Attachment 2 — Burbank City Council, July 25, 2023 (part 1 of 2)

Transit Fleet Electrification
Feasibility Study for the Arroyo
Verdugo Region Transit
Operators
Bryan Lee, CALSTART
Katrina Sutton, CALSTART
Kristian Jokinen, CALSTART
February 2022
White Paper

WHITE PAPER
Attachment 2 - BurbankBus Bus Electrification Feasibility Study ATTACHMENT 2-1
CALSTART | Transit Fleet Electrification Feasibility Study for the Arroyo Verdugo Transit Operators ii Acknowledgments
The authors would like to thank key CALSTART staff for their contributions to the report, including Sara Stith, Nestor Cruz, Narayan Gopinathan, and Mia Fahad. The authors would also like to thank Emily Varnell, Justin Slosky, and Dan Welch for providing a critical review of and additions to this report. Any errors are the authors’ own.
© Copyright 2022 CALSTART

CALSTART
www.CALSTART.org
@CALSTART
Attachment 2 - BurbankBus Bus Electrification Feasibility Study ATTACHMENT 2-2
CALSTART | Transit Fleet Electrification Feasibility Study for the Arroyo Verdugo Transit Operators iii Table of Contents
Acknowledgments ................................ ................................ ................................ ................................ ................................ ................................ ................ ii List of Acronyms ................................ ................................ ................................ ................................ ................................ ................................ .................. vi Figures and Tables ................................ ................................ ................................ ................................ ................................ ................................ ............... ix Section I: Executive Summary ................................ ................................ ................................ ................................ ................................ ............................. 1 Section I: Project Introduction and Technology Overview ................................ ................................ ................................ ................................ ............... 5 Project Description ................................ ................................ ................................ ................................ ................................ ................................ .......................... 5 AVTO Overview ................................ ................................ ................................ ................................ ................................ ................................ ................................ . 5 ZEB Overview ................................ ................................ ................................ ................................ ................................ ................................ ................................ ...... 7 Charging Infrastructure ................................ ................................ ................................ ................................ ................................ ................................ ................ 12 Charging and Fueling Cost Considerations ................................ ................................ ................................ ................................ ................................ ............... 22 Route Modelling Overview ................................ ................................ ................................ ................................ ................................ ................................ ............ 25 Resiliency ................................ ................................ ................................ ................................ ................................ ................................ ................................ ......... 26 Maintenance and Training ................................ ................................ ................................ ................................ ................................ ................................ ............. 31 Estimated Costs ................................ ................................ ................................ ................................ ................................ ................................ .............................. 40 Financing Strategies & Resources ................................ ................................ ................................ ................................ ................................ .............................. 40 Section II: The Pasadena Department of Transportation Executive Summary ................................ ................................ ................................ ........... 48 Section II: The Pasadena Department of Transportation ................................ ................................ ................................ ................................ .............. 50 The Pasadena Department of Transportation Overview ................................ ................................ ................................ ................................ ......................... 50 The Pasadena Department of Transportation Fleet and Bus Depot ................................ ................................ ................................ ................................ ..... 53 Energy Analysis ................................ ................................ ................................ ................................ ................................ ................................ ............................... 53 Fleet Replacement Plan................................ ................................ ................................ ................................ ................................ ................................ ................. 62 Attachment 2 - BurbankBus Bus Electrification Feasibility Study ATTACHMENT 2-3
CALSTART | Transit Fleet Electrification Feasibility Study for the Arroyo Verdugo Transit Operators

Utility Analysis ................................ ................................ ................................ ................................ ................................ ................................ ................................ 67 Charging and Hydrogen Infrastructure Analysis ................................ ................................ ................................ ................................ ................................ ....... 71 Resiliency ................................ ................................ ................................ ................................ ................................ ................................ ................................ ......... 75 Financial Analysis and Cost Estimates ................................ ................................ ................................ ................................ ................................ ........................ 77 Financing Strategy ................................ ................................ ................................ ................................ ................................ ................................ ......................... 82 Implementation Plan ................................ ................................ ................................ ................................ ................................ ................................ ...................... 85 Section III: City of Glendale Executive Summary ................................ ................................ ................................ ................................ ........................... 89 Section III: City of Glendale ................................ ................................ ................................ ................................ ................................ ............................... 91 City of Glendale Overview ................................ ................................ ................................ ................................ ................................ ................................ ............. 91 City of Glendale Fleet and Bus Depot ................................ ................................ ................................ ................................ ................................ ......................... 92 Energy Analysis ................................ ................................ ................................ ................................ ................................ ................................ ............................... 92 Fleet Replacement Plan................................ ................................ ................................ ................................ ................................ ................................ ................. 99 Utility Analysis ................................ ................................ ................................ ................................ ................................ ................................ ............................. 100 Infrastructure Analysis ................................ ................................ ................................ ................................ ................................ ................................ ................ 103 Resiliency ................................ ................................ ................................ ................................ ................................ ................................ ................................ ....... 107 Financial Analysis and Cost Estimates ................................ ................................ ................................ ................................ ................................ .....................108 Financing Strategy ................................ ................................ ................................ ................................ ................................ ................................ ....................... 113 Implementation Plan ................................ ................................ ................................ ................................ ................................ ................................ ..................... 117 Section IV: BurbankBus Executive Summary ................................ ................................ ................................ ................................ ................................ 119 Section IV: BurbankBus ................................ ................................ ................................ ................................ ................................ ................................ ... 121 BurbankBus Overview................................ ................................ ................................ ................................ ................................ ................................ .................. 121 BurbankBus Fleet and Bus Depots ................................ ................................ ................................ ................................ ................................ ............................ 122 Energy Analysis ................................ ................................ ................................ ................................ ................................ ................................ ............................. 123 Fleet Replacement Plan................................ ................................ ................................ ................................ ................................ ................................ ............... 126 BEB Charging Cost Analysis ................................ ................................ ................................ ................................ ................................ ................................ ....... 127 Charging and Hydrogen Fueling Infrastructure Analysis ................................ ................................ ................................ ................................ ...................... 134 Resiliency ................................ ................................ ................................ ................................ ................................ ................................ ................................ ....... 137 Bus Depot Site Analysis ................................ ................................ ................................ ................................ ................................ ................................ .............. 140 Financial Analysis & Cost Estimates................................ ................................ ................................ ................................ ................................ ......................... 142 Financing Strategy ................................ ................................ ................................ ................................ ................................ ................................ ....................... 144 Implementation Plan ................................ ................................ ................................ ................................ ................................ ................................ .................... 147 Section V: Executive Summary................................ ................................ ................................ ................................ ................................ ....................... 149 Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-4
CALSTART | Transit Fleet Electrification Feasibility Study for the Arroyo Verdugo Transit Operators v Section V: Sustainability and Environmental Impact ................................ ................................ ................................ ................................ .................... 151 Emissions Comparisons ................................ ................................ ................................ ................................ ................................ ................................ ............... 151 Battery Recycling ................................ ................................ ................................ ................................ ................................ ................................ ......................... 159 Fuel Cell Stack/Module Recycling ................................ ................................ ................................ ................................ ................................ ............................ 160 Appendix A: Zero Emission Bus Specifications ................................ ................................ ................................ ................................ ............................ 162 Appendix B: Charging Infrastructure Specifications ................................ ................................ ................................ ................................ ..................... 171 Appendix C: Hydrogen Fueling Infrastructure Specifications ................................ ................................ ................................ ................................ ..... 183 Appendix D: Managed Charging Solutions ................................ ................................ ................................ ................................ ................................ .... 185 Appendix E: Energy Storage Options ................................ ................................ ................................ ................................ ................................ ............. 189 Appendix F: The Pasadena Department of Transportation Route Modelling Results ................................ ................................ ............................... 201 Appendix G: Pasadena Department of Transportation Service Changes ................................ ................................ ................................ ................... 207 Appendix H: City of Glendale Route Modelling Results ................................ ................................ ................................ ................................ ............... 209 Appendix I: BurbankBus Route Modelling Results ................................ ................................ ................................ ................................ ....................... 218 Appendix J: Resiliency Methodology ................................ ................................ ................................ ................................ ................................ .............. 220 Appendix K: The Pasadena Department of Transportation Conceptual Framework and Supporting Documents ................................ ................ 222 Appendix L: City of Glendale Conceptual Design and Supporting Documents................................ ................................ ................................ .......... 231 Appendix M: BurbankBus Conceptual Design and Supporting Documents ................................ ................................ ................................ ............... 238 Appendix N: Cost Estimates Methodology ................................ ................................ ................................ ................................ ................................ .... 244 Appendix O: LCFS Calculation Methodology ................................ ................................ ................................ ................................ ................................ . 250 Appendix P: Sustainability Calculations Methodology................................ ................................ ................................ ................................ ................. 253 Appendix Q: The Pasadena Department of Transportation Stakeholder Engagement and Outreach Summary ................................ ................... 255 Appendix R: City of Glendale Stakeholder Engagement and Outreach Summary ................................ ................................ ................................ .... 257 Appendix S: BurbankBus Stakeholder Engagement and Outreach Summary ................................ ................................ ................................ ........... 258 References................................ ................................ ................................ ................................ ................................ ................................ ........................ 260 Attachment 2 - BurbankBus Bus Electrification Feasibility Study ATTACHMENT 2-5
CALSTART | Transit Fleet Electrification Feasibility Study for the Arroyo Verdugo Transit Operators vi List of Acronyms
AC Alternating Current
AQMD South Coast Air Quality Management District
AVTO Arroyo Verdugo Transit Operators
BEB Battery Electric Bus
BTM Behind-the-Meter
BWP Burbank Water and Power
CAISO California Independent System Operator
CalACT California Association for Coordinated Transportation CARB California Air Resources Board
CCS Combined Charging System
CEC California Energy Commission
CH4
CLEEN
Methane
California Lending for Energy and Environmental Needs
CMAQ Congestion Mitigation and Air Quality
CNG Compressed Natural Gas
CO Carbon Monoxide
CO2 Carbon Dioxide
CPUC California Public Utilities Commission
DAC Disadvantaged Community
DC Direct Current
DCFC Direct Current Fast Charge
DER Distributed Energy Resource
DGS California Department of General Services
DOE U.S. Department of Energy
EBCM Electric Bus Corridor Model
EMFAC Emission Factor Model
EnergIIZE Energy Infrastructure Incentives for Zero-Emission Commercial Vehicles EV Electric Vehicle
EVITP Electric Vehicle Infrastructure Training Program
Attachment 2 - BurbankBus Bus Electrification Feasibility Study ATTACHMENT 2-6
CALSTART | Transit Fleet Electrification Feasibility Study for the Arroyo Verdugo Transit Operators vii EVSE Electric Vehicle Supply Equipment
FCEB Fuel Cell Electric Bus
ft Feet
FTA Federal Transit Administration
FTM In Front-of-the-Meter
GGRF Greenhouse Gas Reduction Fund
GHG Greenhouse Gas
GIS Geographic Information System
GREET Greenhouse Gases, Regulated Emissions, and Energy use in Technologies Model GVWR Gross Vehicle Weight Rating
GWh Gigawatt-hour
GWP Glendale Water and Power
HDRSAM Heavy-Duty Refueling Station Analysis Model
HVAC Heating, Ventilation, and Air Conditioning
HVIP Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project IAAS Infrastructure-as-a-Service
iBank Infrastructure and Economic Development Bank
ICT
ISRF
IIJA
Innovative Clean Transit
Infrastructure State Revolving Fund
Infrastructure Investment and Jobs Act
ITC Investment Tax Credit
JPL Jet Propulsion Laboratory
Kg Kilogram
kV Kilovolt
KVA Kilovolt-ampere
kW Kilowatt
kWh Kilowatt-hour
L2 AC Charging at 240V and at least 6 kW
LACTOA Los Angeles County Transit Operators Association LADOT Los Angeles Department of Transportation
LADWP Los Angeles Department of Water and Power
lbs Pounds
LCFS Low Carbon Fuel Standard
LCTOP Low Carbon Transit Operations Program
Low-No Low or No Emissions Program
MDT Microgrid Design Toolkit
Metro Los Angeles Metro
MW Megawatt
MWh Megawatt-hour
N20 Nitrous Oxide
NFPA National Fire Protection Association
NOx Nitrogen Oxide
NREL National Renewable Energy Laboratory
OCPP Open Charge Point Protocol
OEM Original Equipment Manufacturer
OSHA Occupational Safety and Health Administration
Attachment 2 - BurbankBus Bus Electrification Feasibility Study ATTACHMENT 2-7
CALSTART | Transit Fleet Electrification Feasibility Study for the Arroyo Verdugo Transit Operators viii PEM Proton Exchange Membrane
PM Particulate Matter
PM10 Particulate Matter - 10 micrometers and smaller
PM2.5 Particulate Matter - 2.5 micrometers and smaller
PPA Power Purchasing Agreement
PSPS Public Safety Power Shutoffs
PWP Pasadena Water and Power
PV Photovoltaic
RAISE Rebuilding American Infrastructure with Sustainability and Equity RFID Radio Frequency Identification
RFP Request For Proposal
RNG Renewable Natural Gas
SaaS Software-as-a-Service
SAE Society of Automotive Engineers
SARTA Stark Area Regional Transit Authority
SCE Southern California Edison
SCPPA Southern California Public Power Authority
SCRTTC Southern California Regional Transit Training Consortium SMR Steam Methane Reforming
SOC State of Charge
SOx Sulfur Oxides
STURAA Surface Transportation and Uniform Relocation Assistance Act of 1987 TAP Transit Access Pass
TIRCP Transit and Intercity Rail Capital Program
TOU Time-of-Use
WCCoE West Coast Center of Excellence in Zero Emission Technology ZEB Zero Emission Bus
Attachment 2 - BurbankBus Bus Electrification Feasibility Study ATTACHMENT 2-8
CALSTART | Transit Fleet Electrification Feasibility Study for the Arroyo Verdugo Transit Operators

Figures and Tables

Figures
Figure 1-1: Map of AVTO’s Service Area
Figure 1-2: Map of DACs (CalEnviroScreen 4.0, 2021)
Figure 1-3: Plug-in Chargers Example
Figure 1-4: Buses Parked in Lanes Example (Source: ABB) Figure 1-5: Overhead Plug-in Charging Example (Source: Burns McDonnell Foothill Transit In-Depot Charging and Planning Study) Figure 1-6: In-Depot Overhead Charging Example (Source: CALSTART) Figure 1-7: In-Depot Overhead Charging Example (Source: CALSTART) Figure 1-8: Inductive Charging Example (Source: Momentum Dynamics) Figure 1-9: On-route Overhead Charging (ABB)
Figure 1-10: Light-Duty Hydrogen Fueling Station at 124 South Lake Street, Burbank, CA (Source: CALSTART) Figure 1-11: True Zero Light-Duty Hydrogen Fueling Station (Source: CALSTART) Figure 1-12: Map of Retail Fueling Stations in the Los Angeles Area (Source: California Fuel Cell Partnership) Figure 1-13: EV Peak Power Demand Scenarios (CALSTART, 2015) Figure 1-14: Typical Hydrogen Contaminants (CARB, 2016) Figure 1-15: Historical LCFS Prices January 2016 – May 2021 (Source: SRECTrade) Figure 2-1: Pasadena Dial-A-Ride Service Area
Figure 2-2: Pasadena Transit Service Area
Figure 2-3: Pasadena Transit Weekday Operating Schedule (Scenario 1) Figure 2-4: Pasadena Transit Weekend Operating Schedule (Scenario 1) Figure 2-5: Pasadena Transit Weekday Operating Schedule (Scenario 2) Figure 2-6: Pasadena Transit Weekend Operating Schedule (Scenario 2) Figure 2-7: The Pasadena Department of Transportation Fleet Replacement Plan Figure 2-8: Scenario 1 ZEB Rollout Plan
Figure 2-9: Scenario 2 ZEB Rollout Plan
Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-9
CALSTART | Transit Fleet Electrification Feasibility Study for the Arroyo Verdugo Transit Operators

Figure 2-10: Scenario 1 Load Schedule
Figure 2-11: Scenario 2 Load Schedule
Figure 2-12: The Pasadena Department of Transportation Transit Facility Construction Timeline Figure 2-13: Disadvantaged Communities In Pasadena (CalEnviroScreen 3.0) Figure 2-14: Pasadena Transit Routes Serving Disadvantaged Communities Figure 3-1: Glendale Beeline Scenario 1 Weekday Operations Schedule Figure 3-2: Glendale Beeline Weekend Operations Schedule Figure 3-3: Glendale Beeline Scenario 2 Weekday Operations Schedule Figure 3-4: Glendale Beeline Fleet Replacement Plan
Figure 3-5: GWP Electric Utility Operating Statistics (GWP, 2020) Figure 4-1: BurbankBus Fixed-Route Fleet Bus Shifts
Figure 4-2: BurbankBus Fleet Replacement Plan
Figure 4-3: Senior and Disabled Fleet Load Schedule
Figure 4-4: Fixed-Route Fleet Load Schedule
Figure 4-5: Fixed-Route Fleet 150 kW Charging Load Schedule Figure 4-6: Combined Fleet Load Schedule
Figure 4-7: Combined Fleet Load Schedule – 150 kW Charging (Option B) Figure 4-8: Solar Potential at the 124 South Lake Street Depot Figure 4-9: Victory Place and Lincoln Street Lot
Figure 4-10: 323 South Front Street, Burbank, California 91502 Figure 4-10: 323 South Front Street, Burbank, California 91502 Figure K-1: Pasadena Department of Transportation Single-Line Diagram Figure K-2: The Pasadena Department of Transportation Design Memo Figure L-1: Glendale Beeline Conceptual Design and Single-Line Diagram Figure L-2: Glendale Beeline Design Memo
Figure M-1: BurbankBus Site 1 Conceptual Design and Single-Line Diagram Figure M-2: BurbankBus Site 2: Conceptual Design and Single-Line Diagram

Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-10
CALSTART | Transit Fleet Electrification Feasibility Study for the Arroyo Verdugo Transit Operators

Tables
Table ES-1: Daily Energy Consumption and Power Demand
Table ES-2: Estimated Costs to Transition to a ZEB Fleet Table 1-1. Customizable parameters that are inputs to the EBCM Table 1-2: Daily Energy Consumption and Power Demand
Table 1-3: ZEB Maintenance and Operator Training Costs
Table 1-4: Estimated Costs to Transition to a ZEB Fleet Table 1-5: Battery Leasing Options
Table 2-1: Pasadena Dial-A-Ride Fleet Bus Demonstration Parameters Table 2-2: The Pasadena Department of Transportation's Dial-A-Ride Service Daily Energy Needs Analysis Table 2-3: Pasadena Transit Fixed-Route Fleet EBCM Parameters Table 2-4: Pasadena Transit Weekday Service (Scenario 1) Table 2-5: Pasadena Transit Weekend Service (Scenario 1) Table 2-6: Hydrogen Fuel Analysis for FCEBs
Table 2-7: Pasadena Transit Scenario 2 Weekday Service
Table 2-8: Pasadena Transit Scenario 2 Weekend Service
Table 2-9: Pasadena Transit Route 51/52 Bus Demonstration Parameters Table 2-10: The Pasadena Department of Transportation Route 51/52 Daily Energy Needs Analysis Table 2-11: Scenario 1 Utility Analysis (150 kW charging) Table 2-12: Scenario 2 Utility Analysis (150 kW charging) Table 2-13: Hydrogen Cost Analysis – Scenario 1
Table 2-14: Hydrogen Cost Analysis – Scenario 2
Table 2-15: RNG Fleet Financial Analysis
Table 2-16: BEB Fleet Financial Analysis (Scenario 1)
Table 2-17: BEB Fleet Financial Analysis (Scenario 2)
Table 2-18: Hydrogen Production Pathways Financial Analysis Table 2-19: FCEB Financial Analysis (Scenario 1)
Table 2-20: FCEB Financial Analysis (Scenario 2)
Table 2-21: Pasadena Transit Fixed-Route Fleet LCFS Credit Value – Scenario 1 (displacing diesel fuel) Table 2-22: Pasadena Transit Fixed-Route Fleet LCFS Credit Value – Scenario 2 (displacing diesel fuel) Table 2-23: Pasadena Dial-A-Ride Fleet LCFS Credit Value (displacing gasoline fuel) Table 3-1: The City of Glendale's Dial-A-Ride Fleet Bus Demonstration Parameters Table 3-2: City of Glendale's Daily Energy Needs Analysis for Dial-A-Ride Fleet Service Table 3-3: Glendale Beeline Fixed-Route Fleet EBCM Parameters Table 3-4: Glendale Beeline Energy Analysis for Scenario 1 Weekday Regular Service Table 3-5: Glendale Beeline Energy Analysis Weekend Service Table 3-6: Hydrogen Fuel Analysis for FCEBs
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CALSTART | Transit Fleet Electrification Feasibility Study for the Arroyo Verdugo Transit Operators

xii

Table 3-7: Glendale Beeline Energy Analysis for Scenario 2 Weekday Extended Service Table 3-8: City of Glendale Scenario 1 Utility Cost Projections Table 3-9: City of Glendale Scenario 2 Utility Cost Projections Table 3-10: Hydrogen Cost Analysis – Scenario 1
Table 3-11: Hydrogen Cost Analysis – Scenario 2
Table 3-12: CNG Bus Financial Analysis
Table 3-13: BEB Fleet Financial Analysis (Scenario 1)
Table 3-14: BEB Fleet Financial Analysis (Scenario 2)
Table 3-15: Hydrogen Production Pathways Financial Analysis Table 3-16: FCEB Fleet Financial Analysis (Scenario 1)
Table 3-17: FCEB Fleet Financial Analysis (Scenario 2)
Table 3-18: Glendale Beeline's Fixed-Route Fleet LCFS Credit Value – Scenario 1 (displacing diesel fuel) Table 3-19: Glendale Beeline's Fixed-Route Fleet LCFS Credit Value – Scenario 2 (displacing diesel fuel) Table 3-20: Glendale Dial-A-Ride Fleet LCFS Credit Value (displacing gasoline) Table 4-1: BurbankBus Senior and Disabled Fleet Demonstration Parameters Table 4-2: BurbankBus Daily Energy Needs Analysis for Senior and Disabled Fleet Service Table 4-3: BurbankBus Fixed-Route Fleet EBCM Parameters Table 4-4: BurbankBus Daily Energy Needs Analysis for Fixed-Route Service Table 4-5: Hydrogen Fuel Analysis for FCEBs
Table 4-6: Senior and Disabled Fleet Annual Utility Costs (Option A) Table 4-7: Fixed-Route Fleet Annual Utility Costs - Plug-in Charging Annual Utility Costs (Option A) Table 4-8: Fixed-Route Fleet Annual Utility Costs – 150 kW Charging Annual Utility Costs (Option A) Table 4-9: Combined Fleet Annual Utility Costs – Plug-in Charging (Option B) Table 4-10: Combined Fleet Annual Utility Costs – 150 kW Charging (Option B) Table 4-11: Hydrogen Cost Analysis
Table 4-12: CNG Fleet Financial Analysis
Table 4-13: BEB Fleet Financial Analysis
Table 4-14: Hydrogen Production Pathways Financial Analysis Table 4-15: FCEB Fleet Financial Analysis
Table 4-16: Fixed-Route Fleet LCFS Credit Value (displacing diesel fuel) Table 4-17: Senior and Disabled Fleet LCFS Credit Value (displacing gasoline fuel) Table 5-1: Emissions Calculations for the Pasadena Department of Transportation Scena rio 1 Table 5-2: Emissions Calculations for the Pasadena Department of Transportation Scenario 2 Table 5-3: Emissions Calculations for Glendale Beeline Scenario 1 Table 5-4: Emissions Calculations for Glendale Beeline Scenario 2 Table 5-5: Emissions Calculations for BurbankBus
Table 5-6: Projected Emissions from CNG Buses Operated by the Pasadena Dep artment of Transportation Scenario 1 Table 5-7: Projected Emissions from CNG Buses Operated by Pasadena Department of Transportation Scenario 2 Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-12
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Table 5-8: Projected Emissions from CNG Buses Operated by Glendale Beeline Scenario 1 Table 5-9: Projected Emissions from CNG buses Operated by Glendale Beeline Scenario 2 Table 5-10: Projected Emissions from CNG Buses Operated by BurbankBus Table 5-11: Projected Emissions from RNG Buses Operated by the Pasadena Department of Transportation Scenario 1 Table 5-12: Projected Emissions from RNG Buses Operated by the Pasadena Department of Transportation Scenario 2 Table F-1: The Pasadena Department of Transportation Route 10 Modelling Results Table F-2: The Pasadena Department of Transportation Route 20 Modelling Results Table F-3: The Pasadena Department of Transportation Route 31/32 Modelling Results Table F-4: The Pasadena Department of Transportation Route 40 Modelling Results Table F-5: The Pasadena Department of Transportation Route 51/52 Modelling Results Table F-6: The Pasadena Department of Transportation Route 60 Modelling Results Table F-7: The Pasadena Department of Transportation Route 177 Modelling Results Table F-8: The Pasadena Department of Transportation Route 256 Modelling Results Table F-9: The Pasadena Department of Transportation Route 88 Modelling Results Table F-10: The Pasadena Department of Transportation Route H Modelling Results Table F-11: The Pasadena Department of Transportation Route 51/52S Mode lling Results Table G-1: Route 20 Energy Analysis with Redistributed Laps Table G-2: Route 31/32 Energy Analysis with Redistributed Laps Table G-3: Route 51/52 Energy Analysis with Redistributed Laps Table H-1: Glendale Beeline Scenario 1 Route 1 Modelling Results Table H-2: Glendale Beeline Scenario 1 Route 3 Modelling Results Table H-3: Glendale Beeline Scenario 1 Route 4 Modelling Results Table H-4: Glendale Beeline Scenario 1 Route 5 Modelling Results Table H-5: Glendale Beeline Scenario 1 Route 6 Modelling Results Table H-6: Glendale Beeline Scenario 1 Route 7 Modelling Results Table H-7: Glendale Beeline Scenario 1 Route 8 Modelling Results Table H-9: Glendale Beeline Scenario 1 Route 12 Modelling Results Table H-10: Glendale Beeline Scenario 2 Route 1 Modelling Results Table H-11: Glendale Beeline Scenario 2 Route 3 Modelling Results Table H-12: Glendale Beeline Scenario 2 Route 4 Modelling Results Table H-13: Glendale Beeline Scenario 2 Route 5 Modelling Results Table H-14: Glendale Beeline Scenario 2 Route 6 Modelling Results Table H-15: Glendale Beeline Scenario 2 Route 7 Modelling Results Table H-16: Glendale Beeline Scenario 2 Route 8 Modelling Results Table H-17: Glendale Beeline Scenario 2 Route 12 Modelling Results Table I-1: BurbankBus Green Route Modeling Results
Table I-2: BurbankBus Orange Route Modeling Results
Table I-3: BurbankBus Pink Route Modeling Results
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Table J-1: MDT Assumptions for Renewable Energy Sources Table J-2: MDT Assumptions for Generators
Table N-1: CNG Fleet Cost Estimates Assumptions:

Table N-2: BEB Fleet Cost Estimates Assumptions:

Table N-3: FCEB Fleet Cost Estimates Assumptions:

Table N-4: Charging Infrastructure Equipment Cost Assumptions Table N-5: Charging Infrastructure Cost Estimates
Table N-6: On-site Hydrogen Production HDRSAM Assumptions Table N-7: Delivered Gaseous Hydrogen HDRSAM Assumptions Table N-8: Delivered Liquid Hydrogen HDRSAM Assumptions Table N-9: Fueling Station Costs
Table N-10: Annual Maintenance Costs
Table N-11: Cost of Hydrogen
Table O-1: CI Standard for Diesel and fuels that are intended to replace diesel (CARB, 2020) Table O-2: CI Standard for Gasoline and fuels intended to replace gasoline (CARB, 2020) Table P-1: Global Warming Potential Factors
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CALSTART | Arroyo Verdugo Transit Operators Bus Electrification Feasibility Study

1 Section I: Executive Summary
The Arroyo Verdugo Transit Operators (AVTO) aim to transition to a zero-emission bus (ZEB) fleet to combat climate change and improve air quality. This project was undertaken to prepare a Transit Fleet Electrification Plan for each of the three transi t agencies serving the communities of the Arroyo Verdugo subregion—Pasadena Department of Transportation, Glendale Beeline, and BurbankBus. These studies examine the economic and technological feasibility of this transition by identifying individual transit agency needs and avenues for collaboration across the subregion. Each study helps inform elected officials and policy makers on decisions necessary to achieve full deployment of ZEBs and plan in accordance with the Innovative Clean Transit (ICT) regulation, which mandates that all transit fleets be 100 percent zero-emission by 2040.

ZEB Overview

The deployment of a ZEB fleet generates substantial environmental and health benefits for residents within a transit agency's service areas. In California, most transit agencies utilize buses with internal combustion engines that burn compressed natural gas (CNG), which produces carbon dioxide (CO2) —a greenhouse gas (GHG) that contributes directly to climate change —and other pollutants, such as nitrogen oxides (NOx), that result in harmful effects to the respiratory system and human health. For the Arroyo Verdugo subregion specifically, many areas within Glendale Beeline’s service area are designated as a disadvantaged community (DAC) by the California Environmental Protection Agency, which is based on a combination of air quality, pollution, and economic metrics. ZEBs, on the other hand, do not produce any tailpipe GHG or NOx emissions, which helps to improve air quality. ZEBs are also quiet and generate less noise pollution.

Two ZEB technologies currently exist: the battery electric bus (BEB), which uses electricity from a battery to power the bus, and the hydrogen fuel cell electric bus (FCEB), which uses hydrogen to produce electricity that propels the bus. The electricity needed to charge the bus and the hydrogen production process can produce GHG emissions, but the efficiency of the ZEB drivetrain is twice that of an internal combustion engine, meaning ZEBs produce less GHG emissions than CNG buses.

BEBs are propelled by an electrified drivetrain, use batteries to store electricity, produce no tailpipe emissions, and make little noise when moving. Transit BEBs are considered a mature technology and generally have a range of up to 225 mile s.

Shuttle BEBs typically have a range of up to 150 miles. At present, the technology's main drawback is range constraint result ing from the amount of energy stored in the battery, which can be affected by ridership ; heating, ventilation, and air condition ing

Section I: Executive Summary
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CALSTART | Transit Fleet Electrification Feasibility Study for the Arroyo Verdugo Transit Operators

2 (HVAC) intensity due to extreme weather ; route geography; and driver behavior. With these factors at play, BEBs cannot serve as a “drop-in” or a one-to-one replacement for a CNG bus for some duty cycles/routes, especially since a BEB can take hours to fully recharge. However, battery technology is expected to improve over time, and BEB s may become a drop-in replacement for a CNG bus in the future.

FCEBs also have an electrified drivetrain to propel the bus but instead use hydrogen to produce electricity. FCEBs have a longer range than BEBs and are generally considered to be a drop -in replacement for a CNG bus, with a refuel time of about 15 -20 minutes. Transit FCEBs are considered a mature technology and drop-in replacement for CNG, but the market for fuel cell shuttle buses is less developed than that for battery electric shuttle buses. While FCEBs face the same HVAC, ridership, and driver behavior problems as BEBs, these are lessened due to FCEBs' ability to store more energy. However, FCEBs are more costly than BEBs and must use hydrogen, which is expensive and can be difficult to obtain or produce.

Charging Infrastructure

Most electric buses are charged using a plug-in charger, which consists of the dispenser and a charging cabinet. There are several design options for depots implementing plug -in charging, with different space saving, cost, and additional use factors to consider:

• Individual parking spots, in which a dispenser is installed for each bus parking spot. • Lane parking, in which b uses park in lanes with the dispensers and charging cabinets located next to the buses in between lanes.
• Overhead plug -in charging , in which a structure is built over bus parking lanes and a retractable spool descends to charge each bus.

Charger interoperability, which refers to a bus charger 's compatibility with multiple types of buses , is an important factor in plug-in charger infrastructure. A transit agency's fleet could consist of buses from multiple OEMs with chargers from multiple manufacturers. Key points to ensure interoperability are consideration of charger standards, the plug -in charger's ability to communicate with the onboard charger, and whether the charger provides alternating current ( AC) or direct current ( DC) power.

Overhead pantograph charging is another option, in which the bus parks underneath the charger, a radio frequency identification (RFID) sensor on the bus signals to the charger, the charger and the bus make contact, and charging begins. Overhead pantograph chargers do require an overhead structure; a potential variation of this setup includes in-ground inductive chargers . Inductive chargers consist of a pad on the ground on which the bus parks, allowing for wireless charging to begin.

Overhead on-route chargers may be necessary for routes that ZEBs cannot serve on a single charge. With on-route chargers in place, charging could occur during a gap in service. To fuel a fleet of FCEBs, a transit agency would need to obtain and dispense hydrogen to the buses via one of several methods. A transit agency can either produce the hydrogen on-site or buy hydrogen from a fuel provider and have it delivered to the fueling site. Since the transportation of hydrogen is expensive, on-site hydrogen production is usually the cheaper option. However, on-site hydrogen production requires more infrastructure and installations typically have a lead time of ten months to two years.

Charging and Fuel Cost Considerations

The utility costs for a ZEB fleet are dependent on two main factors: energy and power. These have a major impact on the utility charges that a transit agency must pay to charge their buses. There are strategies to reduce utility charges, including overnight Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-16
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3 charging during off peak hours, sequentially charging the fleet in different batches, and managed charging. Managed charging systems can control charging behavior to reduce maximum power, decreasing maximum power draw by up to 31 - 65 percent and greatly reducing demand charges and the cost to operate the buses (Eichman, 2020).

For FCEBs, the cost of hydrogen is influenced by several factor s, one of which is the location of hydrogen production. In general, the cheapest option is to produce hydrogen on-site at the depot, but because on-site production requires capital investment, it is not economically feasible to produce hydrogen on-site until a volume of 200 kilogram ( kg) of hydrogen is reached. Delivered hydrogen must be transported to the depot, typically by truck —this solution is more economically feasible for transit agencies that use low volumes of hydrogen. It is important to remember that electricity is a required input to produce hydrogen, and the fueling station uses electricity. The use of hydrogen fuel thus entails operational costs beyond that of the hydrogen and the fueling station.

Resiliency

The transit agencies in AVTO will collectively deploy a large ZEB fleet with significant energy consumption and power draw.

Addressing resiliency concerns should be a top priority, as AVTO faces several unique resiliency risks in the Los Angeles region that can disrupt utility power to bus yards. Extreme heat, an expected common occurrence as climate change progresses, will further increase the possibility of grid outages and damage to electrical equipment used by transit agencies.

AVTO can obtain resiliency through front-of-the-meter (FTM), which is provided on the utility’s side of the meter, and behind- the-meter (BTM), which refers to resiliency solutions located on the customer’s side of the meter and is controlled by the transit agency. Regardless of whether the resiliency is BTM or FTM, providing full resiliency for a bus depot is difficult. The energy consumption and power draw for weekday service —the maximum energy consumption and power draw —for each transit agency is provided in Table ES-1 below. These figures exclude any energy or power demand from on-site buildings or maintenance bays.

Table ES-1: Daily Energy Consumption and Power Demand
Energy Consumption
/ Power Demand
Time
Pasadena
Department of
Transportation
Glendale Beeline BurbankBus
Weekday Energy
Consumption (kWh) 9,563 9,614 3,053
Weekday Power
Demand (kW) 2,792 2,210 977
Weekend Energy
Consumption (kWh) 4,341 5,358 -
Weekend Power
Demand (kW) 1,500 900 -

Maintenance and Training

ZEBs have unique systems like electric drivetrains, batteries, fuel cells, and hydrogen storage tanks that require specialized training to service effectively and operate with maximum performance . Most of the bus operations and maintenance work for AVTO’s fleets are contracted out to transportation services companies, which are typically responsible for providing trained bus drivers and maintenance staff. Since these transportation service contractors also serve other fleets with ZEBs, their drivers and mechanics might have previous experience with ZEBs. BurbankBus, however, will need to obtain training for their maintenance staff. In addition, each transit agency will need to conduct maintenance on bus infrastructure.

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4 Estimated Costs and Financial Resources

Transitioning to a ZEB fleet will require substantial financial resource s. Table ES-2 below provides a breakdown of the costs associated with transitioning to a ZEB fleet for AVTO's three transit agencies and illustrates a cost comparison between transitioning to a fully BEB fleet and a fully FCEB fleet.

