of regulations, policies and services of transportation in Canada Tugliq Energy Montreal, QC Alternative energy infrastructure (wind, LNG and hydrogen) for Northern communities University of Birmingham Birmingham, UK Academic research University of British Columbia Vancouver, BC Academic research University of Ontario Oshawa, ON Academic research University of Quebec Quebec City Academic research University of Toronto Toronto, ON Academic research University of Waterloo Waterloo, ON Academic research

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