Table ES-2: Estimated Costs to Transition to a ZEB Fleet Transit Agency BEB Fleet Costs FCEB Fleet Costs
The Pasadena Department of
Transportation - Scenario 1 $56,181,098 $61,762,767
The Pasadena Department of
Transportation - Scenario 2 $75,392,385 $81,482,913
Glendale Beeline - Scenario 1 $66,709,857 $88,713,803
Glendale Beeline - Scenario 2 $76,804,452 $91,564,649
BurbankBus $30,229,373 $31,712,460

Though the costs in Table ES-2 assume that the buses and infrastructure will be acquired through capital purchases and that the buses will be purchased according to each transit agency’s fleet replacement plan, there are myriad financing options for transit agencies to deploy ZEBs. The se include state and federal incentive programs and prospective financing mechanisms, in addition to traditional financing models. Section I provides an overview of multiple financing models for transit agencies looking to transition to zero-emission.

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5 Section I: Project Introduction and Technology Overview Project Description
The Arroyo Verdugo Transit Operators (AVTO) provide public transportation to the Arroyo Verdugo subregion through services offered by the Cities of Pasadena, Glendale, and Burbank . In addition to the cities of Pasadena, Burbank, and Glendale, this subregion consists of several communities , including La Canada Flintridge, La Crescenta, Montrose , San Marino, and the unincorporated Los Ange les County areas adjacent to Pasadena, including Altadena, the Kinneloa area, Chapman Woods, and portions of the City San Gabriel . To combat climate change and improve air quality, AVTO aim s to transition to a zero-emission bus (ZEB) fleet . Additionally, the Innovative Clean Transit (ICT) regulation issued by the California Air Resources Board (CARB) mandates that all transit agencies in California transition to ZEBs. AVTO intends to prepare a Transit Fleet Electrification Plan for each of the three transit agencies to examine the economic and technological feasibility of this transition. This report examines each individual transit agency’s needs as well as identify potential areas for collaboration among AVTO . Each study is intended to provide elected officials and policymakers with information needed to help make decisions regarding the rollout of a fully zero-emission transit fleet.

This report is structured in five sections: Section I provides an overview of the AVTO transit agencies and delves into a detailed discussion of current ZEB technology, including charging infrastructure, charging /fueling cost c onsiderations, resiliency, financing resources, and more. Sections II, III, and IV examine the feasibility of transitioning to a fully ZEB transit fleet for the Pasadena Department of Transportation - Public Transportation Services (which will be abbreviated as the Pasadena Department of Transportation), Glendale Beeline, and BurbankBus , respectively. The feasibility studies provide a techno -economic analysis of transitioning to a battery electric bus ( BEB) fleet and a hydrogen fuel cell electric bus (FCEB) fleet, as well as survey each transit agency’s operations, the energy needs of their fleet, a plan for phasing in ZEBs, utility analysis, an overview of infrastructure and resiliency equipment that will serve the fleet, financial analysis, and a funding strategy. Section V explores the sustainability and environmental impact of transitioning to a zero-emission transit fleet.

AVTO Overview
The Pasadena Department of Transportation, BurbankBus, and Glendale Beeline provide the Arroyo Verdugo subregion’s public transportation services . Collectively, the transit agencies span over 70 square miles and have over 350,000 residents in their service territory. This region, pictured in Figure 1-1, is located north of the City of Los Angeles. AVTO plays an important role in

Section I
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6 this region as it provides local transit service and helps transport people to other forms of public transit . Other transit agencies like LA Metro (Metro), Metrolink, LADOT Commuter Express, and Foothill Transit also operate in AVTO’s service territory.

Figure 1-1: Map of AVTO’s Service Area

The City of Pasadena was incorporated in 1886 . The Pasadena Department of Transportation operates the City of Pasadena's public transportation services , including fixed-route service s under the name of Pasadena Transit and demand res ponse transportation services under the name of Pasadena Dial-A-Ride for individuals who are at least 60 years old or who have a disability. Pasadena Transit began in 1994, and service has since evolved from one downtown circulator to a network of routes that operate throughout the City. Pasadena Dial -A-Ride started providing service in 1984. Between these two services, t he Pasadena Department of Transportation has an annual ridership of approximately 1.6 million boardings in 2019. In 2017, it was awarded the Outstanding Transportation Agency award by the California Association for Coordinated Transportation (CalACT) (Pasadena Transit website, 2019). In 2004, the Pasadena Department of Transportation was an early adopter of alternative fuel transit vehicles with the integration of several hybrid electric buses (E-Buses) into its fixed-route fleet. By 2014, Pasadena Transit had fully transitioned their fix ed-route fleet from diesel to compressed natural gas (CNG) and in 2021 the City converted their CNG fuel to renewable natural gas (RNG).

The City of Glendale was incorporated in 1906 , and its transit agency began service in 1984. Glendale Beeline’s routes and timetables were designed to integrate with other forms of public transportation to increase mobility in the city and the L os Angeles region. In 2018, Glendale Beeline reported annual boardings at 1.4 million.

The City of Burbank was incorporated in 1911. BurbankBus has been operating since the 1970s and began fixed-route service in 1995, providing local transit service and connecting Burbank to other forms of public transit (Oberstein, 2007). BurbankBus has Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-20
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7 experience utilizing zero-emission vehicles and previously hosted a hydrogen fueling station . Since 2008, BurbankBus has been running its fixed routes on 100 percent CNG buses.

Fixed-Route Transit Service
The main service that AVTO provides is fixed -route transit service. Fixed-route service is defined as service where buses travel established routes at scheduled times. Pasadena Transit has six fixed routes, BurbankBus has three fixed routes, and Glendale Beeline has 12 fixed routes. Due to the proximity of these three cities , their service territories have some points of contact :
passengers can transfer between BurbankBus and Glendale Beeline at the Downtown Burbank Metrolink Station, and passengers can transfer between Pasadena Transit and Glendale Bee line at the Jet Propulsion Laboratory (JPL). Pasadena Transit and BurbankBus passengers are also able to transfer to Metro’s buses.

Pasadena Transit is a fixed-route transit service. Pasadena Transit has 29 buses to operate their six routes that provide essential transit connections in Pasaden a and portions of Altadena seven days a week . In 201 4, the fixed -route fleet completed its transition from diesel to CNG, and in 2021, all buses began running on renewable natural gas ( RNG). Pasadena Transit is also investigating expanding transit service.

The City of Glendale operates the fixed -route transit service called Glendale Beeline, which has 41 CNG buses and operates twelve fixed routes. The Beeline provides fixed -route service on all seven days of the week with reduced service on weekends .

Fixed-route service provides transit services to key locations in Glendale. Beeline also provides support to La Cañada Flintridge by managing Route 33 and 34; La Cañada Flintridge supplies Beeline with buses for these services.

BurbankBus has 17 buses for their three routes; their service operates Monday through Friday. BurbankBus owns all buses used in transit operation s. The operations and maintenance for BurbankBus’s fixed -route fleet are co ntracted to a transit services company.

Dial-A-Ride Service
Dial-A-Ride service is defined as an on -demand, curb -to-curb transportation service for seniors and people with disabilities.

Pasadena Dial-A-Ride, Glendale Dial-A-Ride, and BurbankBus all operate dial-a-ride service. For residents in the Pasadena D ial- A-Ride or BurbankBus service areas, individuals who are 60 years and older, or those under 60 years with an Access membership or a Los Angeles County Transit Operators Association ( LACTOA) Disabled Reduced Fare Transit Access Pass ( TAP) card, are eligible for this service. For residents in the City of Glendale's service area, individuals who are 65 years and older, or those under 65 years with proof of disability, are eligible for this service. Due to the curb-to-curb nature of this service, these vehicles often traverse residential streets, have limitations in service areas due to street width or other conditions, and do not adhere to a fixed schedule. Dial-A-Ride service is provided seven days a week for Pasadena Dial-A-Ride and Glendale Beeline . As of April 2020, BurbankBus offers dial-a-ride service six days a week, with service not being offered on Sundays.

ZEB Overview
Benefits of ZEBs
In Southern California, most transit agencies use a fleet of buses powered by CNG . These buses have an internal combustion engine that burns CNG to create torque and propel the bus . The current CNG buses have proven to be a reliable technology capable of handling most transit bus duty cycles , but they do have several drawbacks , including noise pollution and tailpipe emissions. The combustion of CNG produces carbon dioxide (CO2) —a greenhouse gas (GHG) that contributes directly to climate change—and other pollutants. One of the most potent pollutants is nitrogen oxide (NOx). NOx, when combined with heat and sunlight, produces ozone, which is harmful to the respiratory system and human health . NOx emissions are regulated by the Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-21
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8 State of California. Many parts of Glendale have elevated levels of ozone, and many areas within Glendale Beeline’s service area are also designated as a disadvantaged community (DAC) by the California Environmental Protection Agency , as seen in Figure 1-2. This designation is based on a combination of air quality, pollution, and economic metrics. The areas shaded in red and dark orange in Figure 1-2 are considered a DAC.

Figure 1-2: Map of DACs (CalEnviroScreen 4.0, 2021)

ZEBs are buses that produce no tailpipe emissions , and therefore do not produce any GHGs or criteria emissions during bus operations. In practical terms, a ZEB cannot use an internal combustion engine and must use an electrified drivetrain. There are currently two ZEB technologies in existence: the BEB, which uses electricity from a battery to power the bus, and the FCEB, which uses hydrogen to produce electricity that propel s the bus. These two tec hnologies do not produce any tailpipe GHG or NOx emissions, which helps to improve air quality. The electricity to charge the bus and the hydrogen production process do produce GHG emissions, but since the drivetrain of a ZEB is twice as efficient as that of an internal combustion engine, ZEBs produce less GHG emissions than CNG buses. ZEBs also generate less noise than CNG buses.

The ICT Regulation
The ICT regulation issued by CARB mandates that all transit agencies in California transition to ZEBs. Fleets must be 100 percent zero-emission by 2040, and the regulation provides a timeline for phasing in ZEB procurements. Under the ICT regulation, the Pasadena Department of Transportation , Glendale Beeline , and BurbankBus all qualify as a small transit agency —they are located in the South Coast Air Bas in, and each agency operates fewer than 65 buses in annual maximum service . Small transit agencies must submit a ZEB Rollout Plan to the Executive Officer of CARB by July 1, 2023, with the following items:
a. A goal of full transition to ZEBs by 2040 with car eful planning that avoids early retirement of conventional internal combustion engine buses.
b. Identification of the types of ZEB technologies a transit agency is planning to deploy, such as BEB or FCEB. c. A schedule for construction of facilities and infrastr ucture modifications or upgrades, including charging, fueling, and maintenance facilities, to deploy and maintain ZEBs. This schedule must specify the general location of each facility, type of infrastructure, service capacity of infrastructure, and a timeline for construction. d. A schedule for zero-emission and conventional internal combustion engine bus purchases and lease options. This schedule Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-22
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9 for bus purchases must identify the bus types, fuel types, and number of buses . e. A schedule for conversion of conv entional internal combustion engine buses to ZEBs, if any. This schedule for bus conversion must identify number of buses, bus types, and the propulsion systems being removed and converted. f. A description on how a transit agency plans to deploy ZEBs in Disadvantaged Communities (DACs) as listed in the latest version of CalEnviroScreen (https://oehha.ca.gov/calenviroscreen). g. A training plan and schedule for ZEB operators and maintenance and repair staff. h. Identification of potential funding sources.

The ICT timeline for phasing in ZEB procurements for a small transit agency is as follows:
• By 2026: 25 percent of new bus purchases must be zero emission . • By 2029: 100 percent of new bus purchases must be zero emission U.S. Federal Requirements
Altoona Bus Testing
The Surface Transportation and Uniform Relocation Assistance Act of 1987 (STURAA) created the Standardized Bus Testing program. The Standardized Bus Testing program, which is frequently referred t o as Altoona Bus Testing, is a federal program that tests the maintainability, reliability, safety, performance, structural integrity and durability, fuel and/or energy eco nomy, noise, and emissions from buses . Altoona Bus Testing is intended to serve as q uality control and aims to ensure that new bus models can safely and reliably operate in real -world conditions. Under Altoona Bus Testing, buses are scored on a scale of 1 – 100 based on their performance in each of the testing categories . A bus must recei ve a score of 70 to pass testing . STURAA mandates that no new bus model can be acquired with federal funding without having received a passing score during Altoona Bus Testing . Since AVTO may use federal funding towards the purchase of transit vehicles and operations, this study only examines buses that have already passed Altoona Bus Testing or are likely to begin testing in the near future.

Buy American and Buy America
In addition to Altoona Bus Testing, the U.S. federal government has two distinct requirements related to domestic content of federal purchases: Buy American and Buy America. Buy American refers to a requirement from the 1933 Buy American Act and applies to purchases by the U.S. federal government valued at more than $10,000. T o comply with this requirement, the goods must be manufactured in the United States, and at least 50 percent of the cost of their components must come from the United States. There are exceptions to this rule: waivers can be granted if it is deemed to be i n the public interest, or if the cost of U.S. components is unreasonably high compared to foreign counterparts. Buy America refers to a requirement for purchases of iron, steel, and other manufactured products incorporated into infrastructure that is funded by the U.S. federal government, including if the project is undertaken by a state or municipal government in the U nited States. This requirement also applies to transit agencies. If a bus does not meet Buy America standards, then it cannot be purchased with federal funding.

Per Buy America, any transit vehicles purchased with the federal funds from the Federal Transit Administration (FTA) must have at least 70 percent of the cost of the vehicle be of domestic origin. This is determined by the origin of the bus components—a component is domestic if it is manufactured in the United States, and if at least 70 percent of the cost of its subcomponents are manufactured in the United States. The cost of making a battery pack is about 26 percent of the cost of a BEB. However, the FTA has not deemed the use of imported battery cells to be contrary to the Buy America rules ; battery cells are considered sub - subcomponents, which are ignored , and t hey are substantially transformed into battery packs, with modules, coolants, and sensors added in the United States (Canis, 2018). The iron and steel components for direct current (DC) fast chargers received a waiver for the Buy America requirements from the FTA in 2016, as there were no domestic manufacturers of the required components (FTA, 2016).

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10 BEB Overview
Battery Electric Technology
BEBs are propelled by an electrified drivetrain and use batteries to store electricity . When the bus needs to move, it draws energy from the battery to power a traction motor. The traction motor uses magnets to generate torque and propel the bus .

BEBs also have a regenerative braking system that can capture some energy from the bus when it decelerates and use it to recharge the battery during braking . BEBs produce no tailpipe emissions and are very quiet when mov ing. BEBs do suffer from some drawbacks, mainly that their range is constrained by how much energy can be stored in the battery . Batteries are heavy and require a lot of space . This factor puts constraints on how many batteries can be placed on the bus safely and may further limit the range of the bus. The range of the bus can be decreased if ridership is high, which increases the weight of the bus, or if the bus must gain elevation on its routes. The heating, ventilation, and air conditioning (HVAC) systems are also energy intensive and, in temperature extremes, can consume more energy than the propulsion system itself . This can reduce the range of the bus on days that are very hot or cold. Lastly, driver behavior can have a large impact on the range of the bus. BEBs are designed to be driven in a certain manner , and bus operators must receive driver training to properly drive the buses . Deviations from this training will impact the bus’s performance. Consequently, BEBs cannot serve as a “drop-in” or a one-to-one replacement for a CNG bus for some cycles/routes. This problem is exacerbated by battery charge time. While a CNG bus can be fully refueled in minutes, a BEB can take hours to fully recharge.

Appendix A provides an overview of some of the relevant BEBs currently on the market , and m ore information on charging technology can be found in the Charging Infrastructure section and Appendix B.

Transit BEBs
Classified in the FTA's 12 year/500,000 mile service-life category, transit buses are Class 7 or 8 vehicles, typically used for fixed- route service, and generally range between 30 and 40 feet in length. A transit BEB is a battery-powered bus that has a length of 30 feet or more. Transit BEBs are considered a mature technology—multiple BEB models have passed Altoona testing, and there are several original equipment manufacturers (OEMs) that produce and sell transit BEBs. Articulated 60-foot ZEB models, which have two sections connected by a joint and can be up to 60 feet in length, have also been Altoona tested. As of December 2020, there were 2,703 transit BEBs that have been purchased, are on order, or deployed across in the United States (Jackson, 2020).

Transit BEBs generally have a range of up to 225 miles, depending on the duty cycle. CNG buses, on the other hand, have a range of about 350 miles. The lower range of the BEB may require additional vehicles to provide the same level of service, depending on the duty cycle. The two Altoona te sted 30-foot BEBs do not currently have adequate range for AVTO's needs at the time of writing. Battery technology is expected to improve over time , however, and it is possible that a BEB can become a drop -in replacement for a CNG bus in the future. BEB charging technology and infrastructure will be discussed in further depth in the Charging Infrastructure section.

Battery Electric Shuttle Bus and Transit Vans
A battery electric shuttle bus (also commonly referred to as a small bus) is classified in the FTA’s 5 year/150,000 mile or 7 year/200,000-mile service-life category, and is defined as a battery-powered cutaway bus with a length of less than 30 feet and a gross vehicle weight rating (GVWR) of greater than 14,000 pounds . Shuttle buses are generally medium-duty Class 4-6 buses.

These buses are typically used for demand response service , such as Pasadena Dial -A-Ride, and have a wheelchair lift to serve disabled passengers . Most shuttle buses can carry 19 -24 passengers. OEMs also have the ability to cust omize configurations based on transit needs , such as changing the floorplan and adding equipment such as fareboxes and wheelchair lifts . Battery electric transit vans have recently been introduced to the market. These vehicles are smaller than shuttle buses and can typically Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-24
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11 carry fewer than 10 passengers.

A few OEMs offer electric shuttle buses of varying battery pack sizes, vehicle lengths, and options . At the time of writing, only one 24-foot shuttle van BEB model, manufactured by GreenPower Motor Company, has passed Altoona testing, and the overall market for electric shuttle buses is small. However, Phoenix Motorcars' shuttle bus is anticipated to complete Altoona testing in 2022. Glendale Dial-A-Ride and Pasadena Dial-A-Ride both include minivans in their fleet, but zero-emission minivan options are unavailable. As of December 2021, 652 battery shuttle buses have been purchased, are on order, or deployed across the United States (Hamilton, 2021).

Battery electric shuttle buses generally have a range of up to 150 miles, depending on the duty cycle , and cost about $275,000.

Fossil fuel powered counterparts, on average, have a range of 350 miles and cost around $75,000. Again, additional vehicles may be required to provide the same level of service, depending on the duty cycle, but battery technology continues to improve. By the time AVTO is subject to the ICT regulation, shuttle buses will likely have a longer range. The market for transit vans is expected to grow, and there will likely be more commercial offerings in the coming years.

FCEB Overview
Fuel Cell Electric Technology
FCEBs use an electrified drivetrain to propel the bus, but unlike BEBs, FCEBs use gaseous hydrogen to produce electricity. When the bus needs to move, hydrogen is drawn from the bus's hydrogen tank and used by a fuel cell to produce electricity . This electricity is stored in a battery until it is sent to the traction motor to generate torque and propel the bus . Since gaseous hydrogen has low energy density per volume, hydrogen must be compressed into the storage tank . The compression process allows more hydrogen to be stored in the tank. Fuel cell vehicles typically store hydrogen in their tanks at a pressure of 350 bar (5,000 pounds per square inch) or 700 bar (10,000 pounds per square inch). FCEBs use hydrogen compressed to a pressure of 350 bar. The tanks on a bus typically store 50 kilograms (kg) of hydrogen, 90-95 percent of which can be used. An FCEB has the advantage of having a longer range than a BEB . Since hydrogen is energy dense and lightweight, the hydrogen tanks can store more energy on the bus than a battery . FCEBs are generally considered to be a drop -in replacement for a CNG bus. In addition, an FCEB can refuel quickly in about 15-20 minutes. While FCEBs must also contend with the HVAC, ridership, and driver behavior problems that BEBs face, these tend to be less severe due to FCEBs' ability to store more energy . While FCEBs have these advantages, FCEBs currently cost more than BEBs and must use hydrogen, which is more expensive than CNG and unleaded fuel and has unique challenges in obtaining or producing it (see page 18 for hydrogen infrastructure pathways).

Transit FCEBs
A transit FCEB is a hydrogen fuel-cell powered bus that has a length of greater than 30 feet and, like transit BEBs, are Class 7 or 8 vehicles, classified in the FTA’s 12 year/500,000 mile service -life category , and typically used for fixed -route service. Most current FCEB models have a length of 35 feet or 40 feet. At the time of writing, there is no Altoona tested 30 -foot FCEB model, but 60-foot articulated models have been Altoona tested. Transit FCEBs are considered a mature technology , but to date there are fewer commercial offerings for transit FCEBs than BEBs; however, this is anticipated to change. As of this writing, two models of FCEBs have passed Altoona testing . As of December 2021, there were only 169 transit FCEBs that have been purchased, are on order, or deployed across in the Unite d States (Hamilton, 2021). Transit FCEBs generally have a range of up to 300 miles, depending on the duty cycle. CNG buses, on the other hand, have a range of about 350 miles . Since transit FCEBs have a longer range, they are generally considered to be a drop-in replacement for a CNG bus.

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12 Fuel Cell Shuttle Buses
A hydrogen fuel cell shuttle bus is defined as a hydrogen fuel -cell powered cutaway bus with a length of less than 30 -feet, a GVWR of greater than 14,000 pounds , and is classified in the FTA’s 5 year/150,000 mile or 7 year/200,000 -mile service -life category. Similar to shuttle BEBs, fuel cell shuttle buses are generally medium-duty Class 4-6 buses, typically used for demand response service, have a wheelchair lift to serve disabled passengers, and can carry 19-24 passengers, depending on the floorplan configuration.

The market for fuel cell shuttle buses is less developed than battery electric shuttle buses, with fewer models of fuel cell shuttle buses available. Fuel cell shuttle buses are also at an earlier stage of commercialization and have a lower technology readiness level than battery electric shuttle buses . As of December 202 1, only nine fuel cell shuttle buses have been purchased, are on order, or deployed across the United States (Hamilton, 2021). It is unclear how mature this technology will be by 2026, when AVTO must begin purchasing ZEBs under the ICT regulation.

Fuel cell shuttle buses generally have a range of 230 miles and cost around $2 75,000. Data on the cost of a fuel cell shuttle bus is scarce. However, cost data from pilot/demo fuel cell shuttle buses indicates that the price is approximately equal to a battery electric shuttle bus. Fossil-fueled powered counterparts have a range of 350 miles and cost around $75,000. Since fuel cell buses have a longer range than BEBs, they are closer to serving as a drop-in replacement. Both full-sized and shuttle FCEB refuel at 350 bar, but the fil ling speed may have to be adjusted for the shuttle buses to maintain hydrogen tank integrity . Hydrogen fueling challenges are discussed in more detail under Hydrogen Fueling Infrastructure Overview.

Charging Infrastructure
Depot Plug-in Charging
Most electric buses are charged using a plug -in charger, which consists of the dispenser and a charging cabinet . The dispenser has a plug that goes into the bus to provide energy to charge the battery, and the plug connects to the dispenser via a hose. The dispenser is then connected to the charging cabinet, which contains the power electronics and communications equipment used to control charging with the bus and to communicate with the charging provider’s network The current technology requires workers to manually plug in the bus when it returns from its route. The communications protocols between vehicle and charger can vary among BEB OEMs (see Charger Interoperability section for additional details).

Buses can be charged with Level 2 chargers or DC Fast Chargers (DCFC). A Level 2 charger delivers AC power to the bus at voltages of up to 240 volts. Level 2 chargers can deliver up to 19.2 kW and are typically used to charge electric cars, vans, and shuttle buses. Buses can also be charged with a DCFC. DCFCs deliver DC power to the bus at voltages of up to 600 volts. DCFCs are typically used to charge transit buses. They can also be used to quickly charge shuttle buses.

A plug-in charging system has a large physical footprint . Charging cabinet are responsible for much of the footprint, and they typically require concrete pads . Bollards are also required to protect the charging cabinets from being hit by buses or other vehicles. Some flexibility in the design/layout of a charging site does exist: The charging cabinet must typically be located within a few hundred feet of the dispenser and, as a result, the charging cabinets can be put in areas of the yard with more space (e.g. the edges). Most depots are designed with the dispensers and charging cabinets adjacent to parked buses. For example, a depot might have parking spots for the buses with a dispenser for each parking spot , as illustrated in Figure 1-3. In most cases, this design is the least expensive option for charging.

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13 Figure 1-3: Plug-in Chargers Example

Since space is a major constraint, space -saving designs can be developed. A depot can also be designed whereby the buses are parked in lanes, and the dispensers and charging cabinets are located next to the buses in between the lanes , as seen in Figure 1-4 below.

Figure 1-4: Buses Parked in Lanes Example (Source: ABB)

Another possible design would be overhead plug-in charging. In this design, the buses are parked in lanes and a structure is built over the parking lanes, similar to the example shown in Figure 1-5.

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14 Figure 1-5: Overhead Plug -in Charging Example (Source: Burns McDonnell Foothill Transit In -Depot Charging and Planning Study)

A retractable spool is installed on the overhead structure, which allows the plug to be pulled down for charging. This design does not require the charging cabinets to be located next to the bus , which is advantageous when there is not e nough space in between parking lanes to install the charging cabinets or dispensers. The overhead structure can also be used for other purposes, such as housing a solar photovoltaic (PV) installation. While this design does save space, the construction cost for the overhead structure is higher because a foundation needs to be laid. Foothill Transit currently uses this design.

Charger Interoperability
A key factor in plug -in charging infrastructure is charger interoperability . Charger interoperability refers to a bus charger 's compatibility with multiple types of buses —if a bus charger can charge buses from multiple manufacturers, it would be considered interoperable . Interoperability has multiple dimensions : the charger must be able to plug -in to, charge, and communicate with buses from multiple manufacturers. Since transit agencies tend to phase-in their fleets over time, it is possible that a fleet will consist of buses from multiple OEMs and that chargers from multiple manufacturers will be deployed . The use of a fleet with buses from multiple OEMs and multiple types of chargers increases the risk that there will be interoperabilit y problems. To promote interoperability, charger standards have been develope d. There are several different charger standards.

SAE J1772 standardizes the charging plug for Level 2 charging up to 19.2 kW. The Combined Charging System (CCS) standardizes the charging plug and offers a protocol for charging communication. CHAdeMO is a competing charging standard that offers a standard for the charging plug and charging communications. The major OEMs have adopted CCS standards.

Other interoperability concerns exist, one being that the plug-in charger must be able to communicate with the onboard charger via a compatible communications protocol . Another concern is whether the charger provides alternating current (AC) or DC power. The type of power the plug-in charger operates on must be the same as that of the onboard charger. Before purchasing, buses and infrastructure should be tested to ensure interoperability. For example, charging infrastructure for the shuttle BEBs and transit vans can vary. Most shuttle buses and transit vans can charge with a Level 2 charger, though many of these vehicles can also be charged faster with a DCFC. The type of charger required for DC fast charging varies by OEM, and some buses must use a high voltage DCFC. It is important to purchase charging equipment that is compatible with the specific bus pur chased.

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15 Depot Overhead Charging
Buses can also be charged with an overhead pantograph charger , which is placed over the bus . When the bus parks, a radio frequency identification (RFID) sensor on the bus signals to the charger, the charger and the bus mak e contact, and charging begins. There are two types of pantograph chargers: a top-down charger, in which the pantograph lowers itself down to the bus to initiate charging, and a bottom-up charger, in which the pantograph is mounted on the bus and raises itself to the charger to begin charging . Pantograph chargers tend to charge at a higher power level than plug -in charging . Most overhead chargers charge at 150-200 kilowatt (kW), though some can charge at 450-600 kW. Most depot overhead chargers charge in the 150-200 kW range to manage utility demand chargers.

An overhead pantograph charger requires an overhead structure to be built in order to mount the charger above the bus parking spots. At a very minimum, a steel structure is required . Typically, the ins tallation of a steel structure involves building a foundation to anchor the structure. Installing the structure itself is one of the most expensive parts of the construction process, but adding additional features to the structure can be done at a relative ly low incremental cost . As a result, solar panels are often installed on the structure , which provides the benefit of providing power for the facility and sheltering the bus from sunlight (to prevent heat gain) and rain . Parking lanes are also built underneath the structure, and a curb is necessary to guide the buses to align with the charger and protect the charging cabinet from collisions.

The main adva ntage of depot pantograph charging is that the pantographs can automatically charge the bus without workers present to manage plugs . Smart charging software can be used to control when to start and stop charging , which means that some of the charging operations can be automated. However, overhead pantograph charging, as depicted in Figures 1-6 and 1- 7, is more expensive than regular plug -in charging . The pantographs add about 30 percent to the cost of the charger (per correspondence with Amply Power), but this amount excludes the construction/installation costs. Since construction/installation comprise the majority of the cost, the overall incremental cost of the pantograph is relatively small. An overhead structure is expensive, but this solution, which becomes economical when installed to charge at least 30 buses, is not much more expensive than overhead plug -in charging. For example, the Los Angeles Department of Transportation (LADOT) is currently planning to deploy a depot overhead charging solution for some of their yards to charge a total of 104 buses.

Figure 1-6: In-Depot Overhead Charging Example (Source: CALSTART)

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16 Figure 1-7: In-Depot Overhead Charging Example (Source: CALSTART)

SAE J3105 is the standard by which conductive automated connection charging devices for electric vehicles are designed. There are multiple types of chargers that are governed by this standard including overhead pantograph chargers. SAE J3105 provides standards for both top-down and bottom-up chargers. SAE J3105/1: Infrastructure-Mounted Cross Rail Connection is the portion of SAE J3105 that governs top -down chargers. SAE J3105/2: Vehicle-Mounted Pantograph Connection is the part of SAE J3105 that governs bottom -up chargers. Top-down chargers that comply with SAE J3105/1 will be interoperable with each other whereas bottom-up chargers that comply with SAE J3105/2 will be interoperable with each other. A SAE J3105/1-compliant top- down charger will not be interoperable with a SAE J3105/2-compliant bottom-up charger.

A potential variation of this se tup includes in-ground inductive chargers , shown in Figure 1-8. Inductive chargers can charge a vehicle without plugging -in or needing an overhead charger . Instead, inductive chargers can charg e vehicles wirelessly . The charger consists of a pad on the ground; the bus parks on top of the charging pad and wireless charging begins. Inductive chargers can charge at powers of up to 200 kW . If these chargers are used, the bus is parked on the inductive chargers at the end of the day’s service. Smart charging software then controls the charging overnight. In-ground inductive chargers are currently produced by Momentum Dynamics and WAVE. At this point in time, few transit agencies use depot inductive ch argers. However, this is a technology that agencies might begin to consider as an alternative to depot overhead pantograph charging.

Figure 1-8: Inductive Charging Example (Source: Momentum Dynamics)

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17 On-route Charging
Most transit agencies use depot charging as the primary method of charging their buses . However, buses are sometimes deployed on routes that they cannot serve on a single charge. This issue can occur if the bus is on a lengthy or high-grade route, or alternatively, on days with extreme weather that increases the energy consumption of the bus’s HVAC system . This is highly problematic, as the bus will run out of battery before it finishes the route.

Overhead on-route chargers is one way to address this problem. On-route charging occurs during a gap in service—the bus will typically drive underneath an overhead on -route charger, and t he bus and the charger will interface and connect in a similar manner as depot overhead charging. Most buses have only short breaks during their schedule. To charge as much of the battery as possible during a break, these overhead chargers usually charge at high power levels . The typical on-route overhead charger will charge at power levels of 450 -600 kW. These chargers are commonly built at a bus stop or a bus terminus to use when the bus is on a scheduled break.

One major issue with an overhead charger is that the driver needs to align the bus with the pantograph . To achieve this, transit agencies will add markings to the ground underneath the charger to assist the driver. See Figure 1-9 as an example of this setup.

Figure 1-9: On-route Overhead Charging (Source: ABB)

Public Charging
A transit agency could also utilize public charging networks. The use of a public charging networ k could serve as a form of on - route charging. Under this charging model, the buses would be charged overnight . However, if the buses were to run low on charge during the day, they would have the option to charge at a public charging station during a break in service to refill the battery and extend the range of the bus. Public charging can be used as an emergency measure if a bus runs low on battery during its operations. It could also potentially be used to extend the range of the bus if its service is expanded. Alternatively, public charging can be used as a resiliency measur e if the bus depot were to lose power. Unless there is an area -wide power outage, it is unlikely that two separate charging locations would lose power simultaneously. As a result, a public charging station could provide backup charging if the bus depot were to lose power.

Public charging would likely be most useful for shuttle buses operating demand response service (e.g. Dial-A-Ride), as they have a smaller battery capacity than transit buses and can therefore recharge a high percentage of the battery during a mid -day charge. Public charging stations can have Level 2 chargers, DCFCs, or both. DCFCs can charge the battery faster and would be the more useful type of charger. However, Level 2 chargers can be useful if the bus only needs a small amount of charge.

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18 If a transit agency opts to use public charging, it would need to identify the specific station or stations that it plans to use in advance. Transit agencies should confirm that the chargers at those specific sites are interoperable with their specific bus OEM.

Since there are multiple charging standards and different charging voltages, it would be advisable to confirm interoperability by physically charging the bus at the actual station. Public charging stations typically require that customers purchase a subscription and they also charge per kWh dispensed by the charger.

Most public charging stations are designed for light-duty electric vehicles as they have head-in parking spaces. However, bus operators do not typically backup vehicles in public spaces without using a spotter to guide them . As a result, this parking configuration would not appropriate for buses. To use a public station, the buses would need to have access to a pull-through parking configuration.

Pasadena Water and Power ( PWP) recently opened the Arroyo EV Charging Depot, which is located at 64 E. Glenarm Street, Pasadena, CA. This station has multiple DCFCs that can be used by buses. The site will likely be expanded within the next couple of years to include DCFCs and dedicated spots for medium - and heavy-duty vehicles. The specifics of the site layout, including the type of parking and the number of c hargers were not disclosed. This station is located near the terminus for the Pasadena Department of Transportation's Route 51/52. There is also an Electrify America station located at 1301 N. Victory Place, Burbank, CA. The transit agencies could potentially use any sites located in their own service area. It is likely that additional public charging stations will also be deployed in the future , which would be an opportunity for coordination to occur with transit agencies in advance in order to identify how these stations could potentially address their needs and to plan their designs accordingly .

Hydrogen Fueling Infrastructure Overview
FCEBs consume hydrogen to power the vehicle. To fuel a fleet of FCEBs, a transit agency needs to obtain and dispense hydrogen to the buses. Currently, FCEBs have a hydrogen tank that receives hydrogen at a pressure of 350 bar. Most FCEBs store 35-50 kg of hydrogen in the tank . Transit agencies have several options for obtaining hydrogen. A transit agency can either produce the hydrogen on-site or buy hydrogen from a fuel provider and have it delivered to the fueling site . Since the transportation of hydrogen is expensive, on-site hydrogen production is usually the less expensive option. However, on-site hydrogen production requires installing infrastructure, which can present challenges depending on the space available.

Hydrogen is a flammable gas , and a s a result, hydrogen infrastructure , as with other types of propulsion infr astructure, must comply with fire safety standards , especially t he prominent National Fire Protection Association (NFPA) codes . Hydrogen infrastructure installations often have a lead time of ten months to two years, including the permitting process.

On-site Steam Methane Reforming (SMR)
Hydrogen can be produced using SMR . SMR requires a reformer that combines natural gas and steam at high temperatures to produce hydrogen. SMR uses little electricity, using instead a catalyst to produce the hydrogen. However, SMR does require the use of natural gas and water.

An on-site SMR system would need a minimum of 60 feet by 60 feet, or 3,600 square feet. The system can also be split into two 60-foot by 30-foot rectangles, as long as the two areas can be placed near each other. Typically, the SMR comes in two parts .

One part is a container that houses the SMR modules, the electronics, and hydrogen compression equipment . The second part is the fueling station and storage . An on-site SMR system also requires a com pressor to compress the hydrogen in order to dispense at a pressure of 350 bar.

Since this process produces GHGs, the State of California requires that 33 percent of the natural gas comes from renewable sources. SMR also consumes about 4.6 gallons of water per kg of hydrogen produced (Webber, 2007). Still, SMR can produce Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-32
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19 hydrogen in a less expensive manner, but SMR production does require investment in production equipment . See page 24 for more information on hydrogen fueling cost considerations.

On-site Electrolysis
Hydrogen can also be produced via on-site electrolysis. Electrolysis produces hydrogen by running an electrical current through pure water to split the water into hydrogen and oxygen . The hydrogen is then ca ptured, compressed, and stored until it is dispensed into the bus. Electrolysis uses approximately 2.4 gallons of water per kg of hydrogen (Webber, 2007). An electrolyzer has a similar footprint as a n SMR system and comes in two containers , with one container housing the electrolyzer and compression equipment and the second container housing storage and fueling equipment . An on-site electrolyzer system also requires a compressor to compress the hydrogen to dispense at a pressure of 350 bar.

Electrolysis is considered the cleanest method of producing hydrogen, as it does not produce any direct GHG emissions. In using electricity, indirect GHG emissions are generated when producing the electricity. However, these emissions can be mitigated if the electricity is produced from renewable sources. Electrolysis is currently an expensive method of producing hydrogen and is energy intensive— see page 24 for more information on hydrogen utility cost considerations.

Delivered Gaseous Hydrogen
Hydrogen can be produced offsite at a centralized location and then delivered to the bus fueling location. Gaseous hydrogen is typically produced at a central production facility at low pressures of 20 -30 bar, then compressed to a higher pressure . The hydrogen is stored in long cylindrical tubes that are then loaded onto a truck trailer and transported to the bus fueling location.

Once the tube trailer arrives at the location, the hydrogen is delivered to the fueling station. A compressor is used to increase the pressure of the hydrogen in the tube trailer. This compressed hydrogen is then delivered to storage tanks where it can be dispensed to the buses.

These tube trailers can carry only a limited amount of hydrogen, however. U.S. Department of Transportation regulations limit compression pressures to 250 bar . Furthermore, truck payload weight restrictions effectively limit a tube trailer to delivering a maximum of 280 kg of hydrogen (U.S. DOE Hydrogen and Fuel Cells Technology Office, n.d.) . As a result, this option is more advantageous for fleets that require relatively low volumes of hydrogen. See page 24 for more information on hydrogen delivery cost considerations.

Delivered Liquid Hydrogen
To be delivered in liquid form , h ydrogen is produced at a centralized production facility and then liquified by reducing its temperature to -253 degrees Celsius. The liquid hydrogen is then put onto a truck for delivery. Once the truck reaches the depot, it will pump the liquid hydrogen into a liquid hydrog en storage tank. The hydrogen from the storage tank is processed by liquid compression pumps , which delivers the hydrogen to a vaporizer . The vaporizer converts the liquid hydrogen to gaseous hydrogen, which is then delivered to gaseous storage tanks. The hydrogen is subsequently dispensed to the buses.

Liquid hydrogen has the economical advantage as compared to gaseous hydrogen but some drawbacks exist. Mainly, liquid hydrogen is lost if it is left in storage for a long time. As liquid hydrogen warms up, it evaporates and turns into a gas . Hydrogen systems are designed to release this gas, known as off -gassing. Off-gassing can result in losses of 1 percent per day, but o ff- gassing can be reduced if hydrogen is dispensed to vehicles on a daily basis . A system that captures off -gassed hydrogen and compresses it into the gaseous storage tanks can also be employed.

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20 Offsite Retail Fueling
If a transit agency is unable to invest in hydrogen fueling infrastructure, they could theoretically fuel buses at offsite retail fueling stations. A retail fueling station is a privately owned station that sells hydrogen to customers , and would be analogous to a gas station or a CNG station.

The market for retail hydrogen fueling is in the early stages of development . As the fuel cell vehicle market has matured, more retail stations have been built . While there are multiple retail stations, light -duty and heavy -duty retail fueling are distinct markets. Light-duty stations typically have 700 bar dispensers and lower levels of storage. Heavy-duty stations typically have 350 bar dispensers and require large storage capacity . Currently, there are no heavy -duty stations near AVTO . As a result, retail fueling would not be a viable option for a fleet of transit FCEBs.

Retail fueling, however, could potentially be appropriate for fuel cell shuttle buses and dial-a-ride vehicles. Hydrogen shuttle buses use less hydrogen than a transi t FCEB, and it is theoretically possible to fuel them at retail hydrogen stations . There is a light-duty hydrogen fueling station located at the City of Burbank’s Public Works facility at 124 South Lake Street, Burbank, CA 91502 (see Figure 1-10). In addition, there is a True Zero hydrogen station located at 550 Foothill Boulevard, La Canada Flintridge, CA 91011 (see Figure 1-11).

Figure 1-10: Light-Duty Hydrogen Fueling Station at 124 South Lake Street, Burbank, C A (Source: CALSTART)

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21 Figure 1-11: True Zero Light-Duty Hydrogen Fueling Station (Source: CALSTART)

The use of retail hydrogen stations as the primary source of hydrogen entails some operational risks . Retail hydrogen stations can be inoperable if they run out of hydrogen or are undergoing planned or unplanned maintenance. To lower this risk, it would be prudent to have access to multiple fueling stations . There are other stations located in the vicinity : a True Zero station is located in South Pasadena at 1200 Fair Oaks Avenue, South P asadena, C A 91030. There are also True Zero stations in the permitting process . These stations will be located at 3402 Foothill Boulevard, Glendale, C A 91214 and 800 North Hollywood Way, Burbank, CA 91505. Shell has also proposed installing a hydrogen station at 290 South Arroyo Parkway, Pasadena, CA 91105. See Figure 1-12 for a map of retail fueling stations in the Los Angeles area.

Figure 1-12: Map of Retail Fueling Stations in the Los Angeles Area (Source: California Fuel Cell Partnership)

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22 Charging and Fueling Cost Considerations
Energy and Power
The utility costs for a ZEB fleet are dependent on two main factors: energy and power . Energy represents the total amount of electrical fuel consumed by the bus. Energy is denoted in units of kilowatt-hours (kWh). The battery of a BEB has capacity limits and can only store a certain amount of kWh of energy. The energy capacity of the battery is analogous to the number of gallons that can be stored in a gas tank . Utility companies typically sell energy by the kWh . The price of the kWh can also change depending on how much demand occurs during the day. Energy is usually most expensive in the afternoon when demand is high and costs less at night when demand is lower. As a result, transit agencies typically schedule their charging to coincide with the lowest energy rates.

Power represents the rate at which energy is consumed and is typically measured in kW . Utilities care about power ; if there is too much ag gregate demand, it can overwhelm the grid and cause a blackout . As a result, utilities incentivize lower power demand from their customers by charging per kW . Customers are usually charged for the maximum amount of power they demand over the course of the month, regardless of how long they draw power at that level . For example, if a transit agency normally has a power demand of 50 kW but experiences a surge in demand and consume s 100 kW for 15 minutes over the course of a month, they would be charged for de manding 100 kW . Charges for power demand are typically high and can be extremely costly. These charges are typically responsible for the majority of the utility bill.

Primary and Secondary Service
Utilities also charge based on the type of electrical servi ce they provide . Utilities can provide primary and secondary service .

Type of service refers to the voltage at which the utility delivers the electricity to the customer. Primary service occurs when the utility delivers electricity to the customer at a hig h voltage. When primary service is provided, the utility delivers electricity directly to the customer without stepping down the voltage . In this case, the customer is responsible for stepping down the voltage with their own transformer. Secondary service occurs when the utility steps down the voltage with their own transformer and delivers the electricity to the customer at a lower voltage . Primary service usually involves lower electricity rates . The decision to provide primary or secondary service is typically determined by the utility.

Strategies for Managing Utility Costs
Utility charges are determined by a variety of factors such as energy and power demand , which have a major impact on the utility charges that a transit agency must pay to charge their buses. However, there are strategies to reduce utility charges. This section will discuss some of the strategies that transit agencies can employ to minimize this co st.

Overnight Charging
Transit agencies are charged for the energy they consume. Transit agencies are typically charged by the kWh, and utilities usually have different rate structures that their customers can use . Most transit agencies use time -of-use (TOU) tariffs. Under a TOU tariff, energy charges vary throughout the day. Energy charges are typically lowest during times of low energy demand (off-peak rates) at night and are highest during the day in the late afternoon/evening hours—solar production decreases as the sun begins to set, and energy consumption increases as air conditioning loads come online . As a result, peak energy charges usually occur from approximately 4 to 8 pm. Some utilities also offer flat rate tariffs, where the cost per kWh is cons tant throughout the day.

Transit agencies aim to reduce the energy costs associated with charging , but transit agencies cannot reduce energy costs by reducing the amount of energy they consume , which would entail cutting transit service . If a transit agen cy is on a TOU tariff, Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-36
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23 they can reduce energy charges by shifting the times during which they charge the buses . Since off-peak rates are lower than peak rates, energy costs can be reduced by shifting the charging schedule so that the majority of buses charge at night during off-peak hours.

Sequential Charging
Utilities typically charge a fee per kW of peak power demand . As a result, transit agencies can decrease their utility costs by lowering the peak power they draw from the grid through sequential charging. In a depot with unmanaged charging, the buses start charging as soon as they are plugged in . All buses then charge at the same time, causing maximum possible power draw .

Sequential charging entails breaking the fleet into batches . The first batch of bu ses begins charging and continues until fully charged. Once the first batch is complete, the second batch begins charging, and so on until all batches have completed charging.

This staggers the power demand on the grid throughout the night and results in lower power demand as compared to unmanaged charging.

Managed/Networked Charging
Another method of reducing utility costs and demand charges is the use of managed charging. Managed charging minimizes power demand by remotely monitoring the bus battery status, communicating with the chargers to prioritize which buses get charged, and regulating the amount of power each bus receives. Managed charging uses algorithms to control which buses should get charged and when . Managed charging software usua lly avoids having all buses charg e at the same time and can control the power level at which they charge, thus reducing power demand. Managed charging optimizes charging and can result in even lower power demand than sequential charging.

Many smart charging systems support the use of Open Charge Point Protocol (OCPP), which is a standard for charger-to-network communication. OCPP compliant chargers allow multiple types of chargers to be integrated by a smart charging provider. While these features are not necessary for charging electric buses, they are a useful tool for larger fleets, as they can ensure all buses charge on time while also reducing maximum power demand . Reducing maximum power demand is important —demand charges and utility interconnection cha rges are a function of max power demand. Smart charging systems can control charging behavior to reduce maximum power , decreasing maximum power draw by up to 31 - 65 percent (Eichman, 2020) and greatly reducing demand charges and the cost to operate the buses. Sometimes the charger manufacturer (e.g., ABB and Siemens) will offer their own networked charging solution . However, there are also other companies who specialize in this space as network providers.

The most basic software solution will remotely monitor the bus battery status while charging. This usually comes in the form of a web portal or app that the fleet manager can access at any time . The web portal can integrate data from the fleet operations/dispatch control system, yard management system, an d energy management/smart charging system . In addition, if a fleet purchases buses and chargers from multiple manufacturers, th e web portal can integrate this data in one place . Basic analysis, such as which buses use the most energy, which buses are havin g range problems, which buses are having a disproportionate amount of maintenance downtime, and battery state -of-charge can be regularly reported to the manager .

Some smart charging companies can also integrate telematics and real -time data from the buses into their smart charging systems. This information can be used by the smart charging software to prioritize which buses should be charged first to assure that all buses are ready for their respective duty cycles.

More advanced solutions will allow the charger to communicate with the utility grid. The data could be passed through in several ways, including aggregated at a network provider’s cloud service or individually sent to the utility via the OpenADR (Open Automated Demand Response) 2.0b protocol, or using the OpenADR with OCPP protocol. In this case, the utility could use OpenADR with OCPP to have open communication between the electric vehicle (EV) charging stations and central management Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-37
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24 software, enabling the charging system to serve as a demand response or excess supply asset. D emand response and excess supply programs incentivize customers to shift electricity load to different times of day to facilitate grid operations and s ystem- wide cost savings. Using OCPP on its own is also an option. Several charging manufactures support the OCPP standards , which allows the end user to manage various chargers with one compatible software management system.

To provide managed charging solutions, a network provider will typically need to collaborate with the utility serving the transit agency. In most cases, managed charging companies provide turnkey infrastructure construction and installation services . In doing so, the managed charging company provides the capital expenditures for the chargers and then signs a power purchasing agreement to sell the electricity to the transit agency. Appendix D provides details for managed/networked charging providers.

Hydrogen Fueling Cost Considerations
On-site vs. Delivered Hydrogen vs. Offsite Refueling Station The cost of hydrogen is influenced by several factors. One key factor is the location of hydrogen production. In general, the least expensive option is to produce hydrogen on-site at the bus fueling location . Hydrogen can be produced on-site using commercialized and technologically mature equipment—see On-Site SMR and On -Site Electrolysis for detailed descriptions of these processes. Using this technology, hydrogen can be produced relatively cheaply. Some SMR equipment manufacturers have estimated that hydrogen can be produced for as low as $6 per kg. However, on-site production requires capital investment, so it is not economically feasible to produce hydrogen on-site until a volume of 200 kg of hydrogen is reached.

Delivered hydrogen must be transported to the bus fueling location —see Delivered Gaseous Hydrogen and Delivered Liquid Hydrogen for descriptions of these options. The transportation of hydrogen via truck is an expensive process , and the majority of the cost of delivered hydrogen comes from transportation. Since delivered hydrogen requires less on-site infrastructure, this solution is more economically feasible for transit agencies that use low volumes of hydrogen. Delivered gaseous hydrogen is the best option for transit agencies that consume less than 200 kg of hydrogen per day, which is below the thr eshold at which on- site production is economically feasible. Liquid hydrogen has less volume than gaseous hydrogen, and therefore more liquid hydrogen can be stored on a truck than gaseous hydrogen, making liquid hydrogen delivery more economical. Due to off- gassing, delivered liquid hydrogen is most economical when a transit agency requires a large amount of hydrogen and will refuel daily.

Even though no heavy-duty stations currently exist near AVTO, retail fueling could be appropriate for fuel cell shuttle buses and dial-a-ride vehicles. Based on pricing data collected in February 2022 , the at -the-pump price charged at local retail stations is about $16-$17 per kg of hydrogen . However, it might be possible to negotiate a lower fuel price with a retail fu el provider in exchange for guaranteed fuel volume. See Offsite Refueling Station for more information.

Utility Charges for Producing Hydrogen
Utility charges are also an important factor in the price of hydrogen . Electricity is a required input for hydrogen. If hydrogen is produced by electrolysis, electricity is used as an input to produce the hydrogen . Electrolysis is energy intensive and producing hydrogen with this methodology will entail high energy and power demand (see On-site Electrolysis). The production of one kg of hydrogen requires 55 kWh. Additional energy is also required to compress the hydrogen so it can be dispensed. An electrolyzer would also have high power demands, which would lead to high utility bills. Hydrogen can be produced via electrolysis for about $10-$12 per kg . Furthermore, regardless of the source of the hydrogen, electricity is required to prepare hydrogen to be dispensed. Once hydrogen is produced or delivered, it must be compressed. In addition, the fueling station uses electricity. As a result, the use of hydrogen fuel will entail operational costs beyond that of the cost of the hydrogen and the fueling statio n.

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25 Route Modelling Overview
Overview of the Electric Bus Corridor Model (EBCM)
CALSTART, in partnership with Utah State University SELECT, developed a modeling tool to analyze and predict the performance of a BEB on a predetermined route, called the EBCM. Environmental factors like terrain and climate can have a significant impact on the range of BEBs. EBCM uses seasonal weather data, bus specifications, route characteristics, ridership, and other operational data to estimate the energy consumption of a BEB for various charging scenarios (depot only, on -route only, or both). EBCM is a dynamic and highly customizable input model that can be modified according to individual transit agency preferences and needs.

CALSTART was tasked with analyzing the electrification of bus routes as part of the AVTO Bus Electrification Feasibility Study.

Identifying the current and future operational needs, specific to the routes each agency runs, was imperative to determine which EV solutions (vehicle and charging infrastructure) may be suitable replacements for the existing fleet.

To complete this analysis, route level data such as ridership, average speed, number of laps per day, number of stops, topography, and time in operation was collected. CALSTART referenced the Altoona Test data for the potential electric bus models that could operate these routes. See Table 1-1 below for the complete set of customizable parameters that contributed to the modeling results.

Table 1-1. Customizable parameters that are inputs to the EBCM Vehicle Inputs Route Information Inputs Bus Charging Infrastructure Inputs
Bus type & length (ft) Service operation times Depot charger power & user specified output (kW)
Frontal area (ft2) Number of passengers Bus state of charge upper & lower bounds
Curb weight (lb) Average driving speed (mph) Overnight dwelling time at depot charger
Battery-to-wheel and regenerative
braking efficiencies
Number of bus stops along the
route Charging efficiency
Battery size (kWh) Distance and slope of route
topography
HVAC cooling and heating
performance factors
Service area elevation &
geographic coordinates
Desired cabin temperatures by
season (°F)
Seasonal temperature highs,
lows, and averages (°F)

As the first step in the analysis, CALSTART interviewed the fleet managers at each of the three participating transit agencie s in this study. The purpose of this initial touchpoint was to establish a mutual understanding of each agency’s goals for the analysis, Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-39
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26 as well as to gather key input parameters for the model. These meetings and subsequent follow up communications yielded important information, such as desired electric bus model options, existing bus routes of interest for electrification, bus passenger cabin HVAC and state of charge (SOC) preferred settings, charging preferences (depot vs. on-route), and other details.

Following this level-setting step, CALSTART determined geographic information for the routes to be modeled by EBCM. For the fixed-route buses, the agencies supplied geographic information system (GIS) data that was converted into a useful format for the tool. Because the on -demand dial-a-ride service routes vary by day and by passenger, CALSTART worked with the fleet managers to determine a hypothetical route with similar mileage and topography to some of the usual service routes. CALSTART then traced these routes on Google Earth to collect topographical inputs for distance and slope to be inputted to the model. The electric bus performance that was modeled in EBCM was also based on battery -to-wheel and regenerative braking efficiencies from published Altoona bus reports. The aim of using Altoona data is to ensure that the model is operating on verifiable thir d- party data, rather than rel ying exclusively on marketing materials from bus manufacturers. The next step in the process is gathering locational (longitude, latitude, elevation, and time zone) and seasonal weather inputs. This step is essential for the customization of bus performanc e specifications for a particular agency’s needs. It is also noteworthy that in the California context, extreme heatwaves are increasing in frequency and intensity. More instances of fluctuations in temperature are projected to have a significant impact on vehicle HVAC energy consumption, especially air conditioning. Air conditioning is a very energy intensive auxiliary function that can, in some cases, dramatically reduce the overall range of the electric bus. To account for these challenges, the EBCM analysis included a temperature maximum parameter of 120 degrees Fahrenheit for the summer season forecast.

The analysis yielded kWh energy consumption outputs by bus subsystem , which is divided into dynamic, heating, and auxiliary sources, and the average expected energy consumption by season. Additionally, the model estimates the remaining SOC per lap on a given route to give an approximation of how much of the regular service day can be covered by a single electric bus. The energy consumption outputs fro m this analysis were used to inform the development of charging schedules, costs, and location(s) for the future electric buses . The route modelling/energy analysis results for each individual transit agency is displayed in their specific chapters.

Resiliency
The introduction of BEBs introduces unique concerns relating to resiliency. All ZEBs are reliant on access to electricity. Electricity is needed to charge a BEB and to produce hydrogen. Even if hydrogen is produced and stored on -site, large amounts of power are required to compress and dispense the hydrogen. As a result, if there is a loss of power, transit agencies would be unable to charge or refuel their buses. Extreme events, such as storms, hurricanes, natural disasters, terrorism, or cyberattacks, can cause the grid to go offline for longer periods of time . For example, in 2017, the American Northeast experienced extreme winter storms, which caused disruptions to power service to the region . Likewise, in 2017, states such as Florida and Georgia experienced outages from hurricanes ; in the aftermath of Hurricane Maria, Puerto Rico experienced the worst blackouts in American history. More recently, in February 2021, Texas experienced a lengthy grid outage following a polar vortex . Lengthy outages such as these could easily prevent transit agencies from engaging in routine charging of their buses, which would then disrupt normal service and core transit operations . Since many members of the community use public transport to get to and from work, such disruptions would have major economic implications and negatively affect public perception of ZEBs.

AVTO faces unique resiliency risks. The Los Angeles region is subject to several factors that can disrupt utility power to bus yards.

One major threat is extreme heat, which is expected to become a much more common occurrence as climate change progresses.

Extreme heat poses a threat to the grid because it decreases utilities' generation and transmission capabilities . Extreme heat also increases air conditioning usage and consequently power demand (Burrillo, 2018). These factors raise the chances for grid infrastructure overload, which further increases the risks of a brownout, blackout, or other grid outage . Extreme heat can also Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-40
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27 cause equipment to overheat, posing a threat to any electrical equipment owned by a transit agency (National Academies of Science, Engineering, and Medicine, 2017).

Public Safety Power Shutoffs (PSPS) are a major risk to power supply in the L os Angeles region. These shutoffs occur when environmental conditions increase the chances that utility infrastructure will spark a wildfire. While the risk of wildfire occurring in Los Angeles proper is low, there is a high risk that wildfire can disrupt electrical supplies . PWP, Burbank Water and Power (BWP), and Glendale Water and Power (GWP)—the municipal utilities that serve AVTO—obtain power from a variety of sources.

While some power is generated locally, these municipal utilities import a significant percentage of power from generation facilities to the north of L os Angeles and even from other states . Much of this power is transported through the northern transmission corridor . If a PSPS is declared in that region, it disrupt s power supplies to the entire L os Angele s region.

Furthermore, natural disasters can pose resiliency risks . Earthquakes can potentially down power lines and damage utility substations, which would threaten power supply to bus depots.

Addressing resiliency concerns should be a priority for trans it agencies deploying ZEBs. AVTO can obtain resiliency through two main methods. One method is to obtain in front-of-the-meter (FTM) resiliency. FTM resiliency is provided on the utility’s side of the meter. Resiliency can also be provided behind-the-meter (BTM). BTM refers to resiliency solutions located on the customer’s side of the meter. A BTM resiliency solution would be controlled by the transit agency. Both FTM and BTM solutions are discussed in more detail on page 28.

Regardless of whether the res iliency is BTM or FTM, providing full resiliency for a bus depot is difficult . ZEBs consume a large amount of energy and draw a lot of power from the grid . This is especially true for BEBs, which use electricity directly as fuel .

Figure 1-13 depicts a hypothetical scenario in which fifty electric buses are charged at a power level of 60 kW . This illustration shows that a fleet of fifty buses would generate power demand of 3 megawatts (MW), which exceeds the power demand from the TransAmerica Pyramid Buildin g (a skyscraper in San Francisco ). In the event of a grid outage, it is difficult to replace the energy and power lost from the grid.

Figure 1-13: EV Peak Power Demand Scenarios (CALSTART, 2015)

The transit agencies in AVTO will collectively deploy a large fleet. Each transit agency is expected to have significant energy consumption and power draw. The energy consumption and power draw for each transit agency is provided in Table 1-2 below.

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28 These figures represent energy consumption and power draw for weekday service, the maximum energy consumption and power draw. Furthermore, these figures exclude any energy or power demand from on-site buildings or maintenance bays.

Table 1-2: Daily Energy Consumption and Power Demand
Energy Consumption
/ Power Demand
Time
The Pasadena
Department of
Transportation
Glendale Beeline BurbankBus
Weekday Energy
Consumption (kWh) 9,563 9,614 3,053
Weekday Power
Demand (kW) 2,792 2,210 977
Weekend Energy
Consumption (kWh) 4,341 5,358 -
Weekend Power
Demand (kW) 1,500 900 -

The remainder of this section will explore various options for providing resiliency for a transit agency.

FTM Resiliency
FTM resiliency is provided by the utility , and the utility can provide resiliency in several ways , such as installing energy storage assets or distributed generation assets at power plants or at a substation . If power is lost, the assets can be deployed and can provide power to customers downstream. Utilities typically charge for resiliency services to offset the cost of these assets. Some utilities offer special electrical tariffs to customers that opt to accept utility resiliency services . These tariffs often entail higher energy charges.

For example, the Los Angeles Department of Water and Power (LADWP) offers various options for resiliency, including a special pilot rate for electric buses. Under these rates, fleets have the option of providing their own resiliency, accepting FTM resiliency from LADWP, or not having any resiliency. If a customer opts to receive FTM resiliency from LADWP, they can choose the length of time they will receive resiliency in the event of a grid outage . LADWP’s resiliency is provided by FTM batteries . Each of these options is associated with a specific tariff.

Utilities can also provide FTM resiliency in other ways . Typically, a fleet is served with a single feeder . A utility could bring a second feeder to the fleet to act as a redundant source of power . Alternatively, if a utility has local power plants, they can potentially use the power plants as a backup source of power in the event of an outage.

BTM Resiliency
A fleet can also receive BTM resiliency . BTM resiliency consists of generation and storage assets that are located on the customer’s side of the meter and, in most cases, on-site at the fleet’s depot. Transit agencies have multiple options for deploying BTM resiliency, such as opting to serve as the owner-operator of resiliency equipment. Under this ownership model, the transit agency provides the capital funding to purchase and install the equipment, and is responsible for operating and maintaining the equipment. Transit agencies can also engage with a third -party energy services company to purchase power . The third-party energy services company would be responsible for purchasing and installing the equipment. The energy services company would retain ownership of the equipment and would sign a power purchasing agreement with the transit agency to sell the energy produced by the equipment . There are also myriad other hybrid business mo dels that can be used to operate BTM resiliency equipment. The following is an overview of different assets that can be used to provide BTM resiliency.

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29 Solar and Storage
Solar PV systems can be used to provide BTM resiliency. Solar PV panels convert solar radiance from light to produce electricity.

As a result, solar PV produces electricity during the day, with peak production occurring at about 1 pm . Solar PV arrays can be installed anywhere with access to direct sunlight . Solar PV arrays are often installed on rooftops, but arrays can also be constructed over parking lots. This solution requires the construction of a steel structure over the parking lot to install the panels.

Many transit agencies have started installing solar panels over the bus parking lanes. This configuration allows the transit agency to maximize the solar potential of their yard and provides shade for the buses , keeping the buses cool and reducing the HVAC load.

While solar PV can produce renewable energy, it does suffer from two main drawbacks. First, solar PV is not an energy dense generation asset. ZEBs are extremely energy intensive, and a large quantity of solar panels is required to power the charging for a fleet of ZEBs. Since many bus depots are space constrained, it is usually not possible to install enough solar panels on a depot to power the charging for a ZEB fleet , especially for transit agencies in urban areas . It is difficult, then, to provide full resiliency to a ZEB fleet from solar PV alone. Solar PV is also an intermittent resource that only produces power during the day, which can be used to help power facilities at a bus depot, but the majority of the buses will be charging at night to take advantage of lower energy charges. As a result, a mismatch arises between when the solar panels produce electricity and when charging occurs ; if a transit agency were to experience a grid outage, they would not have any resources to power charging at night.

One way to solve the intermittent power problem would be to pair solar PV with battery storage . Under this solution, battery storage would be used to absorb excess energy that is produced during the day and store it for later use. The batteries could be used to store power until nighttime or until there is a grid outage . Batteries can help to mitigate the intermittency problem . In addition, batteries can respond very quickly to gri d outages and can ensure continuity of power . However, batteries are expensive and have a large physical footprint, resulting in limits to energy storage capacity on a bus depot.

Another variation of solar and storage would be battery swapping. ZEBs are currently designed so that the batteries remain on the bus at all times . When the batteries need to be recharged, the bus m ust physically go to a charger . The charging process requires hours, which prevents the bus from being used during that time. However, it is theoretically possible to recharge a bus by removing the depleted batteries from the bus and swapping them with fully charged batteries . The concept of battery swapping is not new and has been considered to speed up the charging process in light -duty EVs. If battery swapping were employed, depleted batteries can be removed from the bus and then charged during the day using solar power . The charged batteries could then be installed on the bus at the end of the day.

While battery swapping is a theoretical possibility, the current ZEB design, which is optimized for meeting safety regulations, is not conducive to this option. Batteries are extremely heavy , and they are often placed on the roof of the bus or in other are as that are not easily accessible. It would therefore be difficult to remove batteries on a regular basis. At the time of writing, none of the OEMs have a bus that can employ battery swapping , though some industry interest exists in conducting research to develop battery swapping and business models that can support this practice.

Generators
A transit agency could also use a generator to provide power in the event of a grid outage . Generators typically use fossil fuels such as diesel or natural gas. These fuels are combusted in an internal combustion engine, which is used to produce electricity .

Most generators are reciprocating engines . Generators are useful ; they are energy dense , produce a large amount of power without having a large physical footprint , and can feasibly be sized to power a majority of or the entire fleet . The physical footprint required for generators at each transit agency is described in Appendices K, L, and M. Generators can also respond relatively quickly to outages and take about ten minutes to full ramp up to maximum power generation. In addition, generators Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-43
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30 do not have to operate at full power at all times and can run at partial capacity without major efficiency losses . However, this solution is problematic—since generators burn fossil fuels, they produce GHG emissions. In addition, they can produce criteria emissions such as particulate matter (PM) and NOx. As a result, there are environmental and air quality consequences to using generators.

Further, there are regulatory restrictions on the use of generators . The South Coast Air Quality Management District (AQMD) has a mandate to regulate stationary sources of air pollution in the Southern California region . Since generators emit criteria emissions, they are subject to reg ulation by AQMD . The main regulation is Rule 1110.2, which has stringent regulations on emissions from generators. However, there are some ways that a generator can be exempted from Rule 1110.2. For example, a backup generator is exempt from Rule 1110.2 . In Rule 1110.2, AQMD defines a backup generator as a standby internal combustion engine or turbine that is used for non-utility power and does not operate for more than 200 hours per year. Backup generators are only allowed to operate during an emergency po wer failure or outage or for routine testing and maintenance .

Backup generators that use natural gas as a fuel can be operated when the California Independent System Operator (CAISO) declares a Stage II or Stage III electrical emergency . A Stage II emergency occurs when CAISO declares that they have taken all actions to avoid an outage and are not able to provide expected energy demand . A Stage III emergency occurs when CAISO declares that it cannot meet minimum contingency reserve requirements and a grid o utage is about to occur or has occurred .

To apply for a backup generator permit, a transit agency would need to submit Form 400A, Form 400 -CEQA, and an application fee according to Rule 301. It takes approximately four to six months to obtain a permit. The permit process can be expedited to three months, but this will result in a higher application fee.

There are cases when a transit agency might exceed the 200-hour limit. If there is an extended power outage, then it is possible that the generator will need to be used for more than 200 hours in a year . If a transit agency is on pace to exceed 200 hours of operation in a year, they can apply for a variance to operate the generator for more than 200 hours. To apply for a variance, the transit agency would need to schedule a hearing with AQMD’s Hearing Board. At the hearing, the transit agency can explain why they need the variance , and a decision to grant or deny the variance is g iven the same day . It can take up to fifteen days to schedule a hearing, so it is important to schedule a hearing before the 200-hour operation limit is exceeded.

If a transit agency wanted to avoid obtaining a backup generator permit, they theoretically could rent a backup generator during a grid outage . If a transit agency decided to do this, they would need to rent a generator that has been permitted by AQMD .

Renting a generator in the event of an outage could be beneficial as it would allow the transit agency to avoid the capital expenditures associated with purchasing and install ing a generator. However, it does take time to rent a generator and have it delivered to the site ; the bus depot would be without power until the generator arrives . Furthermore, in the event of a grid outage, other entities would be seeking backup generato rs, making it difficult to find a generator during an emergency outage .

It is recommended that a backup generator be located on-site at all times.

Stationary Fuel Cells
A stationary fuel cell can also be used to provide power in the event of a grid outage. Fuel cells typically consume a fuel and use an oxidation reaction to produce electricity . Fuel cells are most often associated with hydrogen vehicles , which use a fuel cell that oxidizes hydrogen to produce electricity to power the vehicle . However, a fuel cell, like those designed by Bloom Energy and Doosan, can also be designed to use other hydrogen-rich fuels such as natural gas as the source of fuel. Stationary fuel cells are fuel cells deployed for non-vehicle usage and serve an equivalent function as a backup generator.

Stationary fuel cells are comparable to backup generators in that they consume a fuel to produce electricity , but they produce fewer emissions than backup generators . If a stationary fuel cell uses hydrogen as fuel, then there would be zero direct GHG emissions from using the fuel cell. A fuel cell that uses natural gas as fuel, however, would still produce GHG emissions, but since Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-44
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31 fuel cells use an oxidation reaction rather than combustion to produce electricity, they produce far fewer criteria emissions. As a result, the regulations on fuel cells are less restrictive than those for backup generators .

Stationary fuel cel ls do have some drawbacks , one of which is that they are most efficient when operating at full power. Fuel cells cannot easily operate at partial capacity . Furthermore, starting up a fuel cell takes time , meaning a fuel cell cannot immediately respond to a grid outage . Fuel cells work best then in conjunction with other assets and when there is a constant load, such as from a building, for them to serve . AC Transit is currently using a stationary fuel cell as a part of their energy portfolio.

Microgrids
A microgrid is a local grid that uses distributed energy resources (DER) and energy storage assets to provide power to a specific campus or locality . In the transit context, a microgrid would consist of DERs that can provide power and resiliency services t o the transit agency’s depot. A microgrid can use a combination of DERs. A key feature of a microgrid is that it can disconnect from the utility grid and generate power for itself. This functionality is managed by a switch at the point of connection with the utility grid and a controller that decides when to connect to and disconnect from the grid. When microgrids use a variety of generation and storage sources, it provides the microgrid with options for deploying the most appropriate type of power generation. For example, if a grid outage were to occur during the day, the microgrid could opt to provide power with solar panels to maximiz e its use of carbon-free energy, whereas if the outage were to occur at night, the microgrid could opt to use a natural gas generator or batteries when intermittent energy sources are not generating power.

A microgrid can also provide other services for a transit agency. Microgrids can help transit agencies engage in demand response.

While transit agencies can reduce their power demand by using smart charging software, many larger agencies will still have high power needs . A microgrid can allow agencies to further reduce their demand by storing self -generated energy or excess power from the grid during times of low pow er demand and deploying it to partially or completely charge a fleet of buses . This solution would reduce the spike in power demand caused by charging, which would aid in grid management and reduce demand charges for the transit agency . The microgrid controller can also be programmed to interact with energy markets and sell self - generated power during times when demand for grid power is high , allowing the transit agency to help manage the utility grid and generate revenue. The utility could also benefit from microgrids being used in this manner. If the microgrid is able to prevent demand spikes, it could also potentially reduce the need to upgrade utility distribution infrastructure . It should be noted that the function of the microgrid can be limited . If a microgrid includes a backup generator, the generator can only be used for emergency purposes and cannot be used to provide ancillary services.

Maintenance and Training
Many similarities exist between ZEBs and CNG buses , but ZEBs have unique systems such as electric drivetrains, batteries, fuel cells, and hydrogen storage tanks that require specific operational and maintenance needs. These systems have particular needs and require specialized training to service . In addition, ZEBs must be operated and driven differently than a CNG bus to obtain the maximum performance from the buses.

Most of the bus operations and maintenance work for the AVTO's fleets are contracted out to transportation services companies.

The Pasadena Department of Transportation and Glen dale Beeline have contracted with private transportation services companies to provide bus operators and maintenance staff . BurbankBus contracts with a transportation services company to operate and maintain the ir fixed-route fleet , but uses City of Burbank employees to maintain and operate the Senior and Disabled Fleet.

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32 If an agency uses a transportation service contractor, the maintenance and operations is provided by the contractor. As a result, the contractors will need to provi de trained bus drivers and maintenance staff . Since some of these transportation service contractors also serve other fleets with ZEBs, their drivers and mechanics might have previous experience with ZEBs .

BurbankBus, however, will need to obtain training for the maintenance staff. In addition, each transit agency will need to conduct maintenance on bus infrastructure. This section will provide an overview of the maintenance and training that is required to operate a ZEB fleet and associated infrastructure.

Bus Operator Training
Bus operators will need training to drive and operate ZEBs. ZEBs need to be driven in a certain manner to optimize performance and bus range . Typically, electric buses maximize their range when accelerated slowly . Poor driver behavi or, such as rapidly accelerating from a stop, can reduce bus range by up to 25 percent. As a result, ensuring the bus operators drive the buses in the correct manner is vital to maximizing the benefits of ZEBs. Range anxiety, where the driver fears that th ey do not have enough charge to complete their route , has also been widely documented . This fear has resulted in operators prematurely ending their route and returning to the depot to charge the bus . To avoid this problem, bus operators need to understand the range and capabilities of the bus . Bus operators also need to learn how to correctly use technologies such as regenerative braking.

Bus Technician Training
ZEBs have different maintenance needs and operation best practices than traditional internal co mbustion engine buses . ZEBs replace the internal combustion engine with an electric drivetrain , which changes the maintenance needs of the bus . While maintaining a traditional bus, a maintenance technician needs to have expertise in maintaining and repairi ng internal combustion engines and moving parts like belts, alternators, and pumps . In addition, expertise in mechanical systems such as steering, HVAC, and suspension is vital . However, with ZEBs, the vast majority of the moving parts are replaced with electric components, such as batteries, DC-to-DC converters, and electric motors. Since there are few moving parts on a ZEB, the majority of the maintenance tasks relate to prevent ative maintenance. As a result, the most vital skills for maintenance technicians to become proficient in are high voltage safety and proper use of personal protective equipment to minimize the risk of electric al shocks and arc flashes. Mechanics should consider obtaining the NFPA 70E: Standards for Electrical Safety in the Workplace and High Voltage OSHA 1910.269 8 Hour Qualified Training Course certificates . Maintenance technicians will also need to become proficient in bus inspection, preventative maintenance, and how to handle removed battery systems to effectively maintain the buses. Knowledge of standard bus mechanical systems is also important . If a fleet has hydrogen FCEBs, the maintenance technicians need additional skills . Hydrogen is a highly flam mable gas, meaning that it requires specialized skills . Technicians working on hydrogen buses need training in high pressure gases and hydrogen safety . Local first responders need to receive training in EV and hydrogen safety so they can effectively respond in the event of an accident.

Technicians receive their training through a variety of sources , which usually start s in an automotive program at either a community college or trade school. While at community college/trade school, technicians are introduced to automotive safety, vehicle systems, engines, and mechanical systems . Many students will also learn about electric and hybrid drivetrains . Many community colleges such as Rio Hondo College and San Bernardino Valley College have devoted EV Associate of Sciences programs.

After completing community college/trade school, technicians are then hired by a fleet or a transportation services company .

Technicians usually receive on -the-job training after they are hired . Their employer often provides one-on-one training so the technician can work on real -life maintenance and repair issues . Bus OEMs also provide training to technicians . This training typically begins one week before the bus is delivered . The OEM will send a field service representative to provide bus operator training to the contractor’s drivers . The field service representative provides safety, preventative maintenance, and diagnostic/troubleshooting training to the mechanics . Since this training is specific to the buses and is generally at a mor e Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-46
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33 advanced level, it is important that the technicians have some experience with the basics of zero-emission vehicle maintenance before attending the OEM’s training. The pricing for OEM-specific training is provided on page 40.

The field service represent ative is also vital for training mechanics on more advanced maintenance tasks . During the warranty period, if repairs or troubleshooting beyond preventative maintenance are needed, the field service representative can be called to teach the mechanics how to fix the issue. It is important to use the warranty period to provide further training to its mechanics.

If there are problems with any of the non -drivetrain components on the bus ( e.g. the HVAC system), many component manufacturers offer similar services.

There are other avenues for obtaining maintenance technician training . SunLine Transit in Thousand Palms, California , is currently operating the West Coast Center of Excellence in Zero Emission Technology (WCCoE) . The WCCoE offers workforce development training for transit agencies . As a part of this training, the WCCoE offers tec hnician training in multiple formats, including on-site at the WCCoE, virtual training, and webinars . On-site training at the WCCoE includes hands -on lab work with actual buses.

The Southern California Regional Transit Training Consortium (SCRTTC) also of fers training for ZEB technicians . SCRTTC is a membership-based organization that counts many Southern California transit agencies as members . SCRTTC works with OEMs to provide training in a wide range of zero-emission technologies and bus mechanical systems. This organization works with the OEMs to provide train-the-trainer programs, including classroom and hands-on training.

Workforce Development Training Plan
Each transit agency will need to provide training to their workforce to ensure that they have th e skills to operate and maintain ZEBs and infrastructure. The transit agencies in the Arroyo Verdugo Transit Operators do not hire their own mechanics or bus operators. Instead, they contract with a transit company to provide mechanics and bus operators. The contractor is responsible for hiring and providing training to mechanics and bus operators. When ZEBs are purchased, the contractors will need to ensure that their workers have the skills to maintain the buses. Since many traditional vehicle maintenanc e competencies (such as suspension, mechanical systems, HVAC systems, etc.) are transferable for maintaining ZEBs, the easiest way to develop a workforce is to upskill the existing bus operators and maintenance staff . The prerequisite knowledge required to begin ZEB maintenance training is a firm understanding of high -voltage electrical systems and safety. The contractor will need to provide high-voltage electrical training for their maintenance staff before they begin tra ining.

To upskill the existing staff, a transit agency should purchase training packages from the OEM. OEM -provided training teaches maintenance staff how to operate and maintain a zero emission drivetrain system. The OEM-provided training begins about a week before the delivery of the buses. The OEM send s a field service representative to provide bus operator training to the contractor’s drivers. The field service representative will also train the maintenance staff. Since there are few moving parts on a zero emission bus, the majority of the maintenance tasks relate to preventative maintenance. As a result, the field servic e representative provides safety, preventative maintenance, and diagnostic/troubleshooting training to the contractor’s mechanics. The field service representative is also vital for training mechanics on more advanced maintenance tasks. During the warranty period, if repairs or troubleshooting beyond preventative maintenance are needed, the contractor may call out the field service representative to fix the issue and teach the mechanics how to fix it. Using the warranty period to provide on-the- job training to the mechanics is vital to developing the skills of the maintenance staff. Overtime the maintenance staff will accrue enough knowledge to work independently from the field service representative. This knowledge can be institutionalized by pairing more experienced maintenance staff with junior sta ff and new hires to teach them maintenance best practices . OEM- provided training can also be supplemented with training provided by o ther organizations such as the SCRTTC, the California Transit Association, American Public Transportation Association, CalACT, and the National Transit Institute.

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34 Bus Maintenance Requirements
BEB Maintenance
BEBs have an electric drive train that is powered by electricity from an energy storage system , and consequently lack some of the components in an internal combustion engine bus, especially some of the mechanical systems in the propulsion system. The maintenance needs for the propulsion system are therefore different in BEBs than internal combustion engine buses . Despite these differences, BEBs do share many mechanical systems with internal combustion engine buses, such as brakes, suspension, door opening systems, the cab, and chassis, so some of the maintenance needs will be similar.

Those transit agencies that have already deployed BEBs, can provide lessons about the maintenance needs for these vehicles. A number of these agencies reported that BEBs have fewer moving parts and therefore fewer parts to replace. BEBs do not require oil changes and do not have belts that need to be replaced. As a result, certain aspects of preventative maintenance for BEBs is lower than for CNG buses, with the main cost being labor and time.

Transit agencies have reported some issues in regard to unscheduled maintenance for BEBs, with the earlier generation of BEBs experiencing some problems and failures with major components such as high voltage batteries and inverters. Another common issue has been the wires from the high voltage batteries. These wires are held together by connector pins. On many buses, these connector pins have corroded and come apart, preventing energy from being transferred from the battery to the drivetrain .

Some BEBs have also experienced problems with the low voltage batteries . In these buses, auxiliary equipment such as the security camera system continue d to draw power even after the bus was turned off . This issue depletes the battery. Despite these problems, the drivetrain itself has proven to be very reliable , and most buses only experience minor problems with the drivetrain.

Unfortunately, these problems have been costly , and the cost of unscheduled maintenance is higher for BEBs than for CNG buses. The bus availability in a fleet of BEBs has also been significantly lower than for CNGs . One transit agency reported th at the availability for CNG buses is about 95 percent, while BEB availability is about 70 percent. This low rate of availability has been caused by the fact that repairs on BEBs can take time to resolve. Some parts can be difficult to obtain, and sometimes diagnosis of a problem is not quickly resolved . As a result , BEBs can be out of service for up to 20 -30 days in the event of an issue . To improve bus availability, ensuring the quick delivery of parts is vital . Transit agencies can also mitigate this problem by stocking extra parts.

Since some transit agencies have already deployed BEBs, there is data available on maintenance needs and costs. Foothill Transit has a fleet of BEBs: twelve 35-foot Model year 2014 buses and two 40 -foot Model year 2016 bus es (Eudy, 2020). The National Renewable Energy Laboratory (NREL) has been tracking the maintenance costs for this fleet and has compared it to the costs for the CNG fleet. NREL found that the maintenance costs for the 35 -foot BEB fleet is $0.84 per mile and $0.53 per mile for the 40- foot BEB fleet. CNG buses have lower maintenance costs of $0.23-$0.42 per mile. Since all three fleets are out of warranty and Foothill Transit has taken over maintenance, these figures are comparable.

Although this data indica tes that the maintenance costs are higher for the BEB fleet, there are several caveats in the data to consider. First, the BEBs had lower scheduled maintenance costs than the CNG fleet . The 35-foot and 40-foot BEB fleet had scheduled maintenance costs of $ 0.05 and $0.04, respectively . The CNG fleet had scheduled maintenance costs of $0.10 . As a result, the main difference in cost between the BEB fleets and the CNG fleet is unscheduled maintenance . Some of the unscheduled maintenance figures were also skewed by an issue with the low -voltage batteries, which had to be changed out frequently. The bus manufacturer is working to resolve these issues , and the low -voltage battery problem is not expected to emerge in future generations of their bus. When the cost of the low-voltage battery problem is excluded, the maintenance cost Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-48
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35 for the 35-foot and 40-foot BEBs are $0.72 and $0.48, respectively.

NREL also measures data on bus availability , which is defined as the percentage of days the bus is available for service . NREL issued a report analyzing BEB availability at Foothill Transit . This report found that Foothill Transit's CNG bus fleet had an availability of 95.1 percent. The fleet of 35 -foot BEBs had a bus availability of 83.1 percent, and the 40-foot fleet had a bus availability of 81.6 percent. In most cases, general maintenance is the cause of bus unavailability. However, other issues such as problems with the electric drive or energy storage system can cause the buses to be unavailable . Significant variation of bus availability exists within the fleet; that is, some buses will have lower availability than others. For example, between Q3 and Q4 2019, some buses had a bus availability as high as 82 percent and others as low as 42 percent. Moreover, bus unavailability tends to increase as the buses get older, much like bus maintenance costs.

Maintenance and bus availability figures are also for older generations of buses . Since buses have continued to develop and become more technologically mature, newer generations of buses are likely to have fewer problems with unscheduled maintenance and unavailability. During interviews with CALSTART, OEMs and other transit agencies in the Southern California region reported that newer generations of buses have proven to be more reliable and have had higher bus availability.

FCEB Maintenance
Like BEBs, FCEBs have an electric drive train t hat is powered by energy from a battery . Many of the maintenance tasks will be similar for both BEBs and FCEBs , but FCEBs are unique in that energy is provided to the battery by a fuel cell . Since FCEBs use high pressure gases, many maintenance tasks are similar to that of a CNG bus. However, the fuel cell and its supporting systems introduce maintenance needs that increase the amount of required maintenance tasks and the overall maintenance cost . NREL has been investigating the maintenance needs and costs for FCEBs: tracking and reporting on the maintenance needs of several FCEBs deployed at SunLine Transit, NREL has compared them to the CNG buses deployed at the same agency. NREL reports that on a cost per mile basis, the FCEBs have a higher maintenance co st than the CNG buses . The maintenance cost for CNG buses has been reported at $0.23 - $0.42 per mile whereas the maintenance cost for the FCEB fleet was reported at $0.56/mile (Eudy, 2020a).

It is important to note that many of the maintenance tasks are common between a CNG fleet and an FCEB fleet. Like BEBs, FCEBs still have many of the same mechanical systems as CNG buses . This includes systems such as brakes, suspension, door opening systems, the cab, and the chassis . Not surprisingly, both types of buses had to undergo maintenance on systems such as the brakes, low voltage batteries, and suspension . However, there are a couple of systems that seem to be responsible for the majority of the difference in cost between the two types of buses, such as the propulsion system . The maintenance cost of the propulsion system is more than three times higher for FCEBs than for CNG buses . In addition, basic preventative maintenance and inspection is also approximately twice as high for FCEBs than for CNG buses.

NREL also reports on the reliability of FCEBs. NREL uses bus availability as their metric to measure reliability . NREL’s analysis of SunLine’s fleet indicates that FCEBs have lower bus availability than CNG buses . SunLine’s CNG fleet had an availability of 87 percent whereas the FCEBs had an availability of 73 percent. The availability for each individual bus ranged from 60 percent to 89 percent between January 2017 and July 2019. Approximately one third of bus unavailability was caused by routine problems with bus mechanical systems . However, one quarter of bus unavailability was caused by issues with the fuel cell and/or propulsion system. The FCEB’s lower availability was influenced heavily by an event in 2017, where two of the older buses were both unavailable for an entire month—this outlier event lowered the availability figure for the FCEBs.

As a part of this study, CALSTART interviewed SunLine Transit to better understand their experiences with an FCEB fleet. SunLine Transit stated that their experience has been positive and that much of the maintenance for FCEBs is similar to CNG buses. Most Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-49
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36 of the maintenance work they have done has been routine maintenance . However, there are some general preventative maintenance and inspection tasks that are unique to FCEBs. For example, the fuel cell system has several components that need to be replaced regularly, such as particulate filters, deionizing filters (to deionize the water in the fuel cell coolant system), and air filters. These additional tasks increase the cost in comparison to preventative maintenance for CNG buses.

SunLine Transit also provided information about maintenance for the propulsion system. SunLine stated that they do not directly perform maintenance on the fuel cell . Instead, any fuel cell maintenance is handled by the fuel cell manufacturer. The fuel cell manufacturer has a field representative that can be on-site within one day to fix any fuel cell-related issues that arise. If there is a problem that cannot be solved quickly, the fuel cell can be removed and sent to the fuel cell manufacturer for repairs. If this occurs, the fuel cell manufacturer provides a replacement fuel cell that can be used until the issue is resolved . SunLine Transit noted that the drivetrain and fuel cell systems have been very reliable and that they have not needed to receive a replacemen t fuel cell yet . Instead, most of the maintenance on the propulsion system has been due to balance -of-plant components and systems that support the fuel cell , including pumps and the fuel cell cooling system . Other transit agencies have also had this experience and have reported that most bus outages result from problems with balance -of-plant components or auxiliary components such as the HVAC system, rather than from the fuel cell or the drivetrain . SunLine noted that they have been able to obtain replacement parts easily from the fuel cell manufacturer, which gets buses back in operation quickly. In addition, most of the maintena nce performed on the buses to date has been through their warranty and helped to reduce the cost of maintenance. However, once the warranty is finished, the cost of maintenance is subject to increase . According to NREL’s data, out of warranty, older buses have higher maintenance costs per mile than newer buses in warranty.

In addition, the amount of unscheduled maintenance for FCEBs at SunLine fell between 2017 and 2019, which implies that the buses have become more reliable . This decrease might be occurri ng as the buses become more technologically mature —it is possible that maintenance costs between FCEBs and CNG buses can converge in the future.

Infrastructure Maintenance Requirements
Plug-in Charging Infrastructure
Charging infrastructure requires mainte nance, though most of the components are non -moving parts with fewer maintenance needs. Most maintenance tasks focus on changing air filters in the charger and performing inspections . However, components can break from time to time . Since there is an established supply chain for these components, repairs are usually routine and completed quickly. For many chargers, the biggest threat is accidentally damaging the charger receptacle by driving over it. The use of DC fast chargers and networked chargers can increase maintenance needs; DC fast chargers have cooling equipment that can need maintenance and repair . Networked chargers also have data and communications equipment that can potentially break.

Transit agencies can rely on their ch arger manufacturer to provide maintenance . The chargers usually come with a warranty during which the manufacturer is responsible for maintenance and repair tasks . If the transit agency opts to pay for networked charging services, the chargers can communic ate with the network and can alert the charging company to any problems the charger is experiencing . After the warrant y period expires, the transit agency can opt for an extended warranty, pay for a maintenance package, or take over maintenance with their own staff. Charging companies typically plan for up to two planned outages per year to do routine maintenance . Although the actual maintenance tasks are relatively easy to carry out, the labor costs of the maintenance can be substantial, as a certified electrician is needed to perform all maintenance tasks. In addition, if the transit agency uses overhead plug-in chargers, a manlift is required to elevate maintenance worker to the chargers.

The Electric Vehicle Infrastructure Training Program (EVITP) provi des training to electricians on how to install EV charging infrastructure. Electricians who complete this program can receive EVITP certification. This certification is accepted as industry- Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-50
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37 standard, and some California Energy Commission (CEC) grants even require that a certain percentage of electricians working on EV charging infrastructure have EVITP certification . EVITP also provides training on maintaining, troubleshooting, and commissioning EV chargers. It is recommended that maintenance staff who work on chargers obtain EVITP certification.

Overhead Charging Maintenance
Unlike plug-in chargers, overhead chargers have moving parts that require a prescribed set of preventative maintenance that needs to be performed regularly . Every month, the overhea d charger requires an inspection to ensure that the wiring and the brushes are functioning property. Every six months, maintenance technicians measure the energy and charging capacity to make sure the charger is outputting the correct amount of power . On a yearly basis, maintenance technicians inspect the charger to ensure that the wiring and communication systems are working properly . Maintenance is typically carried out by the OEM, and the manufacturer will normally offer a maintenance service package.

Hydrogen Production Equipment and Fueling Stations Maintenance The type of maintenance on-site hydrogen production equipment requires depends on the type of hydrogen infrastructure in place. If hydrogen is produced on-site, the transit agency will require an electrolyzer or SMR, in addition to compression and dispensing equipment. If the transit agency receives delivered hydrogen, storage tanks and a fueling station are required.

NREL has conducted research on maintenance needs for hydrogen production equipm ent and fueling stations . According to NREL, the compressor is the single component most likely to fail (Eudy, 2018). The compressor is used to take hydrogen from the hydrogen production equipment and compress it to be placed in high pressure storage . Since hydrogen cannot be compressed into the dispenser without the compressor, this component is very important to ensure fuel availability. Therefore, NREL recommends that transit agencies have redundant compressors so their system can still operate if one c ompressor fails.

NREL also notes that dispensers and the hydrogen chilling system also frequently require maintenance (Saur, 2020). CALSTART estimated this frequency by using Argonne National Laboratory's Heavy-Duty Refueling Station Analysis Model ( HDRSAM). This analysis has been included in Appendix N.

To better understand maintenance needs for electrolyzers, CALSTART interviewed SunLine Transit . SunLine Transit has an electrolyzer and has paired the electrolyzer with a solar panel array to power it . SunLine Transit states that most of the maintenance for their electrolyzer has focused on route maintenance tasks. Maintenance workers perform a daily walk-through to inspect for safety issues or operating malfunctions. Maintenance workers also perform a w eekly inspection to check water plumbing systems, compressor oil levels, and any system faults or alarms. SunLine also stated electrolyzers are more vulnerable to problems . Since SunLine Transit operates in extreme heat during the summer, cooling and chill ing of the hydrogen has historically been an obstacle . However, to address this issue, SunLine Transit added auxiliary cooling systems, which has effectively eliminated this problem.

SunLine Transit reported few problems with infrastructure unavailability , partly because obtaining replacement hardware components such as compressors is relatively easy with an established supply chain. Some of the controls are manufactured in Europe and were previously difficult to obtain , but these parts are now stocked in Northern California . SunLine Transit did mention that a brief power outage prevented them from operating the electrolyzer. To mitigate this problem, SunLine Transit is building a redundant system to store and produce hydrogen in the event of an outage.

Another factor in infrastructure maintenance is hydrogen purity. It is vital that hydrogen, whether produced on-site or delivered, is pure and does not contain contaminants. Contaminants in the hydrogen, as listed in Figure 1-15, can reduce the performance of the fuel cell. The impact of contaminants on fuel cell performance depends on the type and concentration of the contaminant.

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38 be fixed by flushing out the hydrogen storage tanks and the fuel cell, which is difficult and costly . However, some contaminants can cause catastrophic damage to the fuel cell . SAE J2719 outlines the relevant contaminants . Sulfur compounds are the m ost serious and destructive contaminants. Carbon compounds such as carbon monoxide (CO) and CO2 block the catalyst surface on the fuel cell, which reduces efficiency. Compounds such as ammonia affects the membrane, which reduces the efficiency of the fuel cell system . Removing water from the hydrogen gas is also important because it can facilitate the infiltration of other contaminants into the system (Tiger Optics, 2020).

The hydrogen production pathway affects the types of contaminants that are likely to be present. Electrolysis is the least likely to produce contaminants, as it uses pure water for input. SMR, however, uses natural gas and is at risk of being contaminated with ammonia, sulfur compounds, CO, and CO2. After the hydrogen is produced , atmospheric compounds such as nitrogen, water, and oxygen can contaminate the hydrogen through leaks in the system (Tiger Optics, 2020).

The State of California recognizes the problem from contaminants , and the CEC requires that any hydrogen fueling sta tion that receives grant funding must be tested for contaminants at least every three months. The CEC also requires that hydrogen quality be tested any time the hydrogen could have been exposed to contaminants during maintenance or other activities.

Figure 1-14: Typical Hydrogen Contaminants (CARB, 2016)

The cost of maintenance for hydrogen infrastructure can vary depending on the ownership model for the equipment . Many hydrogen infrastructure providers prefer to own the infrastructure and sign an agreement to provide hydrogen to the fleet .

Under these agreements, the infrastructure provider is responsible for providing maintenance . For example, the Stark Area Regional Transit Authority (SARTA) (the transit agency serving Canton, Ohio , and the surro unding Stark County ) receives delivered liquid hydrogen that is trucked from Canada. SARTA has 9,000 gallons of liquid hydrogen storage and a fueling station.

The liquid hydrogen storage and fueling equipment is owned by Air Products. SARTA has a contract with Air Products, who owns, operates, and maintains the equipment . SARTA pays $10,000 per month plus the cost of fuel (Eudy, 2019) . However, other hydrogen companies have a different business model and will construct the fueling station. After completing the fueling station, the hydrogen infrastructure company will provide maintenance for a fixed cost . The maintenance cost can be reduced if the transit agency’s staff can carry out routine maintenance tasks, leaving major maintenance tasks to the hydrogen c ompany.

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39 Required Tools and Facility Upgrades
To adequately service the buses, the maintenance staff will need to have proper tools and facilities . Many of the tools used to maintain traditional internal combustion engine buses can also be used to service electric buses. However, some specialized equipment is needed to handle EV high-voltage components such as batteries, inverters, and traction motors. The following are examples of necessary tools and equipment:
• OEM-specific diagnostic tools to troubleshoot problems on the bus • High impedance multimeters to monitor current in the electrical systems • Insulated hand tools (wrenches, screwdrivers, pliers, etc.) to protect workers from shock • Personal protective equipment including Class 0 rubber high voltage glov es (which need to be inspected and tested regularly), leather overgloves, insulated dielectric boots, face shield, insulating rubber apron, and insulated electrical rescue hook
• Overhead crane to lift batteries from the roof of the bus • Forklift to remove inverters and HVAC systems from the roof of the bus • Scaffolding with fall protection so technicians can access the roof of the bus • Lifting jigs for batteries and inverters
• OEM-specific tools to fix bus mechanical systems
• Manlift (if using overhead plug-in or pantograph chargers) to perform routine maintenance and repairs Although FCEBs operate in a similar manner as BEBs, they have additional maintenance and operational needs . Since hydrogen is a highly flammable gas, there are many regulations that govern the maintenance of hydrogen vehicles . NFPA has published safety standards for hydrogen facilities. These standards are published in the NFPA 2 Hydrogen Technologies Code . NFPA 2 was most recently updated in 2020. NFPA 2 has several provisions that are relevant to hydrogen fuel cell bus maintenance depots:
• Repair rooms must be separated from the rest of the building by a one-hour fire resistant wall. • A gas detection system must be provided and ready to activate the following if hydrogen level exceeds 25 percent of the lower flammability limit:
○ Initiation of audible and visual signals
○ Deactivation of heating systems
○ Activation of the exhaust system (unless the exhaust system operates continuously) • Infrared flame detectors are required to detect hydrogen fires since hydrogen burns invisibly. • Defueling is required for all work on the fuel system or all hot works (welding or open flame) within 18 inches of vehicle fuel supply container. The maintenance garage must have equipment to defuel the bus’s hydrogen tanks.

Local authorities and fire departments can impose additional fire safety requirements . Meeting these requirements can be expensive and vary depending on the type of improvements required. For example, when AC Transit adopted hydrogen fuel cell buses, they were required to install a two-hour fire wall, an ignition -free heating system for the garage, a hydrogen lower flammability limit detector, and Class 1 Div . 2 electrical equipment throughout the garage . AC Transit spent $1.5 million to provide these upgrades (CALSTART, 2016). SARTA, however, had an existing garage and only needed to purchase air handlers to ventilate the garage and sensors to detect the presence of hydrogen . These upgrades cost about $100,000 (Eudy, 2019).

Training Costs
OEM-specific training is typically part of pr ocurement contracts . California Department of General Services (DGS) has procurement contracts that transit agencies can use to purchase buses at a fixed price without having to issue a Request for Proposal (RFP). These DGS contracts also include pricing for bus technician and bus operator training, as well as for maintenance manuals. See Table 1-3 for a breakdown of these costs.

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40 Table 1-3: ZEB Maintenance and Operator Training Costs Item OEM 1 OEM 2 OEM 3 OEM 5
Operator Training
(total of 56 hours) $12,250.00 $11,667.04 $11,200.00 $11,667.04 Technician Training
(total of 304 hours) $66,500.00 $107,001.92 $44,797.44 $141,657.92 Maintenance Packages
Manual (per manual) $300.00 $741.00 $500.00 $815.54
Preventative Maintenance
and Procedure Manual
(per manual)
$300.00 $298.15 $100.00 $298.15
Parts Manual (per manual) $200.00 $153.46 $500.00 $153.46 Operator's Manual
(per manual) $100.00 $87.69 $250.00 $87.69

Estimated Costs
Transitioning to a ZEB fleet will require substantial financial resources . Table 1-4 provides a breakdown of associated costs and a cost comparison between transitioning to a fully BEB fleet and a fully FCEB fleet . These costs assume that the buses and infrastructure will be acquired through capital purchases and that the buses will be purchased according to each transit agency’s fleet replacement plan. The assumptions used for Table 1-4 are detailed under Financial Analysis and Cost Estimates in Sections II through IV.

Table 1-4: Estimated Costs to Transition to a ZEB Fleet Transit Agency BEB Fleet Costs FCEB Fleet Costs
The Pasadena Department of
Transportation - Scenario 1 $56,181,098 $61,762,767
The Pasadena Department of
Transportation - Scenario 2 $75,392,385 $81,482,913
Glendale Beeline - Scenario 1 $66,709,857 $88,713,803
Glendale Beeline - Scenario 2 $76,804,452 $91,564,649
BurbankBus $30,229,373 $31,712,460

Financing Strategies & Resources
Transit agencies have multiple options for funding the deployment of ZEBs . Bus OEMs offer several models for financing the procurement of buses and infrastructure . In addition, there are myriad governmental programs available to help fund vehicles and infrastructure. This section provides an overview of financing options.

Traditional Financing Models
Bus OEMs offer a variety of financing mechanisms that transit agencies can use to obtain buses. This includes capital purchases, bus/battery leasing, and infrastructure as a service.

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41 Capital Purchases
Traditionally, buses are obtained through capital purchases. A capital purchase is a transaction in which an OEM or infrastructure provider transfers ownership of a bus or infrastructure to a transit agency in exchange for a capital pa yment. In a traditional capital purchase, a transit agency typically releases RFPs, in which they outline the number of buses and type of infrastructure they would like to procure and release the duty specifications the buses need to meet . OEMs and infrastructure providers are then invited to submit bids , and the transit agency select s a winning bid and award s a contract. However, several states have now issued statewide contracts for buses. Under a statewide contract, the state negotiates a contract with bus OEMs to purchase buses at a fixed price . Transit agencies can purchase buses from a statewide contract and thereby avoid the RFP process. The State of California has statewide contracts with several bus OEMs through California DGS. CalACT has also developed a statewide contract for zero-emission shuttle buses.

A capital purchase allows a transit agency to make a single payment to obtain a bus . The bus’s value is then depreciated over the entire life of the bus . Capital purchases can be problematic; they require transit agencies to have access to a large amount of money. It is often difficult for transit agencies to obtain enough funding to make a lump sum payment , especially smaller transit agencies.

Battery Leasing
When compared to conventional diesel- and/or gas-powered vehicles, EVs often come at a higher upfront capital cost. In most cases, the largest cost is the battery itself, which is why some OEMs have developed battery leasing programs to lower the barrier to entry for fleets and allow the manufacturer to recoup the cost of the battery over an extended contract. In this model, the BEB can be purchased without the battery pack at a lower price that is cost competitive with conventional vehicles. The upfront cost of the battery itself is covered by a participating financial partner and enables battery warranties to be guaranteed for the duration of the lease. Under this model, the transit agency would then make monthly or annual lease payments for the battery. Battery leasing helps transit agencies because it reduces capital expenditures for the buses. This model effectively shifts a large portion of the bus cost into lease payments, which allows transit agencies to finance their purchase through operational budgets, rather than capital expenditures.

While this is a promising model for the acceleration of transit fleet electrification, it is a newer idea that is still in de velopment at most OEMs. A price comparison between leasing and owning the battery remains uncertain; battery leasing is a nascent business model, and it is unclear which, if any, transit agencies have utilized this option. Table 1-5 provides a brief overview of BEB OEM battery leasing options.

Table 1-5: Battery Leasing Options
Bus OEM Battery Leasing Options
BYD Yes
New Flyer Unknown
Proterra Yes
GreenPower Motor Company No
Phoenix Motorcars No, but considering offering battery
leasing in the future

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42 Infrastructure-as-a-Service (IAAS)
Like bus/battery leasing, IAAS is another method for reducing the capital expenditures associated with deploying ZEBs , particularly charging and resiliency infrastructure . IAAS can also be combined with battery leasing to further reduce capital expenditures. Under an IAAS model, a company will provide turnkey service, managing t he construction and installation of charging infrastructure. Under this model, the infrastructure company will typically maintain ownership of the chargers and any resiliency equipment. The infrastructure company then signs a power purchase agreement (PPA) with the transit agency to sell the power produced and dispensed to the buses . IAAS companies can develop PPAs where power is sold on a per kWh basis or a per mile basis . Most IAAS companies prefer to sell power on a per kWh basis . IAAS companies typicall y combine the infrastructure with managed/networked charging to minimize demand charges and the cost of electricity.

The IAAS model can also provide tax benefits in some cases . Some types of infrastructure can qualify for the Investment Tax Credit (see page 46) and other tax benefits. Since a transit agency is a public agency that does not pay taxes, they cannot directly take advantage of these tax credits . However, under the IAAS model, the infrastructure provider retains ownership, and they can benefit from the tax credits . This option would allow the infrastructure provider to pass some of the tax benefits onto the transit agency in the form of lower PPA rates . In some cases, an IAAS company may also give transit agencies the option to convert the PPA to a capital purchase of the infrastructure once the tax benefits have been realized. An overview of IAAS companies can be found in Appendix D.

Funding Sources and Incentives for Buses and Infrastructure The transit agencies in AVTO do not currently receive state or federal formula funding (except for the Low Carbon Transit Operations Program). The main funding option that AVTO has to fund the transition to a ZEB fleet is to apply for competitive grants to pay for buses or bus facilities. Grant funding can be used to reduce the capital expenditures associated with purchasing buses or chargers . Alternatively, there are situations where grants can be combined with traditional financing models to fund the fleet. This section provides an overview of governmental funding opportunities.

State Funding Sources and Incentives
California State Budget Allocations
The California State Budget has allocated $2.7 billion for the 21-22 fiscal year and a total of $3.9 billion over the next three years.

Millions of dollars of f unding are specifically being earmarked for ZE transit buses and associated refueling/charging infrastructure:
• $1.3 billion over 3 years to deploy over 3,000 ZE drayage trucks, transit buses, and school buses • $500 million for zero emission clean truck, buses, and off‑road equipment • $200 million for medium-and heavy-duty ZEV fueling and charging infrastructure • $407 million to demonstrate and purchase or lease clean bus and rail equipment and infrastructure that increase intercity rail and intercity bus frequencies.

Clean Transportation Program - CEC
The Clean Transportation Program was created to fund projects that help transition California’s fuels and vehicle types to achieve California’s climate policies. The Clean Transportation Progra m is funded from fees levied on vehicle and vessel registrations, vehicle identification plates, and smog abatement. The Clean Transportation Program was created by Assembly Bill 118 and was extended to January 1, 2024 by Assembly Bill 8. The Clean Transportation Program funds multiple classes of vehicles. Every year the CEC develops an Investment Plan Update to identify how the program’s funds will be allocated. For FY 2021 -22, the CEC proposed that $30.1 million in Clean Transportation Program funding and $208 million in general funds would be used to fund Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-56
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43 medium- and heavy-duty vehicle charging and hydrogen fueling infrastructure. For FY 2022 -23, the CEC proposed $30.1 million of Clean Transportation Program funding for zero emission medium - and heavy-duty vehicles and infrastructure. The amount that will be allocated from general funds in FY 2022-23 has not yet been determined (California Energy Commission, 2021).

Carl Moyer Program – CARB
The Carl Moyer Program provides grant funding for engines, equipm ent, and other sources of air pollution that exceed CARB’s regulations for on-road heavy-duty vehicles. The Carl Moyer Program is managed by CARB in collaboration with local air pollution control districts and air quality management districts . ZEBs with a GVWR of greater than 14,000 pounds are eligible for funding under Carl Moyer. The air pollution control districts and air quality management districts are the entities that issue the grants and determine funding for the program.

Energy Infrastructure Incentives for Zero-Emission Commercial Vehicles (EnergIIZE) – CEC, CALSTART EnergIIZE is a program that was launched by the CEC and is being managed by CALSTART . EnergIIZE will provide $50 million of funding to entities to help finance the purchase of charging and hydrogen infrastructure. EnergIIZE will fund medium- and heavy- duty infrastructure and is intended to primarily benefit communities with disproportionately high levels of air pollution .

EnergIIZE program will only cover a part of the infrastructure hardware and software costs. For EV projects, charging equipment eligible for funding includes Level 2 electric vehicle supply equipment, DCFC electric vehicle supply equipment, charge management software, switchgear, electrical panel upgrades, wiring and conduit, and meters. For hydrogen projects, equipment that is eligible for funding includes compressors, liquid and gaseous pumps, piping and pipelines, hydrogen dispensers with hoses and nozzles, high -pressure storage, on -site production equipment, chiller s, switchgear, electrical panel upgrades, wiring and conduit, and meters. Construction, labor, and utility upgrade costs are not eligible for funding under this program.

The EnergIIZE program offers four pathways to fund infrastructure. Each of these pathways has different eligibility criteria:
• EV Fast Track – for fleets that own or have a purchase order for a vehicle registered in the State of California as a result of State or Federal vehicle incentive funded projects (such as HVIP, Volkswagen Settlement, Carly Moyer, TIRCP, etc.) • EV Jump Start – for transit agencies in a designated Disadvantaged Community (according to CalEnviroScreen 3.0) • EV Public Charging Stations – for public charging station developers • Hydrogen – for the development of hyd rogen refueling stations for medium - and heavy -duty vehicles (either liquid hydrogen or gaseous hydrogen)

The pathway that a transit agency qualifies for determines the amount of funding that they can receive. Under the EV Fast Track pathway, applications are evaluated on a first -come, first-served basis. EV Fast Track will fund 50% of hardware and software costs incurred, up to a maximum of $500,000. EV Jump Start funding is awarded on a competitive basis. EV Jump Start will fund 75% of hardware and sof tware costs incurred, up to a maximum of $750,000. Hydrogen pathway funding is awarded on a competitive basis. The Hydrogen pathway will finance 50% of hardware and software costs incurred, up to a maximum of $2,000,000.

At the time of writing, CALSTART p lans to open funding for the first round of the EV Fast Track pathway in Q1 2022. A second round of funding is planned to open in Q3 2022. The first round for EV Jump Start is planned to open in Q2 and close in Q3 2022.

A second round of EV Jump Start i s scheduled to open in Q4 2023. The hydrogen pathway is scheduled to open in Q2 2022. A second round is scheduled to open in Q4 2022. 70% of funding will be allocated to EV projects and 30% will be allocated to hydrogen (CALSTART, 2021).

Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project (HVIP) – CARB, CALSTART California HVIP is a program that was launched by CARB and is managed by CALSTART . HVIP provides vouchers that are used to finance the purchase of clean transportation vehicles. HVIP’s vouchers are applied at the point -of-purchase, which reduces the Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-57
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44 purchase price of the vehicle when it is purchased . ZEBs are eligible to receive vouchers under HVIP . Vouchers are allocated on a first-come, first-serve basis.

California Infrastructure and Economic Development Bank (IBank) The IBank was created in 1994 to fund infrastructure and economic development projects in California. The IBank was started by the Bergeson -Peace Infrastructure and Economic Development Bank Act and is operated by GO -Biz. IBank can issue low- interest bonds that can be used to finance projects for public agencies or nonprofits. The IBank has programs that can be used to finance the transition to a zero emission fleet. The Infrastructure State Revolving Fund (ISRF) program provides low-Interest financing for infrastructure projects. ISRF provides loans of $50,000 to $25 million over a term of up to 30 years at a fixed interest rate. These loans are funded through the sale of Infrastructure State Revolving Fund Revenue Bonds. Public transit projects, which includes but is not limited to, vehicles and maintenance and storage yards, are eligible for funding thr ough ISRF. ISRF applicants must be a public agency , joint power authority, or nonprofit corporation formed by an eligible entity. ISRF accepts applications on an ongoing basis (California Infrastructure and Economic Development Bank, 2016).

The IBank also offers the California Lending for Energy and Environmental Needs (CLEEN) program. CLEEN provides loans from $500,000 to $30 million over a team of up to 30 years. These loans can be used to fund projects that use a commercially proven technology to reduce greenhouse gas emissions or pursue other environmental objectives. Eligible projects include energy storage, renewable energy generation assets, stationary fuel cells, electric vehicles, alternative fuel vehicles, and alternative fuel vehicles refueling stations (California Infrastructure and Economic Development Bank, n.d.).

Low Carbon Fuel Standard (LCFS) Program – CARB
The LCFS Program is run by CARB and creates a mechanism for the users and producers of low-carbon fuels (including electricity) to generate credits for the use of these low -carbon fuels. These credits can then be sold in the LCFS market . The LCFS program sets standards for the maximum carbon intensity that a fuel can have. If an entity uses fuels that are below the carbon intensity standards, they generate LCFS credits. However, if an entity uses fuels that exceed the carbon intensity standards, they generate deficits and must purchase LCFS credits to negate their deficits .

LCFS credits are generated based on the fuel type, fuel quantity, and carbon intensity of the fuel used (in this case electri city or hydrogen). Over time, the standards for carbon intensity bec ome more stringent, making it more difficult to earn LCFS credits .

Transit agencies must comply with CARB reporting requirements to earn LCFS credits . To generate LCFS credits, the chargers or hydrogen production equipment must be registered with CARB. Once the equipment is registered, the owner of the equipment can begin generating LCFS credits.

LCFS credits can be sold to polluters that need to negate their deficits based on the going market rate . However, as of 2021, CARB has set a purchase price for LCFS credits at $221.67 per credit, effectively creating a price ceiling. LCFS credits have traded at about $200 per credit since Q4 2019 (CARB, n.d.). Sales of LCFS credits represents a significant revenue mechanism. The profits from LCFS credits can be used to fund either vehicle purchases or charging infrastructure. Figure 1-15 shows historic LCFS prices from January 2016 through August 2021.

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45 Figure 1-15: Historical LCFS Prices January 2016 – May 2021 (Source: SRECTrade)

Transit and Intercity Rail Capital Program (TIRCP) – Caltrans TIRCP provides grants to fund capital improvements that will modernize California’s rail, bus, and ferry public transit facil ities.

The objective of the program is to reduce GHG emissions, expand transit service, increase transit ridership, and improve transit safety. Funded projects are expected to reduce GHG emissions, vehicle miles traveled, and congestion. TIRCP is funded through the Greenhouse Gas Reduction Fund (GGRF) and the Cap and Trade program. TIRCP funds can be used to finance site upgrades and the deployment of zero-emission infrastructure at bus depots and facilities.

Low Carbon Transit Operations Program (LCTOP) – Caltrans The LCTOP is one of several programs that is funded by the GG RF, which is funded by revenues from the state’s cap -and-trade system. State law requires continual appropriation of 5 percent of the revenue from the GGRF to be allocated to the LCTOP.

State law requires the program’s funds to provide transit operating or capital assistance that meets any of the following criteria:

1. The funding can directly enhance or expand transit service by enabling new or expanded bus or rail services, water - borne transit, or expanded intermodal transit facilities, and may include equ ipment acquisition, fueling, and maintenance, and other costs to operate those services or facilities.

2. The funding can fund operational expenditures that increase transit mode share.

3. The funding can fund the purchase of ZEBs, including electric buses, and the installation of the necessary equipment and infrastructure to operate these ZEBs.

VW Mitigation Trust – CARB
The purpose of the VW Environmental Mitigation Trust is to fully mitigate the excess NOx emissi ons released during the Volkswagen emission scandal. This program was established as a part of the settlement that VW reached with the EPA. The VW Mitigation Trust has allocated $423 million to the State of California to fund the deployment of clean transportation vehicle s. $130 million of these funds is devoted to replacing older, high emission buses with BEBs or FCEBs . Transit, school, and shuttle buses are eligible for funding.

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46 Federal Funding Sources and Incentives
Bus & Bus Facilities (5339) – USDOT/Caltrans
The Bus & Bus Facilities program is managed by the FTA . This program provides capital funding to replace, rehabilitate, and purchase transit vehicles and construct bus -related facilities. The FTA allocates funding to states to administer these grants . In California, Caltrans has been delegated the responsibility of managing these grants. Public agencies and nonprofit organizations that are involved in public transit may apply for these grants.

Congestion Mitigation and Air Quality (CMAQ) Improvement Plan – USDOT CMAQ provides funds directly to states. These funds may be used to finance projects that reduce traffic congestion and improve air quality. The main objective of this program is to reduce CO, ozone, and PM emissions. This program is primarily intended to fund projects in areas that do not meet national air quality standards. The Infrastructure Investment and Jobs Act (IIJA) provides $13.2 billion of funding over five years. Under IIJA, there are new project types that are eligible for funding under C MAQ. The purchase of medium - or heavy-duty zero emission vehicles and supporting infrastructure is eligible for funding under CMAQ.

Shared micromobility projects are also eligible for funding. CMAQ funds can also be used to provide operating assistance for public transportation projects.

Investment Tax Credit (ITC) - IRS
Internal Revenue Code Section 48 provides a tax credit for investments in certain types of energy projects . Section 48 provides tax credits for a wide range of renewable energy investments. Renewable energy technologies such as solar PV, fuel cells, small wind microturbines, and combined heat and power are eligible for tax credits. Solar PV projects are eligible for a tax credit equal to 10 percent of the cost of system for projects that begin construction in 2022 or after. Only the owner of the system can claim the ITC. Small wind power (100 kW of capacity or less) is eligible for the same tax credits as solar . Fuel cells are eligible for the ITC and are limited to $1500 per 0.5 kW in capacity . Lastly, combined heat and power equipment qualifies for an ITC of 10 percent (Congressional Research Service, 2018).

It is important to note that the ITC for some technologies will phase out over time . The solar ITC is permanent and will remain at 10 percent beyond 2022. However, the ITC for wind, fuel cells, and CHP has been approved until 2024 . It is unclear whether the ITC for these technologies will be enacted beyond this date . Since transit agencies are tax-exempt entities, they would not be able to directly take advantage of these tax credits . However, if a separate entity, such as an IAAS company, owned and operated the energy assets, they would be able to benefit from these tax credits and pass these b enefits on to AVTO.

Low or No Emissions Program (Low-No) – USDOT/FTA
Low-No provides funding to state and local governmental authorities for the purchase or lease of zero -emission and low - emission transit buses . Low-No funding can also be used to acquire charging or fueling infrastructure for the buses, pay for construction costs, or obtain or lease facilities to house a fleet. In FY2021, $182 million was allocated for the Low -No program.

However, the enactment of IIJA will expand funding for the Low-No program. IIJA allocates an additional $5.25 billion for the Low-No program over five years. To be eligible for this funding, a transit agency will need to submit a plan for transitioning to zero emission buses. This plan must demonstrate a long-term fleet management plan that addresses how the transit agency will meet the costs of transitioning to zero emission, the facilities and infrastructure that will be needed to be deployed to serve a zero emission fleet , the transit agency's relationship with their utility or fuel provider, and the impact that the transition will have on the transit agency's current workforce . Under IIJA, transit agencies may apply for Low -No funding with other entities, such as an OEM, that will participate in the implementation of the project. IIJA also requires that 5% of grant funds awarded be used to fund workforce training to prepare their current workforce to maintain and operate the buses.

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47 Rebuilding American Infrastructure with Sustainability and Equity (RAISE) grants – USDOT The RAISE grant is the latest iteration of the BUILD and TIGER grant program . This program is intended to invest in road, rail, transit, and port projects. The objective of this program is to fund projects that are difficult to support through traditional USDOT programs. Public entities, such as municipalities, are eligible to apply for this program. RAISE is a competitive grant program.

Prospective Financing Mechanisms
IBank Climate Catalyst Fund
The state’s IBank is poised to create a new low-interest loan program for public fleets. The Climate Catalyst Fund was created in June 2020 and received its first funds in September 2021. The objective of this fund is to provide a financing mechanism to support the State of California's climate and sustainability infrastructure. The Climate Catalyst Fund 's goal is to provide low - interest loans for projects that support the state's climate objectives. The IBank is in the process of developing the criteria that will be used to award projects. The Climate Catalyst Fund will initially prioritize projects that advance forest biomass management. However, the Climate Catal yst Fund's scope is expected to increase over time. From discussions with the Governor’s Office of Business Development as well as the Director of the IBank, Scott Wu, CALSTART understands that the Fund's scope will eventually encompass zero emission fleets. These low interest loans could be used to fund vehicle purchases, as well as charging infrastructure projects.

Medium- and Heavy-Duty Zero-Emission Vehicle Fleet Purchasing Assistance Program - CARB Under existing California law, CARB administers an Air Quality Improvement Program which promotes the use of zero-emissions vehicles by providing rebates for their purchase. There is a bill in the state legislature, SB-372, which would establish a Medium- and Heavy-Duty Zero-Emission Vehicle Fleet Purchasing Assistance Program, within the Air Quality Improvement Program, and make financing tools and nonfinancial support available for the operators of medium- and heavy-duty vehicle fleets to help them transition to zero -emissions vehicles. This bill has passed State Senate with broad support, by a margin of 37 -2, and for that reason appears likely to pass the Assembly and be approved by the Governor. If enacted, the bill would require that the financial tools offered by this program be available to fleets by January 1, 2023.

Zero Emissions Truck, Bus, and Infrastructure Finance Program – Southern California Edison (SCE) SCE has filed with the California Public Utilities Commission to establish a Zero Emissions Truck, Bus, and Infrastructure Fi nance Program, by funding zero-emissions trucks, buses, and associated infrastructure with $20 million.

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48 Section II: The Pasadena Department of Transportation Executive Summary

The Pasadena Department of Transportation is a transit agency that serves Pasadena, California , and parts of the surrounding area, provid ing both fixed-route (Pasadena Transit) and demand response (Pasadena Dial -A-Ride) services . The Pasadena Department of Transportation aims to transition the Pasadena Transit and the Pasadena Dial -A-Ride fleets to zero emission buses. When planning this transition, the Pasadena Department of Transportation is likely looking at two different scenarios for future service. Scenario 1 where it maintains current routes while adding a route that can be served by the curre nt fleet and Scenario 2 where it maintains current routes while adopting Scenario 1 and adding an additional expansion route that would require additional vehicles to be purchased . The Pasadena Department of Transportation aims to begin service using zero emission buses in 2027. The Pasadena Department of Transportation aims to complete f ull conversion to zero emission buses for Pasadena Dial-A-Ride in 2033 and for Pasadena Transit in 2040.

Bus route modeling showed the current duty cycle for fixed -route transit operations can be served with a 1:1 drop -in replacement using FCEBs. Modelling was also done for BEBs. Our modelling indicates that, based on today's technology, between 15 and 25 of the 26 vehicle assignments can be served on a drop-in basis depending on the OEM. It is anticipated that in coming years technological improvements will allow BE Bs to serve as drop -in replacements for an increasing amount of Pasadena Transit's service. For Pasadena Dial-A-Ride, the available FCEB on the market can serve as a drop-in replacement. Based on the current cost of ZE buses, fueling infrastructure, and the Pasadena Department of Transportation 's needs, and despite the necessity of acquiring additional buses, BEBs are recommended due to their lower overall total cost of ownership.

Transitioning to a ZE fleet will be more expensive than operating a RNG bus fleet. The cost of operating a RNG bus fleet according to the current fleet replacement plan is projected to cost $29,982,281 between 2022 and 2040. When this amount is discounted at a rate of 4 percent per year (discounted to 202 2 dollars), this amounts to a net present value of $ 17,721,132. The cost of transitioning to a fully BEB fleet will be more than the cost of operating a RNG bus fleet. The costs of transitioning to a full BEB fleet are projected to be:
• Transitioning to a fully BEB fleet under Scenario 1 is projected to cost $56,181,098 between 2022 and 2040. Discounting this amount at a rate of 4 percent per year (discounted to 2022 dollars) results in a net present value of $35,974,785.

This is based on the assumption that Pasadena Transit will operate 44 transit buses and Pasadena Dia l-A-Ride will operate 15 vehicles (a total of 59 vehicles combined).
• Transitioning to a fully BEB fleet under Scenario 2 is projected to cost $75,392,385 between 2022 and 2040. Discounting this amount at a rate of 4 percent per year (discounted to 2022 dollars) results in a net present value of $45,724,474.

This is based on the assumption that Pasadena Transit will operate 64 transit buses and Pasadena Dial -A-Ride will

Section II: Executive Summary
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49 operate 15 vehicles (a total of 79 vehicles combined).

The cost of transitioning to a n FCEB fleet depends on the pathway used to obtain hydrogen. The most cost effective hydrogen pathway would be to produce hydrogen on-site via SMR. Based on this pathway, t he cost of transitioning to a fully FCEB fleet are projected to be:
• Transitioning to a fully BEB fleet under Scenario 1 is projected to cost $56,181,098 between 2022 and 2040. Discounting this amount at a rate of 4 percent per year (discounted to 2022 dollars) results in a net present value of $35,974,785.

This is based on the assumption that Pasadena Transit will operate 29 transit buses and Pasadena Dial -A-Ride will operate 15 vehicles (a total of 44 vehicles combined).
• Transitioning to a fully BEB fleet under Scenario 2 is projected to cost $75,392,385between 2022 and 2040. Discounting this amount at a rate of 4 percent per year (discounted to 2022 dollars) results in a net present value of $45,724,474.

This is based on the assumption that Pasadena Transit will operate 42 transit buses and Pasadena Dial -A-Ride will operate 15 shuttle buses (a total of 57 vehicles combined).

These figures include the capital expenditures associated with utility upgrades, purchasing and installing chargers, and the cost of the buses. In addition, this analysis takes into account operational costs such as maintenance costs, the cost of electricity from the utility the cost of hydrogen , and the cost of maintaining charging /fueling infrastructure. This analysis does not include the cost of acquiring land for a depot, building a depot, or labor associated with operating the buses.

PWP has a resilient and reliable grid. However, if there was an extended grid outage, it would compromise the Pasadena Department of Transportation’s ability to charge their buses and would disrupt their ability to provide service. PWP is interested in providing a resiliency option to the Pasadena Department of Transportation ; PWP owns a power plant with 200 MW of generation capacity, located locally in Pasadena. PWP stated that this plant can potentially be used as a resili ency measure. If the grid were to experience an outage, PWP could turn on their power plant and provide power to the Pasadena Department of Transportation, among other customers. PWP has also stated that they are looking into deploying FTM batteries so the y can continue to provide power in the event of an outage.

For on-site BTM resiliency, the Pasadena Department of Transportation can use solar and storage or natural gas generators . If solar and storage is used, the Pasadena Department of Transportation will need a 2,948 kW PV solar array and an energy storage system with a power capacity of 2,628 kW and storage capacity of 31,006 kWh to provide full resiliency. Because it is unclear at present where the Pasadena Department of Transportation will house its new bus fleet, it is not known what, if any, solar potential would be available at the site. If natural gas generators are used, it would require 3,000 kW generator capacity to provide full resiliency to the fleet.

The Pasadena Department of Transportation has identified 2180 E. Foothill Blvd as a possible location for their new transit facility. This transit facility is currently in the design phases. The Pasadena Department of Transportation will need to install both FTM and BTM infrastructure. PWP has stated that there is enough grid distribution capacity to serve this site. As a result, t he main required FTM infrastructure is a transformer. The installation of a transformer typically takes 4 -6 months but can take up to one year. The installation of the transformer can be incorporated into the construction of the transit facility. The Pasad ena Department of Transportation needs to coordinate with PWP to ensure that the final design for the site will a ccommodate the transformer and to schedule the installation of the transformer.

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50 Section II: The Pasadena Department of Transportation The Pasadena Department of Transportation Overview
The Pasadena Department of Transportation serves the city of Pasadena , providing both fixed -route service (operated as Pasadena Transit) in Pasadena and portions of Altadena and d emand response service (operated as Pasadena Dial-A-Ride) in Pasadena, San Marino, Altadena, and other unincorporated Los Angeles County areas. Pasadena Dial-A-Ride is provided seven days a week with reduced service on weekends and holidays. Pasadena Transit provides essential transit connections throughout Pasadena. All of its six fixed-route service lines also connect with Metro’s L Line (formerly known as the Gold Line). Pasadena Transit is provided Monday through Sunday, with reduced service on weekends. Currently, all the buses in the fleet have internal combustion engines and are fueled with RNG. When planning the transition to a zero emission fleet, the Pasadena Department of Transportation is likely looking at two different scenarios for future service. Scenario 1 where it maintains current routes while adding a route that can be served by the current fleet and a Scenario 2 where it maintains current routes while adopting Scenario 1 and adding an additional expansion route that would require additional vehicles to be purchased.

Pasadena Dial-A-Ride began its service in Pasadena in 1984 and has since expanded its service area. It is a shared, curb-to-curb transportation service provided for residents in Pasadena, San Marino, Altadena, and the other unincorporated Los Angeles County areas in the service area ( i.e., Chapman Woods, Kinneloa area, and the unincorporated area of the City of San Gabriel) who are 60 years and older or for those under 60 years old who have a disability. This service is provided seven days per week.

Since this service is demand response, buses do not adhere to a fixed route. Demand response shuttles are typically able to also drive on residential streets and have limitations in service areas due to street width or other conditions.

Section II
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51 Figure 2-1: Pasadena Dial-A-Ride Service Area

Pasadena Transit, which began Its service in 1994, operates multiple fixed routes on weekdays, with some routes operating on reduced or modified weekend schedules:
• Route 10 operates between Old Pasadena and the Allen L Line Station. This route runs on weekdays, with reduced service on weekends.
• Route 20 provides a two-way loop along the Fair Oaks Avenue and Lake Avenue corridors. The Fair Oaks Avenue corridor extends from Woodbury Road in the north to Glenarm Street in the south. The Lake Avenue corridor extends from Woodbury Road in the north to California Blvd. in the south. It operates on weekdays with reduced service on weekends.

Route 20 buses operate in a clockwise and counterclockwise direction. • Route 31/32 provides service from Northwest Pasadena to the Sierra Madre Villa L Line Station. It operates on weekdays with reduced service on weekends. Route 31/32 covers the Washington Blvd. corridor between Lincoln Avenue and Altadena Drive. The route is branched at Altadena Drive with the Route 31 serving south Altadena Drive and Foothill Blvd. and the Route 32 branch serving north Altadena Drive, New York Drive , and Sierra Madre Villa. The two branches terminate at the Sierra Madre Villa L Line Station.

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52 • Route 40 provides service between Old Pasadena and the Sierra Madre Villa L Line Station. It operates on weekdays with reduced service on weekends.
• Route 51/52 runs between Old Pasadena and the ArtCenter and the Jet Propulsion Laboratory (JPL) (Route 51 goes to the Art Center and Route 52 is an extended version of Route 51 that goes to the JPL). The full Route 51/52 operates only on weekdays. On weekends, the Route 51 serves a truncated route between the Memorial Park L Line Station and the Rose Bowl.
• Route 60 operates between the Hastings Ranch area and the Sierra Madre Villa L Line Station to Pasadena City College. It operates limited hours on weekdays only.

Figure 2-2: Pasadena Transit Service Area

Pasadena Transit is also examining the following proposed routes:
• Route H is operating as a demonstration route from January to June 2022 that provides service between the Sierra Madre Villa L Line Station and the Huntington Library. It operate s on weekends only. This study assumes that Pasadena Transit will adopt Route H as a permanent service.
• Metro is proposing Pasadena Transit assume Metro Lines 177 and 256 as part of the Metro Next Gen Bus Plan. Line 177 operates between Caltech and JPL. Line 177 is expected to operate during peak hours (6 am – 9 am and 3 pm – 6 pm) on weekdays only. Line 256 will provide service between the Highland Park L Line Station and the Sierra Madre Villa L Line Station. It is planned to be a bi-directional schedule with departures every 30 minutes from each terminus.

This study will examine two scenarios:

Scenario 1: Pasadena Transit continues its current service and adopts an additional route that can be served with the current fleet. Scenario 1 assumes that the Pasadena Depar tment of Transportation will deploy 4 4 transit vehicles and 15 dial-a-ride vehicles (59 vehicles combined).

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53 Scenario 2: Pasadena Transit continues its current service , adopts Scenario 1, and adopts an additional route that will require additional vehicles to serve. Scenario 2 assumes that the Pasadena Department of Transportation will deploy 64 transit vehicles and 15 dial-a-ride vehicles (79 vehicles combined).

The Pasadena Department of Transportation Fleet and Bus Depot Pasadena Dial-A-Ride consists of 13 Starcraft Allstar 25-foot shuttle buses and two Dodge Caravan vans. There is a replacement plan in which the demand response fleet buses will be replaced every four years. Seven shuttle buses will be replaced on a four- year cycle beginning in 2022 and six shuttle buses will be replaced on a four -year cycle beginning in 2023. The two minivans in the demand response fleet will be replaced on a four-year cycle, starting in 2022.

Pasadena Transit's fixed-route fleet consists of a total of 29 b uses: Four Starcraft Allstar 25-foot shuttle buses, 21 El Dorado EZ Rider II BRT 32-foot, and four New Flyer Xcelsior XN35 35-foot buses. If Pasadena Transit is to assume all routes proposed by Metro, 13 additional buses will be needed to handle the expand ed service.

The Pasadena Department of Transportation’s bus depot is currently located at 303 Allen Avenue in between Corson Street and Locust Street in the city of Pasadena . This depot contains maintenance bays and parking for the fleet . Some of the fleet is also being housed at yards located at 2140 East Walnut Street and 768 West Woodbury Road. The depot is leased and does not have enough space to house the entire fleet. The Pasadena Department of Transportation is planning to develop a new transit facility that would be used to house their fleet. A potential site for the new transit facility is located at 2180 East Foothill Blvd and is in the planning/engineering stages. The Pasadena Department of Transportation is seeking funding to build the transit facility.

These variables include factors such as the speed of the bus, ridership, and HVAC setpoints. CALSTART worked with the Pasadena Department of Transportatio n to obtain parameters for these variables . EBCM also considers variables that are specific to the route and the environment the bus will encounter while in operation, such as grade and temperature (which affects HVAC load).

To obtain data about grade, C ALSTART collected GIS data to determine the path that the buses travel on their route . This data was used to obtain the elevation at multiple points along the bus’s route. HVAC load is also a major factor; in extreme climates, HVAC can consume more energy than the propulsion system . As a result, HVAC load has a significant impact on energy needs and the range of the bus . The Los Angeles region is known to have hot temperatures during the summer, with occasional heat waves. To ensure that the buses will be a ble to perform under worst case conditions, EBCM was programmed to model 120 degrees Fahrenheit in the summer.

These results can be used to determine whether ZEBs can serve as a drop-in replacement for the current fleet and which routes are most suitable to deploy ZEBs. A BEB is considered to be a drop -in replacement if it can complete its shift with a SOC of at least 20 percent. Likewise, an FCEB is considered to be a drop -in replacement if it can complete its shift with 10 percent of its hydrogen capacity remaining. See Appendix F for in-depth EBCM results.

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54 Pasadena Dial-A-Ride Fleet
To estimate the energy needs for Pasadena Dial-A-Ride's fleet, CALSTART hosted a bus demonstration. CALSTART facilitated the demonstration of shuttle buses from two different OEMs. Each demonstration took place over two days. On the first day, the bus was driven on dial-a-ride service. The Pasadena Department of Transportation provided a manifest (Manifest 903) with a list of locations that a dial-a-ride vehicle would drive to on a typical service day. It is important to note that the dial-a-ride demonstrations were held on a Wednesday . Operating the buses on the same day of the week helps to control for traffic patterns. The majority of the driving for the dial-a-ride demonstration was on surface streets . Key variables from the demonstrations are outlined below in Table 2-1:

Table 2-1: Pasadena Dial-A-Ride Fleet Bus Demonstration Parameters Variable OEM 4 OEM 5
Number of People Onboard During the
Demonstration
3 2
Average Driving Speed 15 miles per hour 15 miles per hour Average Temperature 79° F 55° F
Date of Demonstration October 21, 2021 December 16, 2021

Table 2-2 displays the results from the dial-a-ride bus demonstration.

Table 2-2: The Pasadena Department of Transportation's Dial-A-Ride Service Daily Energy Needs Analysis Demonstration Metric OEM 4 OEM 5
Mileage 119 76.3
Energy (kWh) 78 66.15
Energy Economy (kWh per mile) 0.655 0.867

The main objective of this demonstration was to determine whether each OEM's bus can serve as a drop -in replacement for a conventional shuttle bus. The results of this demonstration indicate:
• OEM 4's bus can serve as a drop-in replacement for a Pasadena Dial-A-Ride vehicle. OEM 4's bus completed the entire route, using less than 80% of the battery's capacity.
• OEM 5's bus can serve as a drop-in replacement for a Pasadena Dial-A-Ride vehicle. OEM 5's bus did not complete the entire day's ser vice. However, OEM 5 offers various battery sizes for their vehicle and offers a battery with approximately 50% more energy storage capacity than the one used on the demonstration vehicle . OEM 5's bus completed the majority of the route. The energy economy measured during the demonstration was measured and extrapolated to the size of the larger battery . Based on th is methodology , OEM 5's bus is deemed to be a drop -in replacement.

The results of this demonstration were used to estimate the energy consumptio n of a fleet of battery electric shuttle buses. If Pasadena Dial-A-Ride replaces its entire fleet with electric shuttle buses and deploys all of the buses on a daily basis, the buses are estimated to consume up to 1,548 kWh per day.

Currently, there is only one fuel cell shuttle bus available . Since this vehicle is not yet Altoona tested, there is no performance data for this bus. However, the bus can be installed with a 13 kg or 19 kg hydrogen tank . Since 90 percent of the hydrogen in a tank is recoverable, the maximum amount of hydrogen available is 11.7 kg and 17.3 kg for the 13 kg and 19.2 kg hydrogen tanks, respectively. These amounts equate to an energy equivalence of 185 kWh and 259.51 kWh, respectively .

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55 Based on these results, CALSTART deems that the fuel cell shuttle bus will be a drop-in replacement for the current buses. Each kg of hydrogen has 33.333 kWh of energy . However, the efficiency of the fuel cell is 50 percent, meaning that 16.667 kWh is available to the drivetrain. Based on this assumption, each bus will use a maximum of approximately 6 kg of hydrogen per day .

If Pasadena Dial-A-Ride replaces its entire fleet with fuel cell shuttle buses and deploys all of the buses on a daily basis, the fleet is expected to consume about 90 kg of hydrogen per day.

Pasadena Transit Fleet
Pasadena Transit's fixed-route fleet provides service to Routes 10, 20, 31/32, 40, 51/52, and 60 . In addition, under Scenario 1, Pasadena Transit will provide service to Route 17 7. Under Scenario 2, Pasadena Transit will provide service to both Route 177 and Route 256. To estimate the energy needs for the fixed -route fleet, EBCM was used to estimate the amount of energy that the buses will consume on these routes. CALSTART worked with Pasadena Transit to calibrate the assumptions for those variables. The assumptions used in EBCM are outlined below in Table 2-3:

Table 2-3: Pasadena Transit Fixed-Route Fleet EBCM Parameters Variable Value
Average Number of People on the Bus During Service 13
Average Driving Speed 10 miles per hour
Heating HVAC Setpoint 72°F
Cooling HVAC Setpoint 68°F

CALSTART also obtained data that is specific to each route. Pasadena Transit provided timetables for all routes to model the exact time schedule and duty cycle for each individual bus . Routes 177 and 256 are currently being operated by Metro , so the service operations for these routes were modeled based on Metro's timetable.

Scenario 1
Using EBCM, CALSTART estimated the energy needs of each individual bus based on Scenario 1 , which assumes that Routes 10, 20, 31/32, 40, 51/52, and 60 continue according to the status quo and that Pasadena Transit adopts Route 177.

Figure 2-3 illustrates the operating schedule for the buses and the routes that they will be deployed on for weekdays under Scenario 1 , and Figure 2 -4 displays the operating schedule for the buses and the routes that they will be deployed on for weekends under Scenario 1. The blue color indicates the intervals during which the bus is in operation, while the white unshaded squares indicate when the bus is not in operation and thus able to charge. Each square represents the half hour after its labeled time.

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56 Figure 2-3: Pasadena Transit Weekday Operating Schedule (Scenario 1)

Figure 2-4: Pasadena Transit Weekend Operating Schedule (Scenario 1)

The energy analysis for each shift under Scenario 1 is provided in Table 2-4, and the energy needs analysis for Pasadena Transit weekend service under Scenario 1 is provided in Table 2-5. A drop-in replacement is defined a s a run that completes its route with a SOC of more than 20 percent. In these figures, there are some buses that cannot serve as a drop -in replacement for a RNG bus. These runs have been highlighted. Runs that complete their route with a SOC of 10 percent or more have been highlighted in yellow . While these buses are not a drop -in replacement with current technology in 2021, it is likely that these buses could become a drop -in replacement in the future with improvements in battery technology. Buses that ret urn to the Routes
(Weekdays) Bus # of Laps
12:00:00 AM
12:30:00 AM
1:00:00 AM
1:30:00 AM
2:00:00 AM
2:30:00 AM
3:00:00 AM
3:30:00 AM
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5:00:00 AM
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6:00:00 AM
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10 1 15
2 15
3 17
20CW 1 13
2 13
3 10
4 5
5 1
20CC 1 11
2 12
3 13
4 4
5 1
31/32 1 12
2 10
3 11
4 1
40 1 13
2 12
3 5
51/52 1 13
2 6
3 1
60 1 12
177 1 8
2 8
Legend
Transit Operation
Charging
Routes
(Weekdays) Bus # of Laps
12:00:00 AM
12:30:00 AM
1:00:00 AM
1:30:00 AM
2:00:00 AM
2:30:00 AM
3:00:00 AM
3:30:00 AM
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10 1 11
2 10
3 11
20CW 1 9
2 9
20CC 1 9
2 9
31/32 1 10
2 10
40 1 9
2 9
51 1 32
H 1 13
H 2 13
Legend
Transit Operation
Charging
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57 depot with less than 10 percent SOC have been highlighted in orange. Orange denotes that it is uncertain whether these buses will become a drop-in replacement in the future.

Table 2-4: Pasadena Transit Weekday Service (Scenario 1) Route Bus # of Laps OEM 1 (kWh) OEM 2 (kWh) OEM 3 (kWh) 10 1 15 325.55 361.43 342.82
2 15 325.56 361.43 342.82
3 17 364.23 401.46 383.79
20CW 1 13 318.63 329.29 340.79
2 13 318.63 329.29 340.79
3 10 233.35 253.43 262.28
4 5 130.13 140.17 141.46
5 1 26.57 28.58 29.49
20CC 1 11 258.23 280.32 290.05
2 12 281.74 305.84 316.46
3 13 318.63 329.29 340.79
4 4 104.2 112.23 115.04
5 1 20.98 22.99 23.87
31/32 1 12 344.88 347.28 362.14
2 10 294.17 290.99 303.37
3 11 317.97 339.23 357.84
4 1 25.20 23.11 24.35
40 1 13 331.00 350.76 361.57
2 12 302.08 325.66 335.63
3 5 131.69 139.29 143.44
51/52 1 13 379.85 396.18 430.13
2 6 168.21 175.75 191.42
3 1 23.34 24.60 27.21
60 1 12 237.12 246.92 257.61
177 1 8 319.82 333.32 381.00
2 8 319.82 333.32 381.00
Total 6,221.58 6,582.16 6,827.16

Table 2-5: Pasadena Transit Weekend Service (Scenario 1) Route Bus # of Laps OEM 1 (kWh) OEM 2 (kWh) OEM 3 (kWh) 10 1 11 229.74 236.45 264.43
2 10 229.74 236.45 244.55
3 11 229.74 236.45 244.55
20CW 1 9 224.50 242.57 250.53
2 9 224.50 242.57 250.53
20CC 1 9 224.50 242.57 250.53
2 9 224.50 242.57 250.53
31/32 1 10 275.30 301.41 321.61
2 10 272.0 315.11 324.20
40 1 9 243.75 257.44 264.91
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58 Route Bus # of Laps OEM 1 (kWh) OEM 2 (kWh) OEM 3 (kWh) 2 9 243.75 257.44 264.91
51 1 32 293.06 306.03 332.15
H 1 13 227.68 235.84 258.65
H 2 13 227.68 235.84 258.65
Total 3,370.44 3,588.74 3,780.73

In Table 2-4, Route 177 for OEM 3 consumes enough energy that it ordinarily would not be considered a drop -in replacement.

However, Route 177 only operates in the morning and the afternoon during peak hours. As a result, there is an extended break during which the buses can recharge.

It should be noted that on some routes there is a major inequality in the number of laps that the buses perform per day . This discrepancy occurs when enough ridership during some parts of the day justifies the addition of a bus for a few laps . If the laps are distributed more equitably between the buses, it could mean that more runs will be easier to electrify . Pasadena Transit would benefit from having to purchase fewer buses . In addition, fewer buses would charge simultaneously, which would decrease the maximum power demand . These opti ons are explored in Appendix G. Route 177 may be considered a drop -in replacement as well due to the long break between the AM and PM service time, giving the buses adequate time to charge.

An FCEB is considered a drop-in replacement if it can complete its shift with 10 percent of its hydrogen capacity remaining. The useable hydrogen tank capacity of each OEM was calculated. Each kg of hydrogen has 33.333 kWh of energy . However, the efficiency of the fuel cell is 50 percent, meaning that 16.667 kWh is available to the drivetrain. Based on these assumptions, the energy capacity of these FCEBs is detailed in Table 2-6.

Table 2-6: Hydrogen Fuel Analysis for FCEBs
OEM KWh Equivalent
OEM 6 562.51
OEM 7 750.02

Based on these figures, both FCEB OEMs can serve as a drop -in replacement for shifts because their energy capacity exceeds energy demand for each shift. It is estimated that FCEBs will consume approximately 400 kg of hydrogen per weekday and each bus would consume an average of 15.2 kg of hydrogen per day . During weekend service, the buses are estimated to consume about 250 kg of hydrogen per day, with the average bus consuming about 15. 3 kg of hydrogen per day.

Scenario 2
CALSTART estimated the energy needs of each individual bus based on Scenario 2 , which assumes that Pasadena Transit enacts Scenario 1 and also operates Metro's Route 256.

Figure 2-5 displays the charging schedule for the buses and the routes they will be deployed on for weekdays under Scenario 2 , and Figure 2-6 displays the charging schedule for the buses and the routes they will be deployed on for weekends under Scenario

2. The blue color in dicates the intervals during which the bus is in operation, while the white unshaded squares are when the bus is not in operation and thus able to charge. Each square represents the half hour after its labeled time.

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59 Figure 2-5: Pasadena Transit Weekday Operating Schedule (Scenario 2)

Routes
(Weekdays) Bus # of Laps
12:00:00 AM
12:30:00 AM
1:00:00 AM
1:30:00 AM
2:00:00 AM
2:30:00 AM
3:00:00 AM
3:30:00 AM
4:00:00 AM
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8:30:00 PM
9:00:00 PM
9:30:00 PM
10:00:00 PM
10:30:00 PM
11:00:00 PM
11:30:00 PM
10 1 15
2 15
3 17
20CW 1 13
2 13
3 10
4 5
5 1
20CC 1 11
2 12
3 13
4 4
5 1
31/32 1 12
2 10
3 11
4 1
40 1 13
2 12
3 5
51/52 1 13
2 6
3 1
60 1 12
177 1 8
2 8
256 1 7
2 7
3 7
4 7
5 7
Legend
Transit Operation
Charging
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60 Figure 2-6: Pasadena Transit Weekend Operating Schedule (Scenario 2)

The energy analysis for weekdays under Scenario 2 is provided In Table 2-7, and the energy analysis for weekend service under Scenario 2 is provided in Table 2-8.

Table 2-7: Pasadena Transit Scenario 2 Weekday Service
Route Bus # of Laps OEM 1 (kWh) OEM 2 (kWh) OEM 3 (kWh) Scenario 1 6175.23 6582.16 6827.16
256 1 7 464.26 483.58 547.17
2 7 464.26 483.58 547.17
3 7 464.26 483.58 547.17
4 7 464.26 483.58 547.17
5 7 464.26 483.58 547.17
Total 8,496.53 9,000.06 9,563.01
Table 2-8: Pasadena Transit Scenario 2 Weekend Service
Route Bus # of Laps OEM 1 (kWh) OEM 2 (kWh) OEM 3 (kWh) Scenario 1 3,370.44 3,588.74 3,780.73
256 1 7 464.26 483.58 547.17
2 7 464.26 483.58 547.17
3 7 464.26 483.58 547.17
4 7 464.26 483.58 547.17
5 7 464.26 483.58 547.17
Total 5,691.74 5,910.04 6,102.03

Routes
(Weekdays) Bus # of Laps
12:00:00 AM
12:30:00 AM
1:00:00 AM
1:30:00 AM
2:00:00 AM
2:30:00 AM
3:00:00 AM
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10 1 11
2 10
3 11
20CW 1 9
2 9
20CC 1 9
2 9
31/32 1 10
2 10
40 1 9
2 9
51 1 32
H 1 13
H 2 13
256 1 7
2 7
3 7
4 7
5 7
Legend
Transit Operation
Charging
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61 For Route 256, no BEB model can serve as a drop -in replacement. Using the same methodology employed for Scenario 1, a n FCEB can serve as a drop-in replacement for Route 256. It is estimated that FCEBs will consume approximately 540 kg of hydrogen per weekday and each bus would consume an average of 18.6 kg of hydrogen per day . During weekend service, the buses are estimated to consume about 385 kg of hydrogen per day, with the average bus consuming about 18.3 kg of hydrogen per day.

Pasadena Transit Route 51/52 Demonstration
CALSTART also hosted a demonstration of shuttle buses on Pasadena Transit Route 51/52 . The Pasadena Department of Transportation wanted to conduct this demonstration to determine if shuttle buses can be used to replace the transit bus tha t currently serves this route. The main reason for exploring this option is that ridership on this route is lower than other routes.

In addition, there is little room to turn the bus around at the route terminus and the roads on this route are narrow , meaning that shuttle buses could be easier to maneuver on this route . Since electric shuttle buses have a smaller battery than transit buses, they were not expected to be able to be able to serve the route as a drop-in replacement. However, electric shuttle buses are less expensive than transit buses. As a result, it would be economically viable to replace transit buses with electric shuttle buses on a 2:1 basis. The main objective of this demonstration was to determine whether an electric shuttle bus is able to serve Route 51/52 on a 2:1 basis.

During this demonstration, the bus followed the transit bus that was serving Route 51/52. The Route 51/52 demonstrations were held on a Thursday, operating on the same day of the week to control for traffic patterns . The entire Route 51/52 demonstration was on surface streets. However, this route involves significant elevation gain.

Table 2-9 displays the parameters for the bus demonstration.

Table 2-9: Pasadena Transit Route 51/52 Bus Demonstration Parameters Variable OEM 4 OEM 5
Number of People Onboard During the
Demonstration
2 2
Average Driving Speed 15 miles per hour 15 miles per hour Average Temperature 75° F 55° F
Date of Demonstration October 22, 2021 December 17, 2021

Table 2-10 displays the results from the bus demonstration on Route 51/52.

Table 2-10: The Pasadena Department of Transportation Route 51/52 Daily Energy Needs Analysis

Demonstration Metric OEM 4 OEM 5
Mileage 101 83.8
Energy (kWh) 56 71.4
Energy Economy (kWh per mile) 0.554 0.852
Laps Completed 8 7

The objective of the demonstration was to determine whether the shuttle buses can serve this route on a 2:1 basis. The buses travel a maximum of 13 laps per day. As a result, a bus was deemed to be a 2:1 replacement if it could complete at least 7 la ps, using less than 80% of the battery's capacity. As a result, both vehicles are able to serve as a 2:1 replacement for a transit bus on Route 51/52.

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62 Fleet Replacement Plan
The Pasadena Department of Transportation currently operates 29 transit buses through Pasadena Transit and 15 shuttle buses through Pasadena Dial-A-Ride (44 total vehicles) . The Pasadena Department of Transportation will replace its fleet with ZEBs over multiple years. CALSTART developed a fleet replacement plan based on the Pasadena Department of Transportation’s fleet replacement schedule. The Pasadena Department of Transportation plans to replace the current fleet as the buses reach the end of their useful life.

There are several assumptions that guided this fleet replacement plan . The first assumption is that Pasadena Transit will be replacing their fleet with 35 -foot buses . The second assumption is that any bus can be deployed on any route , meaning a particular bus will not be dedicated to a specific route. This fleet replacement plan also assumes that the Pasadena Department of Transportation will comply with the ICT Rule by beginning to purchase ZEBs after 2026, when the ICT Rule comes into effect for small transit agencies. This fleet replacement shows how RNG buses will be phased out over time. This replacement plan is based on the 2018 Short-Range Transit Plan but has been revised based on current funding opportunities. The fleet replacement plan is displayed in Figure 2-7.

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63 Figure 2-7: The Pasadena Department of Transportation Fleet Replacement Plan

Fleet Type Vehicle Length
(in feet) 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 25 Legend
25 CNG Bus Purchase
25 ZEB Purchase
25 25
25 25
25 25
25 25
25 25
25 25
35 35
35 35
35 35
35 35
35 35
35 35
35 35
35 35
35 35
35 35
35 35
35 35
35 35
35 35
35 Pasadena Transit Fleet Pasadena Dial-A-Ride Fleet
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64 According to this plan, the first ZEB purchases that are required by the ICT rule would take place in 2027. If this plan is followed, Pasadena Dial-A-Ride would be fully zero-emission by 2033 and Pasadena Transit would be fully zero-emission by 2040.

It is important to note that the Pasadena Department of Transportation is planning to expand service . Specifically, Pasadena Transit may adopt routes from Metro according to the Metro NextGen Bus Plan . As a result, Pa sadena Transit will need to purchase more buses. Furthermore, based on the energy modelling results, BEBs currently cannot serve as a drop-in replacement on all routes (unlike FCEBs). As a re sult, additional BEBs would need to be purchased to operate these routes. Based on the energy modelling, Pasadena Transit would need to deploy 44 BEBs or 29 FCEBs to meet the service needs of Scenario 1. Pasadena Transit would need to deploy 64 BEBs or 42 FCEBs to meet the service needs of Scenario 2 . Both of these figures include spare buses.

The ZEB Rollout Plans outlined In Figure 2-8 and Figure 2-9 were calculated by modifying the existing fleet replacement plan .

Since BEBs are not a drop -in replacement for a RNG bus, additional BEBs must be p rocured to operate these routes. A transit agency can choose when they purchase the additional buses but might wish to purchase the extra buses immediately to obtain environmental benefits of the bus earlier. Alternatively, a transit agency might delay purchasing extra BEBs with the expectation that the range of the buses will improve in the future, which might increase the number of routes where they can serve as a drop-in replacement. These ZEB Rollout Plans assume that the extra buses are spaced out over the course of the planned deployment and that additional buses are included in every planned bus purchase . This approach allows Pasadena Transit to maintain the same level of service and flexibility so all buses can serve all routes.

The fleet replacement plan outlined above assumes that the buses will be deployed in accordance with the minimum requirements of the ICT Rule. Under this plan, ZEBs will not be purchased until after 2026. However, if funding becomes available, it might be possible to deploy buses ahead of this schedule. The main barrier to deploy ing ZEBs is the procurement and construction of a transit facility. If a transit facility is obtained and built quickly, ZEB purchases could potentially begin ahead of the 2026 ICT mandate. If the Pasadena Department of Transportation wishes to deploy buses before a transit facility is built, they will need to use public stations, if available, or otherwise secure a location to deploy temporary chargers.

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65 Figure 2-8: Scenario 1 ZEB Rollout Plan

Year
Pasadena Transit Pasadena Dial-A-Ride Pasadena Transit Pasadena Dial-A-Ride 2022
2023
2024
2025
2026
2027 3 2
2028 3 2
2029
2030 8 3 8 2
2031
2032 7 4
2033 8 6 5 9
2034 8 5
2035
2036
2037 13 7
2038
2039
2040
2041
Total 44 15 29 15
BEBs FCEBs
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66 Figure 2-9: Scenario 2 ZEB Rollout Plan

Year
Pasadena Transit Pasadena Dial-A-Ride Pasadena Transit Pasadena Dial-A-Ride 2022
2023
2024
2025
2026
2027 3 2
2028 3 2
2029
2030 12 3 10 2
2031
2032 10 6
2033 12 6 7 9
2034 12 6
2035
2036
2037 18 13
2038
2039
2040
2041
Total 64 15 42 15
BEBs FCEBs
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67 The energy modelling used to develop these fleet replacement plans is based on 120 degrees Fahrenheit weather, which would represent the worst-case conditions the buses will operate in . As a result, the buses will operate in more favorable conditions most of the time, which would reduce the energy needs of the bus and improve their performance. In addition, this assessment is based on current BEB technology. It is very likely that there will be improvements in technology over time, which would reduce the number of buses that the Pasadena Department of Transportation would need to purchase.

The Pasadena Department of Transportation has the option to purchase either BEBs or FCEBs . There are multiple factors that need to be considered when selecting a technology , the main factors being the capability of the technology, capital costs and total cost o f ownership, and infrastructure viability . Based on the energy analysis, FCEBs are able to serve as a drop -in replacement for RNG buses, whereas BEBs are only drop-in replacements for Pasadena Dial-A-Ride and a very limited amount of Pasadena Transit service. However, this is only one of several factors that need to be considered when making this decision .

The rest of this section will be devoted to exploring these factors . CALSTART ultimately recommends that the Pasadena Department of Transportation transitions to a fully BEB fleet.

Utility Analysis
PWP Overview
The Pasadena Department of Transportation is served by PWP. PWP is the not-for-profit municipal utility that serves the City of Pasadena and is owned by the City of Pasadena. It , along with other municipal utility such as Glendale and Burbank , form part of the Southern California Public Power Authority (SCPPA). PWP power assets include 11 substations, 662 miles of distribution lines, and 11,082 utility poles; they deliver over 1 million MWh (megawatt-hour) of energy annually with a peak demand of 320 MW (PWP, 2020).

PWP uses a variety of resources to provide power to its service territory. The majority of PWP’s power is derived from renewable energy (PWP, n.d.). PWP additionally imports power from across California and as far north as British Col umbia. This power is obtained from PPAs directly with PWP and SCPPA and is delivered using the electric transmission grid. PWP owns the Glenarm Power Plant, located in the City of Pasadena, which is a 71 MW natural gas power plant (Stantec, n.d.). In 2017, it completed an update of one of its gas turbines to maximize efficiency.

PWP has a sustainability goal to achieve 60 percent of its power from renewable sources (PWP, 2020). According to their 2020 Annual Report, they currently obtain 37.5 percent of their power from renewables. PWP has a goal to eliminate coal -fired electricity generation from their portfolio no later than 2027. PWP receives 108 MW from a coal-fired power plant in Utah; the contract expires in 2027 (PWP, 2018). In 2017, PWP’s power mix had a higher percentage of eligible renewable th an the state average, which is 29 percent renewable, and a higher percentage of coal in their power mix (PWP, 2018).

PWP Utility Tariffs
The Pasadena Department of Transportation ’s buses are currently primarily domiciled at 303 N. Allen Ave. in Pasadena, which is in PWP’s service territory . This is a leased property by the transit services contractor , and the Pasadena Depa rtment of Transportation has been searching for a new location to house their transit fleet due to existing space constraints and the need to have a facility that is indefinitely available for transit use . The transition to BEBs will lead to a significant increase to the Pasadena Department of Transportation ’s utility costs. The power demand from charging the BEBs would qualify the Pasadena Department of Transportation for the Large (L-1) rate. The transit agency will have power demand greater than 300 kW and the voltage to be delivered will be less than 17 kilovolts (kV) (Pasadena Code of Ordinances, 13.04.067).

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68 PWP’s TOU tariff means the Pasadena Department of Transportation will be charged a different rate for energy depending on the time of day and se ason. The winter rate schedule runs from October through May. The winter on -peak rate applies on all weekdays (excluding holidays) from 6 am-10 pm. The winter off -peak rate applies all -day weekends and from 10 pm-6 am on weekdays. The summer rate schedule runs from June through September. The summer on-peak hours are noon-8 pm daily; the off-peak hours are daily from 8 pm-noon (Pasadena Code of Ordinances, 13.04.067). Additionally, there is a grid access charge, a meter charge, a transmission charge, and a distribution charge. These utility rates are current as of February 2022. However, utility rates may change in the future. Any ZEB operational strategy should be ad justed to any future changes.

Demand charges are assessed based on the maximum kW that is consumed over past four months of service. The Large (L -1) tariff has a constant demand charge that is charged at the same $/kW rate regardless of the time of day or month.

The Pasadena Department of Transportation Utility Costs Pasadena Transit operates Routes 10, 20, 31/32, 40, 51/52, and 60. In addition, under Scenario 1, Pasadena Transit will provide service to Route 177. Under Scenario 2, Pasadena Transit will provide service to both Route 177 and Route 256. Both Scenario 1 and Scenario 2 also include utility costs for Pasadena Dial-A-Ride.

Based on PWP’s Large (L -1) tariff and the energy and projected power demand, Table 2-11 shows the projected annual utility costs for operating the fixed -route and dial-a-ride fleets under Scenario 1. These figures assume that the entire fleet has been converted to BEB. In addition, these figures assume that the buses begin charging at 9 pm at night and are ready for service a t about 5 am, which is illustrated in Figure 2-10.

Table 2-11: Scenario 1 Utility Analysis (150 kW charging) OEM 1 + OEM 4 OEM 2 + OEM 4 OEM 3 + OEM 4
Charge Unmanaged Sequential Unmanaged Sequential Unmanaged Sequential Bureaucracy
Charges $18,575 $18,5745 $18,575 $18,575 $18,575 $18,575 Energy Charges
(per kWh) $240,173 $240,173 $253,325 $253,325 $262,700 $262,700 Demand
Charges (per
kW)
$932,447 $358,391 $932,447 $392,159 $932,447 $493,463
Total $1,191,195 $617,139 $1,204,347 $664,059 $1,213,722 $774,738

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69 Figure 2-10: Scenario 1 Load Schedule

The Scenario 2 projected annual utility costs for operating the Pasadena Transit's and Pasadena Dial-A-Ride's buses are displayed in Table 2-12. The figures for sequential charging assume that the Pasadena Department of Transportation will be levied utility charges based on the PWP’s Large (L-1) tariff for unmanaged charging. This is a secondary service rate. These figures also assume that the buses will charge using the standard charger offered by the OEM . Furthermore, the figures for sequential charging assume that the fleet will be charged in multiple batches, as shown in Figure 2-11.

Table 2-12: Scenario 2 Utility Analysis (150 kW charging) OEM 1 + OEM 4 OEM 2 + OEM 4 OEM 3 + OEM 4
Charge Unmanaged Sequential Unmanaged Sequential Unmanaged Sequential Bureaucracy
Charges $18,575 $18,575 $18,575 $18,575 $18,5745 $18,575 Energy
Charges (per
kWh)
$343,697 $343,697 $359,379 $359,379 $377,081 $377,081

Demand
Charges (per
kW)
$1,270,127 $459,695 $1,303,895 $493,463 $1,067,519 $628,535 Total $1,632,399 $821,967 $1,681,849 $871,417 $1,463,175 $1,024,191

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70 Figure 2-11: Scenario 2 Load Schedule

Utility Infrastructure
To power fleet charging, the utility needs to be able to deliver enough power to the depot . To do this, the utility needs to have appropriate FTM utility infrastructure in place. The Pasadena Department of Transportation is currently planning to build a new transit facility at 2180 E. Foothill Blvd. This facility is planned to house a bus depot, maintenance bays, and offices. The facility is expected to be able to house approximately 40-45 ZEBs, with the rest of the fleet being housed at a separate location.

The Pasadena Department of Transportation ’s new transit facility will need utility upgrades to bring power to the chargers and the rest of the transit facility. CALSTART held discu ssions with the Pasadena Department of Transportation and PWP to determine the utility upgrades that will be required. During these discussions, PWP stated that there is adequate grid distribution capacity to serve this location. As a result, the location will only require a transformer. The type of transformer required depends on the power demand from the site.

An electric service feasibility study was conducted by PWP that provided the site Interconnection point and circuit load for 2180 E. Foothill Blvd, two service Integration designs and approximate costs for each. The study is based on a 5000A 277/480V 3PH 4W service. The site would be connecting into t he Maple circuit. With the addition of the Pasadena Department of Transportation's vehicle charging load, there is potential for the circuit to become overloaded. PWP can mitigate this overload potential by transferring some existing service to other circuits. PWP has adequate grid capacity to charge the vehicles. There is existing conduit infrastructure to the site from the Maple circuit, but it needs to be tested before it can be re-used.

The first proposed service Integration design would be secondary service where PWP uses their equipment to step down the voltage for the customer. Because the power demand exceeds 5 ,000 amps, two 2,500 kVA transformers would need to be installed, and each 2,500 kVA transformer would also need dedicated switchgears. It is important to note that the maximum amount of power that can be supplied to the site is 5,000 kVA. A subterranean vault room would have to be buil t; the cost for this would be incurred by the Pasadena Department of Transportation. The lead time for this upgrade is typically 4 -6 months.

However, if there are delays, it can take up to one year. PWP estimates this would cost approximately $350,000 , not including the cost for the vault room.
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71 PWP's second proposed Integration design would be primary service. In this case, instead of PWP installing a utility transformer, the Pasadena Department of Transportation would need to supply their own transformer to step down the voltage. The installed cost of this would depend on the vendor that supplies and installs the transformers. PWP estimates this wou ld cost approximately $120,000.

It is important to note that the Pasadena Department of Transportation’s new transit facility is still in the design phase. Space will need to be allocated to accommodate the transformers. The most likely scenario is that the designs will need to incorporate a dedicated room to house the transformers. The transformers cannot be physically installed onsite until late in the construction process. The transformers cannot be installed until the room that houses them is physically built out. The Pasadena Department of Transportation will need to coordinate with PWP to ensure that their site design will accommodate transformers.

Coordination will also be needed to plan the installation of the transformers while the transit facility is being built.

Utility-Owned Charging Infrastructure
PWP has constructed and opened several charging stations in Pasadena. The first public charging station that Pasadena opened was the Marengo Charging Plaza. This charging station, which is located on the top floor of a parking garage at 155 East Green Street, houses 24 Tesla Superchargers and 20 DCFCs . In 2021, PWP opened the Arroyo EV Charging Depot, which is located at 64 East Glenarm Street. This charging station houses 20 Tesla Superchargers and 6 DCFCs. PWP is planning to Install additional DCFCs at the Arroyo EV Charging Depot at a future date. Both of these charging stations are open to the public to charge vehicles.

Public charging stations can potentially be used by the Pasadena Department of Transportation to charge small buses. The usefulness of a public charging station will be determined by several factors including whether the available chargers are interoperable with the buses and the parking configuration of the station. Public charging stations can be used as an emergency measure to extend the range of a vehicle if it runs low on charge during service. In addition, public charging stations can be used as a resiliency measure if a bus depot loses power. Since the Marengo Charging Plaza is located in a parking garage that buses cannot fit in, it is not an appropriate location to charge buses. However, the Arroyo EV Charging Depot does not have this constraint and, depending on availability, may present an opportunity to charge for a limited number of buses .

PWP stated that they might be able to provide a facility to charge some of the Pasadena Department of Transportation's buses.

The main challenge that the Pasadena Department of Transportation faces when deploying ZEBs is building a transit facility with charging infrastructure. If the Pasadena Department of Transportation were to deploy ZEBs before their transit facility is built, PWP stated that they might be able to provide a charging site. A charging site will need to be in a secure location to prevent vandalism or theft of the vehicles. In addition, the charging site will need to be designed to allow transit buses to easily navigate the yard. The site should be designed to allow for pull-through parking so buses can easily access the charging equipment.

Charging and Hydrogen Infrastructure Analysis
BEB Charging Infrastructure Deployment Plan
To deploy a BEB fleet, the Pasadena Department of Transportation will first need to build a permanent transit facility . The Pasadena Department of Transportation plans to build a transit facility at 2180 East Foothill Blvd. Initial designs for the site have been drafted and the construction process could begin once the Pasadena Department of Transit has secured funding to build the depot. The Pasadena Department of Transportation has already completed some of the environmental review process but will need to undergo an updated environmental review. The Pasadena Department of Transportation will also need to develop a final design for the depot. Once this is completed, the Pasadena Department of Transportation will need to ensure it has completed public outreach on the proposed design and develop a construction bid package. In addition, the project will go Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-85
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72 through the permitting process. Once a construction firm has been selected and permitting is complete, construction may begin.

Construction is scheduled to take 20 months. During the construction phase, utility infrastructure will also need to be installed After construction is complete, commissioning will take place. After commissioning, the facility is ready to be used. A Gantt chart outlining the proposed construction timeline is included below in Figure 2-12.

Figure 2-12: The Pasadena Department of Transportation Transit Facility Construction Timeline

If the construction process adheres to the proposed timeline, construction is expected to take 39 months. As a result, to begin deploying buses by 2027, the Pasadena Department of Transportation should initiate the construction process by 2023. The main barrier to beginning this process is obtaining funding to build the depot.

In addition to building a trans it facility, i nstalling charging infrastructure is vital for the successful deployment of a BEB fleet .

Deploying BEB chargers is more than simply installing the chargers . In addition to FTM utility infrastructure, electrification requires the deployment of BTM infrastructure (on the customer’s side of the meter). BTM infrastructure carries the power from the utility transformer, where the utility delivers power to the depot, to the actual chargers. BTM infrastructure upgrades entail installing appropriately sized transformers and switchgear. In addition, conduit through which the circuits can deliver power to the chargers is required. Conduit is typically underground, and the depot must be trenched to install this.

The depot will need FTM equipme nt. The mai n FTM equipment that will need to be deployed is a transformer. The type of transformer required will depend on the maximum power demand of the site. The most likely outcome is that the Pasadena Department of Transportation will require either one or two 2 ,500 kVA transformers . The Pasadena Department of Transportation will also need to deploy BTM equipment on their depot to bring power from the transformer to the chargers.

To serve the charging site under Scenario 1, the Pasadena Department of Transportat ion will need to deploy the following infrastructure:
• 16 Transit Bus Power Cabinets
• 46 Transit Bus Depot Chargers
• 15 Shuttle Bus Chargers
• 3 DC Fast Chargers (shuttle bus backup chargers)
• Electric Bus Switchboard (480 V)
• 2 Electrical Panelboards (120/208 V)
• A transformer (see Utility Infrastructure section for more details)500 kVA Transformer • Main Service Switchboard
• Automatic Transfer Switch (if natural gas generators are used to provide resiliency)

To serve the charging site under Scenario 2, the Pasadena Department of Transportation will need to deploy the following infrastructure:
• 22 Transit Bus Power Cabinets
• 64 Transit Bus Depot Chargers
Months from Grant Award 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 NEPA Determination
Develop Final Design
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Construction Bid Package
Permitting
Construction Phase
Install Utility Infrastructure
Commissioning
Facility in Service
Year 1 Year 2 Year 3 Year 4
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73 • 15 Shuttle Bus Chargers
• 3 DC Fast Chargers (shuttle bus backup chargers)
• 3 Electric Bus Switchboards (480 V)
• 2 Electrical Panelboards (120/208 V)
• A transformer (see Utility Infrastructure section for more details)500 kVA Transformer • Main Service Switchboard
• Automatic Transfer Switch (if natural gas generators are used to provide resiliency)

If all of the buses are housed at one location, the space required for bus parking and infrastructure under Scenario 1 is estimated to be approximately 111,500 square feet, and Scenario 2 would require approximately 147,600 square feet. More information can be found in Appendix K.

The Pasadena Department of Transportation will transition to zero-emission between 2027 and 2040. To minimize the amount of construction work needed to install BTM infrastructure, it is advisable to i nstall all of the BTM upgrades at the same time. To save time and reduce costs , BTM infrastructure installation should begin during the construction phase of the transit facility.

This would allow the infrastructure to be installed before concrete is laid. This would reduce the cost of deploying conduit by reducing the amount of trenching. In addition, the Pasadena Department of Transportation will need to install conduit directly to the location where each of the chargers will be located . This strategy allows the Pasadena Department of Transportation to install the infrastructure without having to do multiple rounds of trenching . The site will then be “charger ready” and as the buses are deployed, additional chargers can be added by simply running circuitry through the conduit to the chargers. To achieve this, preplanning will need to be conducted to identify where each of the chargers will be located on the site .

FCEB Hydrogen Fueling Infrastructure Deployment Plan
If the Pasadena Department of Transportation were to rollout a fleet of FCEBs, the main requirement would be to obtain hydrogen for the fleet. Under Scenario 1, the fleet would consume approximately 3,130 kg of hydrogen per week, which equates to approximately 162,760 kg per year . Under Scenario 2, the fleet would consume approximately 4,100 kg per week or approximately 213,200 kg per year . The Pasadena Department of Transportation would have several options for obtaining hydrogen for the fleet: produce hydrogen on-site via SMR or electrolysis, or alternatively opt to receive delivered gaseous or liquid hydrogen. Lastly, the Pasadena Department of Transportation could fuel at public fueling stations.

Several of these options can be elimi nated immediately. Producing hydrogen on -site via electrolysis is not viable because the utility costs would be high. Producing one kg of hydrogen via electrolysis requires 55 kWh of energy. Furthermore, compressing the hydrogen so it can be dispensed at 3 50 bar consumes between 1.7 and 6.4 kWh per kg of hydrogen (Monterey Gardner, 2009). This analysis uses the average of this range, which is 4.1 kWh per kg. Based on these figures, the production of hydrogen via electrolysis would require 59.1 kWh per kg of hydrogen . Under Scenario 1, the Pasadena Department of Transportation would consume about 28,960 kWh per day to produce hydrogen . Assuming the best -case scenario (that minimizes power demand) where the electrolyzer produces hydrogen 24 hours per day, po wer demand would be 1,207 kW . Under Scenario 2, the Pasadena Department of Transportation would consume approximately 37,233 kWh per day. Under the best-case scenario, this would entail power demand of 1,551 kW. This method for producing hydrogen is not viable; the amount of energy required to produce this much hydrogen would exceed the amount of energy that the entire BEB fleet uses by a factor of five. In addition, there would still be high power demand for electrolysis . Hydrogen produced via electrolysis is expected to cost $1,686,887 per year under Scenario 1 and $2,210,884 under Scenario 2. As a result, the utility bills would be higher than that of a BEB fleet, which makes this option financially infeasible . In addition, utility upgrades might be requi red to deliver this much power to the electrolyzer.

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74 The use of delivered gaseous or liquid hydrogen is also financially infeasible. Hydrogen can be delivered in gaseous form but only in limited quantities. Most trucks can only deliver approximately 250-280 kg of hydrogen. To serve the entire fleet, the Pasadena Department of Transportation would need to receive multiple truck deliveries per day . This situation would likely be incompatible with the Pasadena Department of Transportation's operations. However, if this option was pursued, the expected annual cost of hydrogen would be approximately $1,318,356 under Scenario 1 and $1,726,920 under Scenario 2. Liquid hydrogen is typically delivered in larger quantities and most liquid hydrogen trucks can deliver u p to 4,500 kg of hydrogen . When the Pasadena Department of Transportation’s fleet is fully zero-emission, the fleet would consume enough fuel to justify the use of liquid hydrogen. The annual hydrogen fuel price is projected to be approximately $1,362,301 under Scenario 1 and $1, 784,484 under Scenario 2, but these figures still greatly exceed the utility charges incurred for a BEB fleet.

Another option would be retail fueling. At the time of writing, there are no heavy-duty hydrogen stations currently in existence or planned in or near Pasadena. However, there are some light-duty stations near Pasadena. While Pasadena Dial-A-Ride could theoretically fuel at a light-duty station, the price of retail hydrogen is currently high. At this point in time, the use of retail fueling is currently infeasible due to the lack of heavy -duty hydrogen fueling stations and the high price of hydrogen at light -duty stations. However, the market for retail hydrogen fueling is rapidly c hanging, and the CEC has awarded grants to expand California’s retail hydrogen fueling market (CEC, 2020). As a result, the market for retail hydrogen fueling can change in the future.

The most viable option that the Pasadena Department of Transportation has to fuel an FCEB fleet would be to use on-site SMR.

On-site SMR is only economically viable at volumes of at least 200 kg per day (about 13 buses per day) . Although delivered hydrogen is not a viable option for fueling the entire fleet, it could be use d temporarily to fuel the fleet until the fleet size increases to consume more than 200 kg per day . There are two options for using delivered hydrogen. One option would be to use a mobile refueler. A mobile refueler is usually delivered in a shipping contai ner, trailer, or other non -permanent structure.

The mobile refueler would accept delivered hydrogen. When the fleet grows to the point where it consumes more than 200 kg per day, a hydrogen station with onsite production can be built and the mobile refuele r removed. The pricing for deploying a mobile refueler is not available. Alternatively, the Pasadena Department of Transportation would need to build a hydrogen station. The station would be designed to accept hydrogen from a tube trailer . The Pasadena Department of Transportation would then schedule deliveries of hydrogen. Once demand reaches 200 kg per day (about 13 buses per day), an on-site SMR can be deployed at the location. The capital cost of this approach is not clear because this proce ss involves replacing equipment as the fleet grows.

Based on the fleet replacement plan, the Pasadena Department of Transportation would be expected to reach a demand of 200 kg per day in 2033. When the on-site SMR is installed, the equipment used to accept delivered hydrogen can be left on-site. This will allow the Pasadena Department of Transportation to accept delivered hydrogen when the SMR is undergoing scheduled maintenance or if there is an equipment fault . The Pasadena Department of Transportation is projected to pay approximately $1,069,333 per year for hydrogen under Scenario 1 and $ 1,400,724 per year for hydrogen under Scenario 2 . This amount also exceeds the utility costs that would be associated with charging a BEB fleet .

It is important to note that, in addition to the cost of the fuel, there are capital expenditures associated with some of these options, such as a hydrogen fueling station. The Pasadena Department of Transportation would need to invest in a fueling station if it decides to obtain hydrogen via on-site electrolysis, delivered liquid hydrogen, or on-site SMR. The Pasadena Department of Transportation could avoid this capital expense if it was able to obtain hydrogen from retail fueling stations ; however, this is currently not a feasible option. The capital expenditures and annual fuel costs for each hydrogen pathway under Scenario 1 and Scenario 2 are displayed in Table 2-13 and Table 2-14. There are additional costs associated with deploying on -site hydrogen production equipment, which is explored further in Appendix N.

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75 Table 2-13: Hydrogen Cost Analysis – Scenario 1
Expense On-site Electrolysis Delivered Liquid
Hydrogen
Off-site Retail
Fueling
On-site SMR
Capital
Expenditures
$5,411,019 $2,208,627 $0 $4,650,006
Annual Cost of
Hydrogen Fuel
$1,686,887 $1,362,301 Off-site fueling not
currently available
$1,069,333

Table 2-14: Hydrogen Cost Analysis – Scenario 2
Expense On-site Electrolysis Delivered Liquid
Hydrogen
Off-site Retail
Fueling
On-site SMR
Capital
Expenditures
$5,411,019 $2,208,627 $0 $4,650,006
Annual Cost of
Hydrogen Fuel
$2,210,884 $1,784,484 Off-site fueling not
currently available
$1,400,724
Resiliency
PWP has a resilient and reliable grid . However, if there was an extended grid outage, it would compromise the Pasadena Department of Transportation’s ability to charge their buses and would disrupt their ability to provide service . Such an event is especially problematic because Pasadena Transit integrates with other forms of public transit, such as Metro’s L Line and numerous regional bus lines . This means that any disruption to the fleet would have impacts on the wider Los Angeles region .

As a result, the Pasadena Department of Transportation needs to have a resiliency option in the event of an extended outage and be able to deploy measures that would allow them to operate at full capacity in the event of a grid outage .

FTM Resiliency
PWP recognizes that a grid outage would put the Pasadena Department of Transportation in a precarious position. As a result, PWP is interested in providing a resiliency option to the Pasadena Department of Transportation. PWP owns a power plant with 200 MW of gene ration capacity . This plant is located in Pasadena . PWP stated that this plant can potentially be used as a resiliency measure. If the grid were to experience an outage, PWP could turn on their power plant and provide power to the Pasadena Department of Transportation, among other customers.

PWP has also stated that they are looking into deploying FTM batteries to provide power to their customers in the event of an outage. It is important to note that other utilities offer FTM resiliency options to their customers. These utilities typically finance this resiliency through a special utility tariff. Under this tariff, customers pay a higher rate for energy (per kWh) in exchange for resiliency. This strategy is beneficial because it allows the transit agency to avoid the capital expenses associated with deploying resiliency assets . The Pasadena Department of Transportation should consider exploring options for FTM resiliency and establishing a special utility tariff with PWP.

BTM Resiliency
Despite the fact that PWP can potentially offer a FTM resiliency solution, the Pasadena Department of Transportation should also consider a BTM resiliency solution . A BTM resiliency solution could protect the Pasadena Department of Transportation in the event of a disruption to the local grid . Having a BTM resiliency solution could also complement FTM resiliency and provide additional protection in case of an outage. This section will outline a BTM resiliency strategy for Scenario 1 and Scenario 2 .

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76 To develop thes e resiliency strategies, CALSTART used Sandia National Laboratory’s Microgrid Design Toolkit (MDT) . MDT can be programmed with information specific to the site being analyzed, such as the load profile and energy needs of the site/fleet.

Furthermore, factors such as the type of assets that can be included in the energy portfolio and the cost of different energy assets can be programmed into MDT . Users can also input objectives and criteria that the microgrid needs to be able to meet , which can include minimizing the capital and operational costs of the microgrid, the percent of energy needs the microgrid meets, or ensuring that a certain percentage of the energy produced comes from renewable energy . Once this information is input into the model, MDT projects the performance of all possible combinations of energy assets . It then selects the set of energy assets that can meet the objectives. MDT and the assumptions programmed into the model are explained in more detail in Appendix I. NREL’s REopt model was also used to evaluate resiliency scenarios.

This analysis assumes th at the Pasadena Department of Transportation ’s options for BTM resiliency are limited . The Pasadena Department of Transportation does not yet have a property for its depot. However, due to the scarcity of land in Pasadena, it is likely that any depot occupied in the future will be space constrained . This factor limits the type of generation assets that can be deployed. The results of the resiliency analysis are outlined below.

Scenario 1
The Pasadena Department of Transportation has multiple options for providing resiliency to the fleet under Scenario 1. The fleet has a peak power demand of 2,628 kW, and the buses consume between approximately 7,700 and 8,342 kWh per day. Based on modeling results from NREL’s REopt Lite tool, to provide resiliency for the entire fleet during a seven-day grid outage entirely using solar and storage would require a 2,948 kW PV solar array and a battery energy storage system with a power capacity of 2,628 kW and storage capacity of 31,006 kWh. On the assumption that the panels have an efficiency of 19 percent, a solar array with a surface area of approximately 15,515.8 square meters (3.8 acres) would be required to fully power the fleet during a seven-day outage. In addition, the required battery storage system would occupy an area of approximately 325 square meters (0.08 acres).

Alternatively, the Pasadena Department of Transportation could employ backup generators. In the event of a grid outag e, the Pasadena Department of Transportation would need three 1000 kW /1250 kVA generators. In theory , either a natural gas generator or a diesel generator could be used . However, natural gas generators would be the preferred option because they produce fewer emissions. A natural gas turbine would need access to a gas pipeline to obtain fuel. If the generator maintains access to fuel, it is capable of powering the fleet indefinitely during an outage. However, if the generator is permitted as a backup generator, its operations would be limited to 200 hours per year. It is theoretically possible that the generator could lose access to fuel if the natural gas network is disrupted during an emergency. However, disruptions to the natural gas network are rare , and a simultaneous disruption to both the grid and the natural gas network is exceedingly rare . If the Pasadena Department of Transportation wanted to protect against this possibility, it would be advisable to install a 2,000-gallon CNG storage tank. The addition of the natural gas storage tank would provide one day of fuel in the event of a gas network disruption .

The natural gas generators and the CNG storage tank would require a physical footprint of 1,310 square feet. This figure includes equipment clearances. Natural gas generators entail high capital expenditures and a future depot might be space constrained , but it would be possible to scale down the natural gas generators. According to MDT modelling, if the Pasadena Department of Transportation used two 1,000 kW/1,250 kVA generators, it would be able to provide 85 percent of the fleet’s energy needs. If the Pasadena Department of Transportation used a single 1,000 kW/1,250 kVA generator, it would be able to provide 54 percent of the fleet’s energy needs. The generators would be able to provide this power indefinitely as long as it maintains access to its fuel source.

Other factors can affect the viability of resiliency options . Resiliency is typically customi zed to a particular site , so the specific Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-90
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77 qualities of a depot can affect resiliency options. The Pasadena Department of Transportation has identified 2180 East Foothill Blvd as a possible location for a transit facility . A feasibility study should be completed to determine what resiliency assets can be hosted on this site In addition, there are financial considerations that should affect the decision about which resiliency option to deploy. These considerations are discussed in the Financing Strategy section.

Scenario 2
The Pasadena Department of Transportation has multiple options for providing resiliency to the fleet under Scenario 2. The fleet has a peak power demand of 2,792 kW and the buses consume between approximately 10,000 and 11,100 kWh per day. Based on modeling results from NREL’s REopt Lite tool, to provide resiliency for the entire fleet during a seven-day grid outage, entirely using solar and storage would require a 3 ,805 kW PV solar array and a battery storage system with a power capacity of 3,138 kW and storage capacity of 38,180 kWh . On the assumption that the panels have an efficiency of 19 percent, a solar array with a surface area of approximately 20,026.3 square meters (4.9 acres) would be required to fully power the fleet during a seven - day outage. In addition, the required battery storage system would occupy an area of approximately 400 square meters (0.10 acres).

Alternatively, the Pasadena Department of Tran sportation could use generators. The Pasadena Department of Transportation could employ the resiliency options as in Scenario 1 and deploy three 1,000 kW/1,250 kVA natural gas generators and a 2,000- gallon CNG storage tank. These assets would have the same space requirement as in Scenario 1. If the Pasadena Department of Transportation faced financial constraints or space constraints on a site, they would be able to scale down the resiliency assets.

Two 1,000 kW/1,250 kVA natural gas generators would be able to provide 74 percent of the fleet’s energy needs. A single 1,000 kW/1,250 kVA natural gas generator would be able to provide 46 percent of the fleet’s energy needs. The generators would be able to provide this power indefinitely as long as it maintains access to its fuel source.

Similar to Scenario 1, A feasibility study should be completed to determine what resiliency assets can be hosted on the proposed transit facility at 2180 East Foothill Blvd.

Financial Analysis and Cost Estimates
CALSTART developed cost estimates for the Pasadena Department of Transportation’s transition to both a BEB fleet and an FCEB fleet. This financial analysis assumes that the buses are deployed according to the Fleet Replacement Plan (see page 62 and 63).

Table 2-15 outlines the expected cost of purchasing and operating a RNG fleet. This scenario represents a continuation of the status quo between 202 2 until 2040. Under this status quo scenario, the Pasadena Department of Transportation is projected to spend $29,982,281 for fleet replacement between 2022 and 2040. When this amount is discounted at a rate of 4 percent per year (discounted to 2022 dollars), this amounts to a net present value of $18,429,997.

Since the Pasadena Department of Transportation already has access to CNG fueling infrastructure, this figure includes the capital expenditures associated with purchasing buses. In addition, this analysis takes into account operational costs such as maintenance costs, midlife bus repairs, and the cost of fuel. This analysis does not include the cost of acquiring land , building costs, or labor associated with operating the buses.

Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-91
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78 Table 2-15: RNG Fleet Financial Analysis

The costs for transitioning to a BEB fleet are outlined In Table 2-16 and Table 2-17. These tables outline the expected cost of purchasing and operating a BEB fleet under Scenario 1 and Scenario 2, respectively:

• Table 2-16 outlines the expected cost of purchasing and operating a BEB fleet under Scenario 1. Transitioning to a fully BEB fleet under Scenario 1 is projected to cost $56,181,098 between 2022 and 2040. Discounting this amount at a rate of 4 percent per year (discounted to 2022 dollars) results in a net present value of $35,974,785. • Table 2-17 outlines the expected cost of purchasing and operating a BEB fleet under Scenario 2. Transitioning to a fully BEB fleet under Scenario 2 is projected to cost $75,392,385between 2022 and 2040. Discounting this amount at a rate of 4 percent per year (discounted to 2022 dollars) results in a net present value of $45,724,474.

These figures include the capital expenditures associated with purchasing and installing chargers and the cost of the buses. In addition, this analysis takes into account operational costs such as maintenance costs, the cost of electricity from the utility, and the cost of maintaining charging infrastructure. This analysis does not include labor associated with operating the buses . Since the resiliency options available to the Pasadena Department of Transportation are uncertain, the cost of resiliency assets was Year
Transit Buses
Shuttle Buses
Bus Maintenance
Midlife Repairs
RNG Fuel Costs
Total Cost
Net Present Value (2022 dollars)
2022
2023
2024
2025
2026
2027 $360,000 $10,275 $25,200 $25,641 $421,116 $332,814 2028 $360,000 $20,549 $25,200 $51,282 $457,032 $347,306 2029 $20,549 $51,282 $71,832 $52,487
2030 $5,200,000 $360,000 $77,071 $401,200 $179,487 $6,217,758 $4,368,515 2031 $77,071 $179,487 $256,558 $173,322
2032 $2,600,000 $100,195 $188,000 $230,769 $3,118,964 $2,026,019 2033 $3,250,000 $1,620,000 $175,335 $348,400 $410,256 $5,803,992 $3,625,156 2034 $3,250,000 $204,240 $235,000 $474,359 $4,163,599 $2,500,549 2035 $204,240 $474,359 $678,599 $391,874
2036 $204,240 $474,359 $678,599 $376,802
2037 $4,550,000 $244,706 $329,000 $564,103 $5,687,808 $3,036,767 2038 $244,706 $564,103 $808,808 $415,221
2039 $244,706 $564,103 $808,808 $399,251
2040 $244,706 $564,103 $808,808 $383,895
Total $18,850,000 $2,700,000 $2,072,588 $1,552,000 $4,807,692 $29,982,281 $18,429,977 Capital Expenditures Operational Expenditures Total Costs Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-92
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79 not included. These figures include the cost of utility service planning . However, they do not include any additional utility infrastructure upgrade costs. The cost estimates for a BEB fleet will increase if additional utility upgrades are required.

Table 2-16: BEB Fleet Financial Analysis (Scenario 1)

It is important to note that the financial analysis provided in Table 2-16 is based on the current technological capabilities of BEBs.

BEB technology is expected to impr ove and the range of BEBs will increase in the future. While current BEBs are not projected to be a drop-in replacement for all of the Pasadena Department of Transportation bus fleet vehicle assignments, improvements in BEB range could be serv e more shifts on a drop-in basis, reducing the number of buses that would need to be purchased. If BEB range were to increase by 10 percent, then the Pasadena Department of Transportation would only need to purchase 40 transit buses and 15 shuttle buses. Under these conditions, the total cost between 2022 and 2040 is projected to be $51,180,654.

Discounting this amount at a rate of 4 percent per year (discounted to 2022 dollars) results in a net present value of $30,738,121.

Year
Transit Buses
Shuttle Buses
Driver and Maintenance Training
Charging Infrastructure
Utility Infrastructure
Bus Maintenance
Midlife Repairs
Infrastructure Maintenance
Utility Costs (fueling costs)
Total Cost
Net Present Value (2022 dollars)
2022
2023 $350,000 $350,000 $323,595
2024
2025 $6,600,000 $24,000 $6,624,000 $5,662,223
2026 $24,000 $24,000 $19,726
2027 $840,000 $78,750 $29,484 $63,000 $24,000 $33,766 $1,069,000 $844,846 2028 $840,000 $58,968 $63,000 $24,000 $67,531 $1,053,499 $800,573 2029 $58,968 $24,000 $67,531 $150,499 $109,968
2030 $5,680,000 $840,000 $176,925 $497,608 $24,000 $191,339 $7,409,872 $5,206,077 2031 $176,925 $24,000 $191,339 $392,264 $264,999
2032 $4,970,000 $254,338 $380,282 $24,000 $270,126 $5,898,746 $3,831,713 2033 $5,680,000 $1,680,000 $401,779 $560,608 $24,000 $427,699 $8,774,086 $5,480,268 2034 $5,680,000 $490,251 $434,608 $24,000 $517,741 $7,146,600 $4,292,063 2035 $490,251 $24,000 $517,741 $1,031,992 $595,950
2036 $490,251 $24,000 $517,741 $1,031,992 $573,028
2037 $9,230,000 $634,019 $706,238 $24,000 $664,059 $11,258,316 $6,010,907 2038 $634,019 $24,000 $664,059 $1,322,078 $678,719
2039 $634,019 $24,000 $664,059 $1,322,078 $652,615
2040 $634,019 $24,000 $664,059 $1,322,078 $627,514
Total $31,240,000 $4,200,000 $78,750 $6,600,000 $350,000 $5,164,214 $2,705,344 $384,000 $5,458,790 $56,181,098 $35,974,785 Capital Expenditures Operational Expenditures Total Costs Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-93
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80 Table 2-17: BEB Fleet Financial Analysis (Scenario 2)

If the Pasadena Department of Transportation were to transition to a n FCEB fleet, it will need to select a hydrogen fueling pathway. The hydrogen fueling pathway impacts the costs associated with deploying a n FCEB fleet . Table 2 -18 provides an overview of the costs associated with each hydrogen production pathway.

Table 2-18: Hydrogen Production Pathways Financial Analysis Hydrogen Production Pathway Cost Estimates Net Present Value Scenario 1
On-site SMR $61,762,767 $37,585,750
On-site Electrolysis $68,375,238 $41,608,721
Delivered Gaseous Hydrogen* $60,867,226 $36,377,107
Delivered Liquid Hydrogen $62,301,551 $37,293,412
Scenario 2
On-site SMR $81,107,913 $46,137,566
On-site Electrolysis $87,406,807 $50,072,114
Delivered Gaseous Hydrogen* $80,532,287 $45,152,594
Delivered Liquid Hydrogen $81,969,469 $46,065,583
* Deemed to not be feasible as it would conflict with the Pasadena Department of Transportation's operations

The most cost-effective method for obtaining hydrogen under both Scenario 1 and Scenario 2 would be through on-site SMR.

The cost of transitioning to a fully FCEB fleet using on-site SMR hydrogen production is detailed in Table 2-19 (Scenario 1) and Table 2-20 (Scenario 2). These tables outline the expected cost of purchasing and operating a BEB fleet under Scenario 1 and Scenario 2, respectively:
• Under Scenario 1, an FCEB fleet is projected to cost $61,762,767 between 2022 and 2040. A discount rate of 4 percent per year (discounted to 2022 dollars) amounts to a net present value of $39,089,180.

Year
Transit Buses
Shuttle Buses
Driver and Maintenance Training
Charging Infrastructure
Utility Infrastructure
Bus Maintenance
Midlife Repairs
Infrastructure Maintenance
Utility Costs (fueling costs)
Total Cost
Net Present Value (2022 dollars)
2022
2023 $350,000 $350,000 $311,149
2024
2025 $6,600,000 $6,600,000 $5,424,719
2026
2027 $840,000 $78,750 $33,088 $63,000 $24,000 $33,092 $1,071,929 $814,578 2028 $840,000 $66,175 $63,000 $24,000 $66,184 $1,059,359 $774,063 2029 $66,175 $24,000 $66,184 $156,359 $109,856
2030 $8,520,000 $840,000 $245,936 $714,912 $24,000 $231,642 $10,576,490 $7,145,098 2031 $245,936 $24,000 $231,642 $501,578 $325,816
2032 $7,100,000 $368,163 $543,260 $24,000 $341,948 $8,377,372 $5,232,482 2033 $8,520,000 $1,680,000 $581,011 $777,912 $24,000 $540,499 $12,123,423 $7,281,013 2034 $8,520,000 $727,684 $651,912 $24,000 $672,866 $10,596,463 $6,119,193 2035 $727,684 $24,000 $672,866 $1,424,551 $791,002
2036 $727,684 $24,000 $672,866 $1,424,551 $760,579
2037 $12,780,000 $947,694 $977,868 $24,000 $871,417 $15,600,979 $8,009,125 2038 $947,694 $24,000 $871,417 $1,843,111 $909,811
2039 $947,694 $24,000 $871,417 $1,843,111 $874,819
2040 $947,694 $24,000 $871,417 $1,843,111 $841,172
Total $45,440,000 $4,200,000 $78,750 $6,600,000 $350,000 $7,580,312 $3,791,864 $336,000 $7,015,458 $75,392,385 $45,724,474 Capital Expenditures Operational Expenditures Total Costs Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-94
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81 • Under Scenario 2, an FCEB fleet is projected to cost $81,482,913 between 2022 and 2040. A discount rate of 4 percent per year (discounted to 2022 dollars) amounts to a net present value of $48,350,575.

These figures include the capital expenditures associated with building a hydrogen fueling station (see Appendix N for the methodology for estimating the hydrogen fueling station costs) and the cost of the buses. In addition, this analysis takes into account operational costs such as maintenance costs, the cost of hydrogen, and the cost of maintaining hydrogen infrastructure.

This analysis does not include the cost of acquiring land, building any facilities, or labor associated with operating the buses.

Table 2-19: FCEB Financial Analysis (Scenario 1)

Year
Transit Buses
Shuttle Buses
Driver and Maintenance Training
Hydrogen Infrastructure
Bus Maintenance
Midlife Repairs
Infrastructure O&M
Hydrogen Costs
Total Cost
Net Present Value (2022 dollars)
2022
2023
2024
2025 $4,650,006 $190,564 $4,840,570 $4,137,740
2026 $190,564 $190,564 $156,630
2027 $560,000 $153,325 $25,017 $42,000 $190,564 $46,493 $1,017,398 $804,065 2028 $560,000 $50,033 $42,000 $190,564 $92,985 $935,583 $710,966 2029 $50,033 $190,564 $92,985 $333,583 $243,746
2030 $9,560,000 $560,000 $187,652 $311,440 $190,564 $325,449 $11,135,105 $7,823,377 2031 $187,652 $190,564 $325,449 $703,665 $475,371
2032 $4,780,000 $243,952 $134,720 $190,564 $418,435 $5,767,671 $3,746,569 2033 $5,975,000 $2,520,000 $426,903 $357,400 $190,564 $743,884 $10,213,751 $6,379,479 2034 $5,975,000 $497,279 $168,400 $190,564 $860,116 $7,691,359 $4,619,231 2035 $497,279 $190,564 $860,116 $1,547,959 $893,908
2036 $497,279 $190,564 $860,116 $1,547,959 $859,527
2037 $8,365,000 $595,806 $235,760 $190,564 $1,022,840 $10,409,970 $5,557,968 2038 $595,806 $190,564 $1,022,840 $1,809,210 $928,800
2039 $595,806 $190,564 $1,022,840 $1,809,210 $893,077
2040 $595,806 $190,564 $1,022,840 $1,809,210 $858,728
Total $34,655,000 $4,200,000 $153,325 $4,650,006 $5,046,302 $1,291,720 $3,049,024 $8,717,390 $61,762,767 $39,089,180 Capital Expenditures Operational Expenditures Total Costs Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-95
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82 Table 2-20: FCEB Financial Analysis (Scenario 2)

Financing Strategy
The Pasadena Department of Tra nsportation will need a financing strategy to transition to a zero-emission fleet. The most important item that the Pasadena Department of Transportation will need is to secure the location and funding to build a transit facility. If the Pasadena Department of Transportation can utilize property already owned by the City of Pasadena, they can avoid having to purchase land . Otherwise, land will need to be purchased to house the fleet . The financial resources needed for a facility may potentially be obtained by winning a competitive grant(s) that funds capital expenditures . Grant programs such as Caltrans’s TIRCP and the U.S. Department of Transportation's RAISE can also be used toward purchasing a bus depot or financing utility and BTM infrastructure upgrades. The U.S. Department of Transportation also provides other competitive federal grants that could potentially be used as funding. For example, the Bus and Bus Facilities grant, if awarded, could be used to help fund the purchase of buses and related equipment, and the construction of bus facilities. However, grant funding should not be considered as a guaranteed source of funding as these are highly competitive grant programs.

Once a transit property has been acquired and the infrastructure upgrad es have been completed, the operational costs are expected to be covered by the Pasadena Department of Transportation’s operating budget. However, the purchase of the buses needs to be financed . Bus purchases can be financed with various grant and funding sources (see Financing Strategies & Resources on page 40). Most of these grant and finance p rograms will only partially finance the cost of the buses . To maximize funding for bus purchases, it would be advisable to apply for and stack multiple grants, though it is unlikely that grants will pay for the entire transition to a zero-emission fleet. The main objective when pursuing grants should be to cover the incremental cost of ZEBs, or the difference between the cost of a ZEB and a RNG bus. Using grants to cover the incremental cost of the buses would allow the Pasadena Department of Transportation to purchase ZEBs with the funding sources they normally employ to purchase buses.

The Pasadena Department of Transportation should also consider which finance methods would be most appropriate for their Year
Transit Buses
Shuttle Buses
Driver and Maintenance Training
Hydrogen Infrastructure
Bus Maintenance
Midlife Repairs
Infrastructure O&M
Hydrogen Costs
Total Cost
Net Present Value (2022 dollars)
2022
2023
2024
2025 $4,814,959 $190,564 $5,005,523 $4,278,742
2026 $190,564 $190,564 $156,630
2027 $1,195,000 $560,000 $153,325 $62,819 $75,680 $190,564 $73,610 $2,310,998 $1,826,415 2028 $1,195,000 $560,000 $125,638 $75,680 $190,564 $147,220 $2,294,102 $1,743,329 2029 $125,638 $190,564 $147,220 $463,422 $338,618
2030 $560,000 $166,814 $42,000 $190,564 $196,294 $1,155,672 $811,959 2031 $166,814 $190,564 $196,294 $553,672 $374,041
2032 $5,975,000 $275,031 $168,400 $190,564 $318,977 $6,927,972 $4,500,279 2033 $5,975,000 $2,520,000 $568,539 $357,400 $190,564 $662,491 $10,273,994 $6,417,106 2034 $7,170,000 $698,400 $202,080 $190,564 $809,711 $9,070,755 $5,447,660 2035 $5,975,000 $806,617 $168,400 $190,564 $932,395 $8,072,975 $4,661,942 2036 $806,617 $190,564 $932,395 $1,929,575 $1,071,425
2037 $9,560,000 $979,764 $269,440 $190,564 $1,128,688 $12,128,457 $6,475,482 2038 $979,764 $190,564 $1,128,688 $2,299,017 $1,180,254 2039 $4,780,000 $1,066,338 $134,720 $190,564 $1,226,835 $7,398,457 $3,652,086 2040 $8,365,000 $1,217,842 $235,760 $190,564 $1,398,592 $11,407,758 $5,414,606 Total $50,190,000 $4,200,000 $153,325 $4,814,959 $8,046,635 $1,729,560 $3,049,024 $9,299,410 $81,482,913 $48,350,575 Capital Expenditures Operational Expenditures Total Costs Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-96
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83 agency. If the Pasadena Department of Transportatio n is amenable to capital expenditures, then traditional financing models would be the most appropriate. However, if the Pasadena Department of Transportation prefer s to avoid or reduce capital expenditures, then financing models such as bus/battery leasing or IAAS would be more appropriate . These financing models would effectively allow the Pasadena Department of Transportation to pay capital expenditures from their operational budget.

There are additional financial considerations that need to be considered when deploying resiliency assets . The most likely candidates for the Pasadena Department of Transportation would be solar and storage or natural gas generators. However, there are unique financial considerations that need to be evaluated when selecting an asset. One major drawback of natural gas generators is that they are subject to air quality regulations and would likely be permitted as backup generators . As a result, they can only be used in the event of a grid outage and would remain idle for the vast majority of the time . This solution is problematic because generators have a high capital cost , meaning that the levelized cost of energy (per kWh) produced by the generator would be very high . Unlike generators, there are no restrictions on whe n solar and storage can be used. A solar and storage system is eligible for net metering, and excess energy produced can be exported to the grid and sold back to the utility .

Furthermore, the storage system can be used to “peak shave” and reduce overall power draw from the grid during times of high power demand when using the battery to provide energy. This scenario is useful because it can reduce demand charges, which are a major component of utility costs. Furthermore, a solar and storage system could potentially generate revenue by providing ancillary grid services . Since solar and storage can provide a transit agency with savings and/or revenue, the levelized cost of energy would be much lower than for a natural gas generator.

In addition, solar and sto rage is better situated to take advantage of the ITC . The ITC provides a tax credit for investment in particular DERs. Solar is eligible for a 10 percent ITC. The ITC for solar is permanent. Generators are only eligible for a 10 percent ITC if they are used in a combined heat and power system (a system where waste heat from the generator is captured and used to provide heating for a building or industrial process). Since air quality regulations limit backup generator use to 200 hours per year, they would likely not be useable in a combined heat and power system. Furthermore, the ITC for combined heat and power systems expires at the end of 2023.

If the Pasadena Department of Transportation opts to deploy DERs that are eligible for the ITC, acquiring them through a third- party ownership model, such as IAAS, would likely be the best option . The entity that owns the DER is eligible for the ITC . As a public agency, the Pasadena Department of Transportation is a tax-exempt entity and would not be able to benefit from the ITC.

However, if the Pasadena Department of Transportation were to finance the ITC-eligible DERs through an IAAS model where a third-party ow ns the asset, the infrastructure provider can realize the benefits of the ITC and pass the benefits on to the Pasadena Department of Transportation in the form of lower PPA rates . If the Pasadena Department of Transportation opts to deploy DERs that are eligible for the ITC, the use of an IAAS financing model should be seriously considered.

LCFS Credits
Once the buses are deployed, LCFS credits can also be used to finance capital expenditures and operational expenses . LCFS credits can be used in many ways. If the Pasadena Department of Transportation owns the charging equipment, they would earn the LCFS credits and could redeem them for cash . In addition, transit agencies can transfer their LCFS credits to their utility for a certain period of time to fund utility upgrades. LCFS credits can also benefit a transit agency even if they don’t own the charging equipment or if they opt to use an IAAS financing model. If this were to occur, the infrastructure provider would receive the LCFS credits. The infrastructure provider could then pass on the benefits of the LCFS credits to the transit agency in the form of lower PPA rates.

The estimated value of the LCFS credits for Pasadena Transit under Scenario 1 are displayed in Table 2-21 and Scenario 2 in Table 2-22. Table 2-23 shows the estimated value of the LCFS credits for Pasadena Dial-A-Ride. These projections provide the nominal revenue generated by LCFS credits. They also provide a net present value which assumes a 4 percent discount rate (discounted Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-97
CALSTART | Transit Fleet Electrification Feasibility Study for the Arroyo Verdugo Transit Operators

84 to 2022 dollars) and a LCFS credit value of $200.

Table 2-21: Pasadena Transit Fixed-Route Fleet LCFS Credit Value – Scenario 1 (displacing diesel fuel) Year Revenue Net Present Value Leveled cost per kWh
2022 $0.00 $0.00 $0.00
2023 $0.00 $0.00 $0.00
2024 $0.00 $0.00 $0.00
2025 $0.00 $0.00 $0.00
2026 $0.00 $0.00 $0.00
2027 $0.00 $0.00 $0.00
2028 $0.00 $0.00 $0.00
2029 $0.00 $0.00 $0.00
2030 $137,721.94 $96,761.61 $0.16
2031 $137,721.94 $93,040.01 $0.16
2032 $206,582.91 $134,192.32 $0.15
2033 $292,659.13 $182,794.03 $0.15
2034 $378,735.34 $227,458.63 $0.14
2035 $378,735.34 $218,710.22 $0.14
2036 $499,242.04 $277,211.38 $0.13
2037 $499,242.04 $266,549.41 $0.13
2038 $499,242.04 $256,297.51 $0.12
2039 $499,242.04 $246,439.91 $0.12
2040 $499,242.04 $236,961.45 $0.11
Total $4,028,366.83 $2,236,416.49 $0.13
Table 2-22: Pasadena Transit Fixed-Route Fleet LCFS Credit Value – Scenario 2 (displacing diesel fuel) Year Revenue Net Present Value Levelized cost per kWh
2022 $0.00 $0.00 $0.00
2023 $0.00 $0.00 $0.00
2024 $0.00 $0.00 $0.00
2025 $0.00 $0.00 $0.00
2026 $0.00 $0.00 $0.00
2027 $0.00 $0.00 $0.00
2028 $0.00 $0.00 $0.00
2029 $0.00 $0.00 $0.00
2030 $195,113.44 $137,084.11 $0.16
2031 $195,113.44 $131,811.65 $0.16
2032 $292,670.16 $190,112.95 $0.15
2033 $414,616.05 $258,967.96 $0.15
2034 $536,561.95 $322,245.20 $0.14
2035 $536,561.95 $309,851.16 $0.14
2036 $707,286.21 $392,730.93 $0.13
2037 $707,286.21 $377,625.89 $0.13
2038 $707,286.21 $363,101.82 $0.12
2039 $707,286.21 $349,136.36 $0.12
2040 $707,286.21 $335,708.04 $0.11
Total $5,707,068.04 $3,168,376.08 $0.13
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85 Table 2-23: Pasadena Dial-A-Ride Fleet LCFS Credit Value (displacing gasoline fuel) Year Revenue Net Present Value Leveled cost per kWh
2022 $0.00 $0.00 $0.00
2023 $0.00 $0.00 $0.00
2024 $0.00 $0.00 $0.00
2025 $0.00 $0.00 $0.00
2026 $0.00 $0.00 $0.00
2027 $12,040.52 $9,515.80 $0.18
2028 $23,618.31 $17,947.97 $0.17
2029 $23,155.57 $16,919.55 $0.16
2030 $34,033.65 $23,911.59 $0.15
2031 $34,033.65 $22,991.92 $0.15
2032 $34,033.65 $22,107.61 $0.14
2033 $85,084.13 $53,143.30 $0.14
2034 $85,084.13 $51,099.32 $0.13
2035 $85,084.13 $49,133.96 $0.13
2036 $85,084.13 $47,244.20 $0.12
2037 $85,084.13 $45,427.11 $0.12
2038 $85,084.13 $43,679.91 $0.11
2039 $85,084.13 $41,999.92 $0.11
2040 $85,084.13 $40,384.54 $0.10
Total $841,588.38 $485,506.70 $0.13

It is important to note that the number of LCFS credits awarded depends on the quantity of GHG emissions avoided by using BEBs. As California’s grid becomes cleaner, the amount of GHG emissions avoided will increase. The number of LCFS credits awarded is therefore likely to increase as the grid becomes less carbon intensive ., and the value of the LCFS credits earned has the potential to increase. The methodology used to make these calculations can be found in Appendix O.

Implementation Plan
The Pasadena Department of Transportation has many options for deploying a ZEB fleet . As discussed under Financial Analysi s and Cost Estimates , the most practical option would be to deploy a BEB fleet . While BEBs cannot currently serve as a drop -in replacement for RNG buses on all the Pasadena Department of Transportation's routes and would require purchasing more BEBs than FCEBs, a fully BEB fleet is less costly than deploying a fully FCEB fleet due to higher FCEB capital costs. In addition, the cost of hydrogen is greater than the utility costs associated with BEBs . As a result, a fully BEB fleet is more cost effective than a fully FCEB fleet.

The analysis for BEBs is also based on a worst -case scenario. Currently, there is a large inequality in the number of miles each bus is driven within the same route . As discussed in Appendix G, there are options for redistributing lap s so that the miles are shared more equitably between buses and help to reduce the intensity of the duty cycle for buses assigned to high -mileage shifts. Furthermore, the analysis for BEBs is based on current technology . As battery technology improves, BEB s will be able to obtain a longer range and become a drop -in replacement for more routes , reducing the number of buses that need to be purchased. The cost of BEBs and FCEBs is also expected to decrease over time.

If the Pasadena Department of Transportation were to deploy a BEB fleet, they have options for charging the buses . The Pasadena Department of Transportation will primarily charge the buses using depot charging . However, the Pasadena Department of Transportation could also theoretically employ overhead on -route charging to conduct midday charging to extend the range of the bus. CALSTART believes that overhead on-route charging is not a practical solution. Overhead on-route Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-99
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86 chargers require an overhead mast and a charging cabinet . This infrastructure would likely infringe on public property such as sidewalks. In addition, the bus stops can only accommodate one bus at a time . As a result, if a bus stopped to conduct an overhead fast charge, other buses would not be able to pick up or drop-off passengers at that stop. Due to the level of disruption that overhead on-route charging would cause to transit operations, CALSTART deems that this is not a viable option.

Currently, the main barrier to deploying a BEB fleet would be the provision of a site to house Pasadena Transit's and Pasadena Dial-A-Ride's fleets. Significant construction must be invested in a site to install infrastructure so it can host a fleet . Conducting infrastructure upgrades on a leased depot would not b e advisable because the Pasadena Department of Transportation would need to obtain permission from the property owner . In addition, due to the high costs associated with construction, it would not be financially viable to upgrade a leased depot , as any improvements to the site would effectively be left behind if the Pasadena Department of Transportation were to move depots . As a result, a BEB fleet cannot be deployed until a permanent depot is obtained.

The Pasadena Department of Transportation is planning to build a new transit facility at 2180 East Foothill Blvd . This transit facility is currently in the design phases. The Pasadena Department of Transportation will need to install both FTM and BTM infrastructure. PWP has stated that there is enough grid distribution capacity to serve this site. As a result, the main requ ired FTM infrastructure is a transformer. The installation of a transformer typically takes 4-6 months but can take up to one year. The installation of the transformer can be incorporated into the construction of the transit facility. The Pasadena Department of Transportation needs to coordinate with PWP to ensure that the final design for the site will accommodate the transformer and to schedule the installation of the transformer.

According to the Fleet Replacement Plan ( see pages 62 and 63), the first buses are scheduled to arrive in 2027 . The Pasadena Department of Transportation should work to ensure that construction is com pleted before the buses arrive . Construction is expected to take 39 months according to the proposed construction timeline. As a result, the construction process should be initiated in 2023 to ensure that the site is ready by 2027. The main barrier to starting the construction process is funding. Once the construction starts, The Pasadena Department of Transportation should work with PWP to submit a request for electrical service. The transformer cannot be installed until the room or vault that houses it is built. The Pasadena Department of Transportation should coordinate the construction schedule with PWP so they can install the transformer in a timely manner .

Construction will also need to occur BTM on the depot. Typically, the utility will deliver power to the site at a utility transformer.

The transformer is then connected to switchgear, which then connects to the chargers. Most BTM construction involves installing switchgear, the chargers, and the wires that connects the chargers to the sw itchgear. Generally, the wires are installed underground, which requires trenching.

The buses are scheduled to be phased-in over time, and they will not all arrive during the same year. In light of this, it is important to plan ahead. Since all the buses will not be arriving at the same time, it does not make sense to install all the chargers at once and expose unused chargers to wear and tear . Instead, the rest of the site should be constructed so that it is “EV Ready " by installing electrical panels as w ell as conduit and wires running to the locations where the unused chargers will eventually be installed. This approach will allow chargers to be installed quickly as they are needed.

It is vital that construction, utility upgrades, and the BTM construct ion occur before the buses arrive . If this is not completed, then the buses will not be able to charge. The Pasadena Department of Transportation should coordinate with their construction management firm and PWP to ensure that construction and the utility upgrades are coordinated with the delivery of the buses.

If the buses arrive before the utility upgrades and/or site construction are complete, the Pasadena Department of Transportation can use temporary chargers at a different site until the permanent charging infrastructure is ready for use.

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87 The Pasadena Department of Transportation is considering deploying pilot buses ahead of the ICT Rule requirements. A pilot deployment would consist of a deployment of up to four buses ahead of the planned 2027 transi tion to zero emission. The objective of a pilot deployment would be to accelerate the deployment of ZEBs and to gain operational experience with the buses before starting the full -fleet transition. The main challenge to a pilot deployment would be the lack of a charging site. If the Pasadena Department of Transportation were to deploy ZEBs before their transit facility is built, they will need to use public charging stations or secure a place to install temporary chargers . PWP has stated that they support a pilot deployment and can provide a temporary charging site if a pilot demonstration occurs.

Disadvantaged Communities
The Pasadena Department of Transportation's fleet serves disadvantaged communities. Disadvantaged communities are defined by CalEnviroScreen. Under CalEnviroScreen, each census tract in California was given a score based on Pollution Burden and Population Characteristics, which includes socio-economic and demographic traits. Each census tract was then given a percentile score to denote its performance relative to other census tracts. A higher percentile is a worse score. Under CalEnviroScreen 3.0, a disadvantaged community was defined as a census tract in the top 25th percentile (75th percentile or above). In addition, there are some c ensus tracts that did not have an overall CalEnviroScreen score because they are sparsely populated and therefore do not have a Population Characteristics score. Census tracts that have a pollution score in the top 5th percentile but do not have an overall CalEnviroScreen score are also considered to be disadvantaged communities. Under CalEnviroScreen 3.0, Pasadena has one census tract that is designated as a disadvantaged community. Census Tract 6037461600, which is marked in dark orange and is located due east of the Rose Bowl is Pasadena’s sole disadvantaged community.

Figure 2-13: Disadvantaged Communities In Pasadena (CalEnviroScreen 3.0)

In 2021, the California Environmental Protection Agency made changes to the scoring criteria for CalEnviroScre en. This change in methodology was made in CalEnviroScreen 4.0. Under this new scoring system, Census Tract 6037461600 is no longer in the top 25th percentile. In CalEnviroScreen 4.0, the California Environmental Protection Agency proposed a new definition of a disadvantaged community. Under this definition, any census tract that is in the top 25th percentile in CalEnviroScreen 4.0 is a disadvantaged community. Any census tract that has a Pollution Burden Score in the top 5th percentile but does not have an overall CalEnviroScreen score is also considered to be a disadvantaged community. Lastly, any census tract that was designate d as a disadvantaged community under the CalEnviroScreen 3.0 methodology is also considered to be a disadvantaged community Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-101
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88 (California Environmental Protection Agency, 2021) . Based on this proposed definition, Census Tract 603746160 would remain Pasadena’s sole disadvantaged community under CalEnvironScreen 4.0. It is important to note that this definition has not yet been finalized and is subject to change.

The Pasadena Department of Transportation aims to deploy zero emission buses in its disadvantaged community to help improve air quality. Pasadena Transit Routes 20, 31/32, 51/52, and 88 go through this disadvantaged community. As a result, replacing RNG buses with ZEBs on these routes would reduce emissions and help improve air quality in the disadvantaged community.

Furthermore, these routes run through Old Pasadena and near Metro light rail stations . As a result, these routes provide this community with access to economic centers and other forms of mobility.

Figure 2-14: Pasadena Transit Routes Serving Disadvantaged Communities

It is important to note that although Pasadena only has one census tract designated as a disadvantaged community, it has other census tracts with high pollution burden scores. Most of these high Pollution Burden census tracts are located in the northwestern part of Pasadena near the disadvantaged community. Pasadena Transit's routes also serve these areas and will provide air quality and mobility benefits to these census tracts as well. Furthermore, a significant portion of Pasadena Dial -A- Ride's stops are in the northwestern part of Pasadena. As a result, the transition to zero emission shuttle buses will also improve air quality in this area.

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89 Section III: City of Glendale Executive Summary
Glendale Beeline is a transit agency that serves Glendale, California, and the surrounding area, providing fixed-route and dial-a- ride service. Glendale Beeline is considering extending its service hours. Under Scenario 1, it would maintain the same service hours, while Scenario 2 would extend its lines’ service h ours until 10:30 pm to 11:30 pm on weekdays and Saturdays. The City of Glendale is planning to make its first purchase of five ZE vehicles in 2023, followed by eight ZE vehicles in 2024, ten in 2025, nine in 2028, and nine in 2032 to complete the fixed-route fleet's conversion.

Bus route modeling showed the current duty cycle for fixed -route transit operations can be served with a 1:1 drop -in replacement using FCEBs . BEBs can serve as a drop -in replacement for most but not all routes for fixed -route servic e. It is anticipated that in coming years technological improvements will allow all BEBs to serve as drop -in replacements for an increasing amount of Glendale Beeline's service. For the dial-a-ride fleet, an FCEB can serve as a drop -in replacement, but at present BEBs cannot on a 1:1 basis. Based on the current cost of ZE buses, fueling infrastructure, and Glendale Beeline's nee ds, and despite the necessity of acquiring additional buses, BEBs are recommended due to their lower overall total cost of ownership. Furthermore, due to space constraints on the City of Glendale's depot, installing hydrogen fueling infrastructure will not be feasible.

If the City of Glendale chooses to adopt BEVs for their fleet, the following table has a breakdown of the annual utility costs per option and charging logic for Scenario 1 and Scenario 2.

Charging
Method
Annual Utility Costs
($/year)
Scenario 1 Unmanaged $1,575,734
Sequential $769,794
Scenario 2 Unmanaged $1,697,103
Sequential $869,318

Transitioning to a ZE fleet will be more expensive than operating a CNG bus fleet . The cost of operating a CNG bus fleet is projected to cost $45,671,981 between 2021 and 2040 . When this amount is discounted at a rate of 4 percent per year (discounted to 2021 dollars), this amounts to a net present value of $32,420,044 . The cost of transitioning to a fully BEB fleet is detailed below:
• The cost of transitioning to a fully BEB fleet under Scenario 1 is projected to cost $66,709,857 between 2021 and 2040.

Section III: Executive Summary
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90 A discount rate of 4 percent per year (discounted to 2021 dollars) amounts to a net present value of $48,495,006. This assumes that the City of Glendale will operate 41 transit buses and 10 shuttle buses (51 vehicles in total). • The cost of transitioning to a fully BEB fleet under Scenario 2 is projected to cost $76,804,452 between 2021 and 2040.

A discount rate of 4 percent per year (discounted to 2021 dollars) amounts to a net present value of $54,606,233. This figure assumes that the City of Glendale will operate 47 transit buses and 10 shuttle buses (57 vehicles in total).

These figures include the capital expenditures associated with utility upgrades, purchasing and installing chargers, and the cost of the buses. In addition, this analysis takes into account operational costs like maintenance costs, the cost of electricity from the utility, and the cost of maintaining c harging infrastructure. This analysis does not include the cost of labor associated with operating the buses or upgrades to the utility's distribution system.

The cost of transitioning to an FCEB fleet depends on the pathway used to obtain hydrogen. If the City of Glendale transitioned to an FCEB fleet, t he most cost-effective hydrogen pathway would be to produce hydrogen on -site via SMR . Based on this pathway, the cost of transitioning to a fully FCEB fleet is detailed below:
• Transitioning to a fully FCEB fleet under Scenario 1 is projected to cost $88,713,803 between 2021 and 2040. A discount rate of 4 percent per year (discounted to 2021 dollars) amounts to a net present value of $63,160,164. This is based on the assumption that Glendale Beeline will ope rate 41 transit buses and Glendale Beeline will operate 10 shuttle buses (51 vehicles in total).
• Transitioning to a full FCEB fleet under Scenario 2 is projected to cost $91,564,649 between 2021 and 2040. A discount rate of 4 percent per year (discounted to 2021 dollars) amounts to a net present value of $64,887,964. This is based on the assumption that Glendale Beeline will operate 41 transit buses and Glendale Beeline will operate 10 shuttle buses (51 vehicles in total).

This figure includes the capital expenditures associated with building a hydrogen fueling station and the cost of the buses. In addition, this analysis takes into account operational costs like maintenance costs, the cost of hydrogen, and the cost of maintaining hydrogen infrastructure. This analysis does not include the cost of labor associated with operating the buses.

GWP has stated that there are limited options for providing FTM resiliency for the City of Glendale's depot. GWP stated that the depot can be connected to two feeders. This would help to provide some resiliency as the chances of both feeders failing at the same time is extremely unlikely. The City of Glendale has several options for providing BTM resiliency for their depot. The City of Glendale is currently planning to i nstall a 135 kW solar PV system on the roof of the bus maintenance bays/office space and the bus wash. This may be accompanied by a battery storage system. This system will be sized to power the buildings on the depot but not the buses. The depot also has room to host an additional 300 kW solar PV system. However, the resiliency needs of the fleet exceed the capacity of a 300 kW solar PV system. GWP has stated that a natural gas backup generator would probably be the most appropriate form of resiliency for the site. However, installing backup natural gas generators would be challenging due to space constraints on the site.

Because the City of Glendale already has property to house the bus fleet, the main barrier to deploying a BEB fleet would be the installation of charging infrastructure and working with GWP to carry out FTM utility improvements so there is enough utility distribution capacity to provide power to the depot. Due to space constraints at the City of Glendale's depot, it is not feasible to deploy hydrogen fueling infrastructure.

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91 Section III: City of Glendale
City of Glendale Overview
Glendale Beeline is a transit agency that serves Glendale, California , and the surrounding communities. The Beeline provides fixed-route service on all seven days of the week with reduced service on the weekends. Fixed -route service provides transit services to key locations in Glendale. Service also extends to the Burbank M etrolink Station, connecting with BurbankBus, and into La Crescenta/Montrose. Glendale Beeline also connects with the Pasadena Department of Transportation at the JPL.

Glendale Beeline currently operates 12 fixed routes:
• Route 1 runs from the Glendale Transportation Center to Stocker Square. The route operates on weekdays and weekends. • Route 3 is a bidirectional route with buses starting at the Glendale Galleria and JPL termini. This service only operates on weekdays. Routes 31, 32, 33, and 34 serve por tions of Route 3. Route 31 is a bidirectional route that operates only on Saturdays between the Glendale Galleria and La Crescenta. Route 33 operates between Montrose and JPL on weekdays only. Route 34 operates between Montrose and La Canada High School. T his service operates in the afternoon on school days.
• Route 4 operates between the Glendale Transportation Center and Glendale Galleria. The route is serviced on weekdays with reduced service on weekends.
• Route 5 operates between the Pacific Community Center and Hoover High School. This route operates on weekdays with reduced service on Saturdays.
• Route 6 operates between the Pacific Community Center and Glendale High School . This route operates on weekdays with reduced service on Saturdays.
• Route 7 operates between Riverside Rancho and Glendale Community College . This route operates on weekdays with reduced service on Saturdays.
• Route 8 operates between the Glendale Transportation Center and Glendale Community College. This route operates on weekdays with reduced service on Saturdays.
• Route 11 operates between the Glendale Transportation Center and Downtown Glendale. Route 11 operates during peak hours on weekdays from 6:00 am to 9:00 am and from 3:00 pm to 7:00 pm. • Route 12 operates between the Glendale Transportation Center and the Downtown Burbank Metrolink Station. This route also operates during peak hours from 6:00 am to 10:00 am and from 3:00 pm to 7:00 pm.

Section III
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92 Glendale Beeline will also operate a pilot program that will extend hours for some of t heir routes. The pilot will include Routes 1, 3, 4, 5, 6, 7, and 8. Under the pilot, these routes will continue to operate until 10:30 pm to 11:30 pm.

This feasibility study will examine two options for service:

• Scenario 1: Regular Service: Glendale Beeline operates the buses according to the regular service schedule. Under this scenario, most buses will complete their routes between 8 pm and 9 pm . • Scenario 2: Extended Service: Glendale Beeline will implement extended service for Routes 1, 3, 4, 5, 6, 7, and 8. Some of the buses on these routes will continue service until 10:30 pm to 11:30 pm on weekdays.

City of Glendale Fleet and Bus Depot
Glendale Beeline owns all the buses in the transit fleet. The fixed-route fleet consists of fifteen 35-foot transit buses and twenty- four 40-foot transit buses that were built by New Flyer and Gillig . In addition, five 35 -foot New Flyer buses are currently in production and will be deployed in 2020 . Eleven buses are due to be replaced in 2026, four in 2029 , ten in 2030, nine in 2033, and two in 2036 . The five buses currently in production are due to be replaced in 2037 . Glendale Dial-A-Ride's response fleet consists of four Dodge Grand Caravan vans, two 26 -foot ARBOC Spirit of Mobility buses, two Ford E350 r aised top vans, one Chevy Uplander van, and one 32 -foot El Dorado National bus. The operation of the buses and maintenance activities are contracted out to a transit services company . Currently, all the buses in Glendale Beeline's fleet have internal combu stion engines and are fueled with CNG; the Glendale Dial-A-Ride vehicles are all gasoline powered.

The fleet is housed at 1759 Gardena Ave., Glendale, C A, which is a property owned by the City of Glendale. The depot recently completed construction, and the transit services contractor is due to move in at the end of 2020 . The buses will be stored and maintained at this facility. The depot contains a building that houses office space and maintenance bays. In addition, the facility has a bus wash to clean th e buses. The buses are currently fueled at a CNG station that is on -site, next to the maintenance building. The buses will be parked outside in rows at the facility. Since the parking rows are space constrained, Glendale Beeline is planning to install overhead plug-in charging to reduce the physical footprint of the chargers.

Energy Analysis
To understand the energy needs of the fleet, CALSTART used its proprietary EBCM to model the amount of energy the buses would use over the course of a day. EBCM uses several transit agency-specific variables that are used to calculate energy needs, like the speed of the bus, ridership, and HVAC setpoints . CALSTART worked with the City of Glendale to obtain parameters for these variables. EBCM also considers variables tha t are specific to the route and the environment the bus will encounter while in operation, like grade and temperature (which affects HVAC load) . To obtain data about grade, CALSTART collected GIS data to determine the path that the buses travel on their ro ute. This data was used to obtain the elevation at multiple points along the bus’s route . HVAC load is also a major factor ; in extreme climates, HVAC can consume more energy than the propulsion system. As a result, HVAC load has a major impact on energy ne eds and the range of the bus . The Los Angeles region has mild winters and summers. However, the region is known to have occasional heat waves, with extremely hot temperatures. To ensure that the buses will be able to perform under worst -case conditions, EBCM was programmed to model 120 degrees Fahrenheit temperatures in the summer.

These results can be used to determine whether ZEBs can serve as a drop-in replacement for the current fleet and which routes are most suitable to deploy ZEBs . A BEB is considered to be a drop -in replacement if it can complete its shift with a SOC of at least 20 percent. Likewise, an FCEB is considered to be a drop -in replacement if it can complete its shift with 10 percent of its hydrogen capacity remaining.

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93 Dial-A-Ride Fleet
The City of Glendale's dial-a-ride fleet provides dial-a-ride service to seniors and people with disabilities. To estimate the energy needs for the dial-a-ride fleet, CALSTART hosted a bus demonstration. During this demonstration, the City of Glendale provided a manifest with a list of locations that a dial-a-ride vehicle would drive to on a typical service day. The City of Glendale provided a bus operator that drove to all of the locations on the manifest. During the demonstration, the bus drove 115 miles over seven and a half hours. The majority of the driving was on surface streets . However, these was some highway driving. The bus also made several trips from Glendale to La Crescenta, which involves significant elevation gain. The bus consumed approximately 81 kWh during this demonstration. Key variables from the demonstration are outlined in Table 3-1.

Table 3-1: The City of Glendale's Dial-A-Ride Fleet Bus Demonstration Parameters Variable Value
Number of People on the Bus 3
Average Driving Speed 20 miles per hour
Average Temperature 72° F

Table 3-2 displays the results from the bus demonstration and the amount of energy that one dial-a-ride bus will consume over the course of a day.

Table 3-2: City of Glendale's Daily Energy Needs Analysis for Dial-A-Ride Fleet Service Demonstration Metric OEM 4
Mileage 115
Energy (kWh) 81
Energy Economy (kWh per mile) 0.704

During this demonstration, the bus achieved an energy economy of 0.704 kWh per mile . Based on these results, the bus is a drop-in replacement because it used less than 80% of the battery's storage capacity. The City of Glendale has ten dial-a-ride vehicles. If all the buses go into service on a daily basis, the buses are estimated to consume approximately 1150 kWh per day.

While a battery electric shuttle bus can service as a drop-in replacement, a fuel cell shuttle bus could also theoretically be used.

Currently, only one fuel cell shuttle bus is available. Since this vehicle is not yet Altoona tested, there is no performance data for this bus. However, the bus can be installed with a 13 kg or 19 kg hydrogen tank. Assuming that 90 percent of the hydrogen in a tank is recoverable , this equates to an energy equivalence of 185 kWh and 259.51 kWh, respectively . On the assumption this bus's drivetrain has a similar efficiency as the Altoona tested small bus, CALSTART deems that the fuel cell shuttle bus will likely be a drop-in replacement for the current buses . Each kg of hydrogen has 33.333 kWh of energy . However, the efficiency of the fuel cell is 50 percent, meaning that 16.667 kWh is ava ilable to the drivetrain. Based on this assumption, each bus is estimated to use a maximum of approximately 7 kg of hydrogen per day. If all ten buses are in operation, this equates to 70 kg of hydrogen per day for the entire dial-a-ride fleet.

Fixed-Route Fleet
Glendale Beeline’s fixed-route fleet provides service to Routes 1, 3, 4, 5, 6, 7, 8, 11, 12, 33, and 34 . CALSTART analyzed two scenarios for Glendale Beeline . In Scenario 1, Glendale Beeline continues to provide service to their routes according t o the existing regular schedule. In Scenario 2, Glendale Beeline provides extended evening service to routes 1, 3, 4, 5, 6, 7, and 8 . To estimate the energy needs for the fixed -route fleet, EBCM was used to estimate the amount of energy that the buses will Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-107
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94 consume on these routes. CALSTART worked with Glendale Beeline to calibrate the assumptions for those variables . The assumptions used in EBCM are outlined in Table 3-3.

Table 3-3: Glendale Beeline Fixed-Route Fleet EBCM Parameters Variable Value
Average Number of People on the Bus During Service 13
Average Driving Speed 10 miles per hour
Heating HVAC Setpoint 72°F
Cooling HVAC Setpoint 68°F

CALSTART also obtained data that is specific to each route. Glendale Beeline provided timetables for all routes to model the exact time schedule and duty cycle for each individual bus.

Scenario 1: Regular Service - Weekdays
Using EBCM, CALSTART estimated the energy needs of each individual bus based on Scenario 1 , which assumes that all of Glendale Beeline’s routes are operated according to the regular schedule . Under this scenario, transit service ends at approximately 8 pm on weekdays.

Figure 3-1 displays the operating schedule for the buses and the ir routes for weekdays under Scenario 1, and Figure 3-2 shows the operating schedule for the buses and the routes that they will be deployed on weekends (please note that weekend service for both Scenario 1 and Scenario 2 are the same). The blue color indicates the intervals during which the bus is in operation, while the white unshaded squares are when the bus is not in operation and thus able to charge. Each square represents the half hour after its labeled time.

Figure 3-1: Glendale Beeline Scenario 1 Weekday Operations Schedule

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95 Figure 3-2: Glendale Beeline Weekend Operations Schedule

Table 3-4 displays the estimated energy needs for Glendale Beeline under Scenario 1 , and Table 3-5 displays the estimated energy needs for weekend Glendale Beeline service. In these tables, some buses cannot serve as a drop -in replacement for a CNG bus . A drop -in replacement is defined as a run that completes its route w ith a SOC of less than 20 percent. Runs that complete their route with a SOC of 10 percent or more have been highlighted in yellow . While these buses are not a drop -in replacement with technology in 2021, it is likely that, with improvements in battery technology over time , these buses could become a drop-in replacement. Buses that return to the depot with less than 10 percent SOC have been highlighted in orange.

Orange denotes that it is uncertain whether these buses will become a drop -in replacement in the future.

Table 3-4: Glendale Beeline Energy Analysis for Scenario 1 Weekday Regular Service Route Run Laps OEM 1 (kWh) OEM 2 (kWh) OEM 3 (kWh)
1 1111 17 257.95 265.30 266.87
1 1112 17 257.95 265.30 266.87
1 1113 17 257.95 265.30 266.87
1 1114 17 257.95 265.30 266.87
1 1115 11 196.93 252.46 253.94
3 3191 8 401.71 416.30 429.21
3 3192 8 401.71 416.30 429.21
3 3193 7 401.71 416.30 429.21
33 33111 15 355.89 398.34 395.83
34 34111 3 90.76 93.43 100.53
3 32111 13 346.87 458.06 472.59
4 4191 11 228.70 233.96 235.37
4 4192 12 249.45 255.19 256.73
4 4193 11 228.70 233.96 235.37
4 4194 11 228.70 233.96 235.37
4 4195 12 228.70 233.96 235.37
4 4116 11 228.70 233.96 235.37
5 5111 17 229.21 235.76 237.30
5 5112 18 241.57 248.50 250.30
5 5131 2 26.61 28.46 27.55
6 6111 17 246.57 253.86 256.04
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96 Route Run Laps OEM 1 (kWh) OEM 2 (kWh) OEM 3 (kWh)
6 6112 16 233.23 240.09 242.00
7 7111 8 241.45 248.91 250.20
7 7192 7 276.68 285.22 286.68
7 7193 7 275.65 284.19 285.68
7 07134/5/6 3 100.31 103.49 104.06
8 8113 13 255.90 264.00 273.26
8 8191 12 277.11 285.89 295.92
8 8192 12 255.90 264.00 273.26
11 11111 6 96.95 102.14 104.76
11 11112 6 96.95 102.14 104.76
11 11131 5 134.20 121.08 142.01
11 11132 5 134.20 121.08 142.01
12 12113 6 147.08 150.50 151.07
12 12111 5 119.96 122.80 123.28
12 12112 4 92.28 94.56 94.94
Total 8102.14 8494.05 8656.66

Table 3-5: Glendale Beeline Energy Analysis Weekend Service Route Run Laps OEM 1 (kWh) OEM 2 (kWh) OEM 3 (kWh)
1 1291 11 228.52 235.00 256.56
1 1292 10 192.74 197.93 203.52
1 1213 10 166.11 170.43 170.51
1 1294 10 242.06 266.98 268.55
1 1215 10 166.11 170.43 170.51
31 31291 7 257.36 267.60 259.56
31 31292 6 238.61 247.92 240.61
31 31213 6 174.32 180.82 175.72
4 4291 8 268.37 274.60 276.26
4 4292 7 268.37 274.60 276.26
4 4293 7 200.83 200.83 225.31
5 5291 13 299.68 303.87 305.85
6 6211 17 172.56 177.28 178.69
6 6292 16 275.20 283.27 285.70
7 7291 6 341.90 352.57 354.40
7 7292 5 341.90 352.57 354.40
8 8291 8 204.94 211.02 214.96
8 8292 8 297.52 306.98 314.78
Total 4337.10 4474.70 4532.15

An FCEB is considered a drop-in replacement if it can complete its shift with 10 percent of its hydrogen capacity remaining. The useable hydrogen tank capacity of each OEM was calculated. Each kg of hydrogen has 33.333 kWh of energy . However, the Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-110
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Table 3-6: Hydrogen Fuel Analysis for FCEBs
OEM KWh Equivalent
OEM 6 562.51
OEM 7 750.02

Based on these figures, both FCEB OEMs can serve as a drop -in replacement because their energy capacity exceeds energy demand for each shift. It is estimated that transit FCEBs will consume approximately 510 kg of hydrogen per weekday and each bus would consume an average of 14.2 kg of hydrogen per day . During weekend service, the buses are estimated to consume about 270 kg of hydrogen per day, with the average bus consuming about 14.9 kg of hydrogen per day.

Scenario 2: Extended Service - Weekdays
Using EBCM, CALSTART estimated the energy needs of each individual bus based on Scenario 2, which assumes that Routes 1, 3, 4, 5, 6, 7, and 8 operate on an extended service schedule. Under this scenario, transit service ends at approximately 10:30 pm on weekdays.

Figure 3 -3 displays the operating schedule for the buses and the routes that they will be deployed on for weekday s under Scenario 2, and Table 3-7 displays the energy analysis for Glendale Beeline's Fixed-Route Fleet under Scenario 2. The legends for these graphics are the same as those under Scenario 1.

Figure 3-3: Glendale Beeline Scenario 2 Weekday Operations Schedule

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98 Table 3-7: Glendale Beeline Energy Analysis for Scenario 2 Weekday Extended Service Route Run Laps OEM 1 (kWh) OEM 2 (kWh) OEM 3 (kWh)
1 01191 21 306.55 265.30 266.87
1 01112 17 257.95 265.30 266.87
1 01193 21 306.55 315.64 317.58
1 01114 17 257.95 265.30 266.87
1 01115 11 196.93 252.46 253.94
3 03191 10 483.16 501.16 517.53
3 03192 10 441.66 457.83 472.59
3 03193 9 441.66 457.83 472.59
33 33111 15 355.89 398.34 395.83
34 34111 3 90.76 93.43 100.53
3 32111 13 346.87 458.06 472.59
4 04191 16 316.99 324.65 326.70
4 04192 12 249.45 255.19 256.73
4 04193 15 301.25 308.44 310.35
4 04194 11 228.70 233.96 235.37
4 04195 15 301.25 308.44 310.35
4 04116 11 228.70 233.96 235.37
5 05111 17 229.21 235.76 237.30
5 05192 24 309.26 318.49 320.66
5 05131 2 26.61 28.46 27.55
6 06191 24 334.18 344.48 346.19
6 06112 16 233.23 240.09 242.00
7 07111 10 332.39 343.05 344.89
7 07192 7 276.68 285.22 286.68
7 07193 10 332.39 343.05 344.89
7 07134/5/6 3 100.31 103.49 104.06
8 08113 12 255.90 264.00 273.26
8 08191 18 364.68 376.84 354.84
8 08192 17 331.68 342.49 390.73
11 11111 6 96.95 102.14 104.76
11 11112 6 96.95 102.14 104.76
11 11131 5 134.20 121.08 142.01
11 11132 5 134.20 121.08 142.01
12 12113 6 147.08 150.50 151.07
12 12111 5 119.96 122.80 123.28
12 12112 4 92.28 94.56 94.94
Total 9,060.41 9,435.01 9,614.54

CALSTART estimates that during weekday service, the transit FCEBs will consume about 560 kg of hydrogen per day . Weekend service under Scenario 2 is the same as in Scenario 1 . As a result, weekend service will also consume approximately 270 kg of hydrogen per day.

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The City of Glendale plans to replace the current CNG fleet with BEBs as the bu ses reach the end of their useful life . Glendale currently owns 41 buses and manages three buses that are owned by La C añada Flintridge. Although the ICT Regulation does not obligate the City of Glendale to start purchasing buses until 2026, ZEBs will be d eployed ahead of this deadline . Glendale Beeline currently has nine buses that went into service in 2009 . These buses are reaching the end of their useful life and will be the first buses to be replaced . Glendale Beeline plans to purchase five ZEBs that will be deployed by the end of 2023 . Glendale Beeline also intends to purchase eight ZEBs and deploy them by the end of 2024 . In 2025, Glendale Beeline plans to acquire 10 ZEBs, followed by nine in 2028, and nine in 2032. Figure 3-4 illustrates the fl eet replacement plan. The buses from La Cañada Flintridge are not included in the plan.

Figure 3-4: Glendale Beeline Fleet Replacement Plan

It is important to note that Glendale Beeline’s current operations is based on Scenario 1. Under current operations, 36 buses are put into revenue service on weekdays . FCEBs will be able to serve as a drop -in replacement for the current fleet of CNG buses .

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because of the length of the route, especially for Route 3. Based on the route modeling results, Glendale Beeline would need to deploy up to 41 BEBs to provide service under Scenario 1 . Under Scenario 2, Glendale Beeline would need to depl oy up to 47 BEBs. It is important to note that there are variations in performance between the bus OEMs . As a result, the number of extra buses that would need to be purchased varies based on the bus OEM selected. This fleet replacement plan represents the worst- case scenario. These figures do not include any spare buses that would be purchased by Glendale Beeline.

BEBs can serve as drop -in replacements for most of the Beeline's routes , so the first deployment of BEBs should be on routes that can be electrified. CNG buses can then be replaced on a 1:1 basis with BEBs until there are no remaining routes where BEBs can serve as a drop-in replacement. Once this occurs, CNG buses would then be replaced on a 2:1 basis with BEBs.

This assessment does have some limitations and caveats . This assessment is based on 120 degrees Fahrenheit weather, which would represent the worst -case weather conditions the buses will operate in . As a result, the buses will operate in more favorable conditions the vast majority of the time, which would reduce the energy needs of the bus and improve their performance. In addition, this assessment is based on current BEB technology . It is very likely that there will be improvements in technology over time. In the fleet replacement plan, the buses that are highlighted in yellow and orange represent extra buses that must be deployed to meet the needs of the fleet. The buses highlighted in yellow indicates that the extra bus would not be needed if the buses were able to impro ve their battery storage capacity by 10 percent. As a result, if battery storage capacity were to increase by 10 percent, then the number of routes that could be served on a drop-in basis by BEBs would increase.

The success of the fleet replacement plan i s dependent on several factors . The main factor is the availability of infrastructure .

Site construction and charging installation must be complete before the buses are delivered in order to successfully roll out the fleet. In addition, upgrades to the uti lity distribution system need to be made to accommodate the power draw from bus charging and should be finished before deploying buses. This topic will be discussed in further detail in Utility Infrastructure on page 102.

The City of Glendale has the option to purchase either BEBs or FCEBs . There are multiple factors to consider when selecting a technology, including the capability of the technology, capital costs and total cost of ownership, and infrastructure viability .

Based on the energy analysis, FCEBs are able to serve as a drop-in replacement for CNG buses, whereas BEBs are not. However, this is only one of several factors that need to be considered when making this decision. The rest of this chapter will be devoted to exploring these factors. CALSTART ultimately recommends that the City of Glendale transitions to a fully BEB fleet.

Utility Analysis
GWP Overview
Glendale Beeline is served by GWP, which is a municipal utility that serves the City of Glendale . GWP is owned by the City of Glendale and is also a member of the Southern California Public Power Authority ( SCPPA). GWP manages multiple assets including fourteen substations, 503 miles of distribution lines, and 14,768 utility poles . In FY2019-20, GWP provided a total of 1,540,033 MWH with a system peak power demand of 288 MW. GWP uses a variety of resources to provide power to Glendale.

GWP owns the Grayson Power Plant, which is a local natural gas power plant located in the City of Glendale used produce electricity. This power plan t produced 119,213 MWH during FY2019 -20 (GWP, 2020). The Grayson Power Plant is undergoing several upgrades to modernize the facility.

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Figure 3-5: GWP Electric Utility Operating Statistics (GWP, 2020)

GWP also import s power. GWP obtains power from several power plants that they jointly own through SCPPA or that are remotely owned . The power from these sites is transported through the transmission system to GWP . GWP also obtains electricity through purchased power contracts and market purchases. The vast majority of GWP’s power does not originate from local sources.

GWP is also obtaining power from renewable sources and aims to obtain 100 percent of its power from clean sources . GWP owns a 12.5 percent share of the Eland 1 Solar and Storage Center in Kern County. GWP also receives power from the Whitegrass and Star Peak Geothermal projects and owns a 4.166 percent share of the Intermountain Power Plant in Utah . GWP also uses local solar and battery stor age to provide power . The City of Glendale also recently signed an agreement to deploy solar and storage at multiple municipal facilities throughout the city.

Glendale Beeline and Glendale Dial-A-Ride Utility Costs When the City of Glendale transitions to BEBs, they will incur utility costs as the fleet electrifies . The City of Glendale will be purchasing power from GWP and would qualify for the PC-1-B tariff. The PC-1-B tariff is a TOU rate for large customers that have a power demand of greater than 500 k W. As a TOU tariff, PC -1-B has different rates for energy depending on the time of day .

The day is divided into the base period and the peak period . From July to October, or the High Season, the peak period occurs between 2 pm – 7:59 pm on weekdays . From November to June, or the Low Season, the peak period occurs between 12 pm – 8:59 pm. All other times are in the base period. In this analysis, the buses are assumed to charge only during base hours.

The PC-1-B tariff also has demand charges. Demand charges are assessed based on the maximum kW consumed over the course of a year . There is also a separate demand charge based on reactive power . This demand charge is assessed based on the maximum kVAR that occurs over the course of a year.

Based on the PC-1-B rates and the energy and power demand projected from EBCM, Table 3-8 shows the projected annual utility costs for Scenario 1, and Table 3-9 shows the projected annual utility rates for Scenario 2 . The buses from La Cañada Flintridge have been included in the energy analysis. These figures assume that the entire fleet has been converted to BEB.

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Table 3-8: City of Glendale Scenario 1 Utility Cost Projections

OEM 1 (150 kW) OEM 2 (150 kW) OEM 3 (150 kW)
Charge Unmanaged Sequential Unmanaged Sequential Unmanaged Sequential Bureaucracy
Charges
$8,213 $8,213 $8,213 $8,213 $8,213 $8,213
Energy
Charges (per
kWh)
$313,648 $313,648 $325,898 $325,898 $330,984 $330,984 Demand
Charges (per
kW)
$1,204,158 $416,202 $1,249,617 $446,508 $1,264,770 $446,508 Reactive
Power
Demand
Charges (per
kVAR)
$4,792 $1,821 $4,416 $1,586 $4,278 $1,586
Total $1,530,811 $739,884 $1,588,144 $782,205 $1,608,245 $787,291

Table 3-9: City of Glendale Scenario 2 Utility Cost Projections OEM 1 (150 kW) OEM 2 (150 kW) OEM 3 (150 kW)
Charge Unmanaged Sequential Unmanaged Sequential Unmanaged Sequential Bureaucracy
Charges
$8,213 $8,213 $8,213 $8,213 $8,213 $8,213
Energy
Charges (per
kWh)
$339,924 $339,924 $351,699 $351,699 $357,250 $357,250 Demand
Charges (per
kW)
$1,242,546 $515,202 $1,272,852 $446,508 $1,484,994 $567,732 Reactive
Power
Demand
Charges (per
kVAR)
$6,546 $1,800 $6,371 $2,193 $4,487 $1,006
Total $1,597,229 $865,139 $1,639,135 $808,613 $1,854,944 $934,201

These figures demonstrate that the use of managed charging greatly reduces the demand charges, which has a major impact on the total annual utility cost.

Utility Infrastructure
GWP will need to install additional utility infrastructure to serve a fully electric fleet . GWP is currently in the process of a city - wide modernization and upgrade of utility inf rastructure, which includes upgrading their current and aging 4 kV distribution system to a 12 kV distribution system. This upgrade will allow the power lines to carry more electricity to customers. The City of Glendale has set aside funding for these dist ribution system upgrades through the Glendale Capital Improvements Program .

GWP is also working on upgrading their substations from a 34 kV system to a 69 kV system . No funding has been devoted to substation upgrades yet. These upgrades are needed to meet rising power demand in the city.

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GWP stated that there are currently two feeders that serve the City of Glendale's depot. However, there is limited available power in these feeders . The amount of power in these feeders is not enough to power the entire fleet. At the time of writing, there is enough power to charge 21 buses at 75 kW, 15 buses at 100 kW, or 9 buses at 150 kW . If any additional loads are introduced to the feeders before the buses arrive, this capacity would be reduced. As a result, the distribution system will need to be upgraded to bring enough power to the yard to charge the entire fleet. It is important to note that Glendale Beeline plans to have more than 9 buses deployed by 2024 , so u tility upgrades will need to be conducted to c ontinue electrifying the fleet .

Lastly, the substations serving the City of Glendale's depot may need to be upgraded to a 69 kV system . While the Capital Improvements Program can help finance the upgrade to a 12 kV distribution system, it cannot be used to finance other items like substation upgrades to a 69 kV system or upgrades to the feeders. Since upgrading the substations is a part of GWP’s utility upgrade plans, GWP will cover the cost of the substation upgrades, as long as the upgrade occurs on their schedule. If the City of Glendale wants the substation upgrades to be expedited, then they would have to pay for at least a part of the upgrade . If this were to occur, GWP would aim to finance utility upgrades with LCFS credits earned from the charging in frastructure.

The City of Glendale will also need to install infrastructure on-site at their depot to manage the power that arrives . GWP stated that voltage from the distribution system will need to be stepped down so the chargers can use the power . GWP offer two options for stepping down the power. One option would be for GWP to provide power at secondary voltage, in which the voltage is stepped down by the utility with their transformer . This option would entail constructing utility transformers on-site. Since Glendale Beeline is space constrained, it would likely need a vault room with a transformer and switch gear . A vault room has a physical footprint of 8-ft by 10-ft or 8-ft by 15-ft. Since bus charging is a large load, the City of Glendale would likely need multiple vault rooms and multiple switchgear , resulting in a large physical footprint . The vault rooms must also be spaced apart for ventilation. In addition, GWP would be responsible for installing the vault rooms/transformers . GWP needs to obtain funding and approval for this, which can delay the project.

Alternatively, GWP can deliver power to the City of Glendale at primary voltage at 12 kV . Under this scenario, GWP would not provide a transformer . Instead, the City of Glendale would need to obtain its own transformer to step down the voltage and manage the power . By doing this, the City of Glendale would avoid the need for vault rooms/transformers and switchgear .

Instead, the City of Glendale could use one large transformer . GWP could help to determine where the transformer would go and can provide BTM conduit to bring the feeders to the transformer . However, the City of Glendale would be responsible for hiring a contractor to install the transformer . GWP provides primary service to ot her large customers like Glendale Community College and local hospitals.

To apply for electrical service, GWP will need to be provided with the specifications of the chargers that Glendale Beeline w ill use and single-line diagrams. GWP will also need to determine where the meters/switchgear will be located on-site.

Infrastructure Analysis
Charging Infrastructure
Glendale currently owns 41 transit buses and 10 dial-a-ride vehicles. In addition, Glendale Beeline currently houses three transit buses owned by La Canada. Glendale Beeline puts 36 buses into transit service on a typical weekday . If Glendale Beeline were to deploy a fleet of BEBs, route modeling results indicate that 41 BEBs would need to be deployed for weekday service under Scenario 1 and 47 BEBs would need to be deployed for weekday service under Scenario 2.

To deploy a BEB fleet, Glendale Beeline need s charging infrastructure . Deploying BEB chargers involves additional measures beyond installing the chargers . In addition to FTM utility infrastructure, electrification requires the deployment of BTM infrastructure (on the customer’s side of the meter) . BTM infrastructure carries the power from the utility transformer, where Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-117
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the utility delivers power to the depot, to the actual chargers. Upgrading BTM infrastructure entails installing appropriately sized transformers and switchgear . In addition, conduit through which the circuits can deliver power to the chargers is required .

Conduit is typically underground, and the depot must be trenched to install it.

Under the City of Glendale's current depot arrangement, the transit buses are parked in rows and the dial-a-ride vehicles are parked in the south corner of the yard . The depot was designed to park 60 transit buses in 10 parking lanes and the 10 dial-a- ride vehicles in regular parking spaces . However, since infrastructure has a large physical footprint, the depot only has enough room to park 42 buses. This design assumes that there will be one charging plug for each bus. Each charging plug will be attached to a charging cabinet, which includes the power electronics and controls the charging activity of each plug. Each charging cabinet will control three chargers and will be capable of conducting sequential charging. To fit the charging plugs and cabinets, a raised curb will be installed between each parking lane . The charging plugs and cabinets will sit on top of the raised curb . This design protects the charging equipment from being run over by buses and also provides space to install support beams for a solar canopy. This design allows for chargers to be installed next to the buses to facilitate plug -in charging . It can also allow for overhead plug-in charging if a gantry and/or solar canopy is installed. The installation of an overhead retractable reel would also be required to facilitate overhead charging.

To provide charging at their depot, the City of Glendale will need to:

• Decommission and remove the existing utility transformer (will require coordination with GWP) • Install a 3000 kVA utility transformer (will require coordination with GWP) • Install a main service entrance with disconnect
• Install an automatic transfer switch (if natural gas generators are used to provide resiliency) • Install three 1000 kW generators
• Decommission the existing 480/277 V, 1200 A switchboard • Install a 480/277V, 5000 A switchboard to replace the existing 480/277 V, 1200 A switchboard • Install a 480 V, 4000A switchboard
• Install a 225 kVA transformer (for dial-a-ride vehicles) • Install a 600 A, 120/208 V EV panel (for dial-a-ride vehicles) • Install a PV disconnect, AC combiner, and inverters (if solar panels are deployed)

More details about the required equipment can be found in the single-line diagram in Appendix L.

During the construction process, the City of Glendale will need to install conduit directly to the location where each of the chargers will be located. This strategy allows the City of Glendale to install the infrastructure without having to do multiple rounds of trenching. This will make the site “charger ready” and as the buses are deployed, additional chargers can be added by simply running circuitry through the conduit to the chargers. To achieve this, preplanning will need to be conducted to ident ify where each of the chargers will be located on the site.

It is important to note that the depot is space constrained . The current depot arrangement does not support the installation of charging infrastructure for dial-a-ride vehicles. The parking spaces for the dial-a-ride vehicles are located in an easement that gives the Southern California Regional Rail Authority the ability to travel through that space . The easement runs through the entire parking space (see Appendix L). This easement prevents the installation of charging infrastructure in places that the vehicles could access. Furthermore, there are no other feasible places to park the vehicles. The dial-a-ride vehicles, parking, and associated charging infrastructure would require a contiguous area of 9,832 square feet. There is no other location on the current depot that can support this without obstructing the flow of traffic.

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Hydrogen Infrastructure
Deploying an FCEB fleet is not feasible at the City of Glendale current depot. The main requirement for operating an FCEB fleet is obtaining hydrogen . If the City of Glendale were to roll out a fleet of FCEBs, it would consume a large amount of hydrogen .

Under Scenario 1, the fleet would consume approximately 3,720 kg of hydrogen per week, which equates to approximately 193,440 kg per year. Under Scenario 2, the City of Glendale would consume approximately 3,970 kg per week or approximately 206,440 kg per year. To operate the fleet, Glendale Beeline would need access to a hydrogen fueling station. This would be challenging ; the current yard is space constrained and there is no room to install a hydrogen fueling station on the depot. The City of Glendale would need to build a hydrogen station at another location or fuel at a retail fueling station. Both of these options are infeasible. The construction of a hydrogen station at a different location would require the acquisition of land and high construction costs . Furthermore, there are currently no heavy-duty retail fueling stations near the City of Glendale's depot. As a result, there is no viable way to provide hydrogen to the fleet.

Even if there were no space constraints, the use of hydrogen would be difficult. The City of Glendale would have several options for obtaining hydrogen for the fleet . The City of Glendale could produce hydrogen on -site via SMR or electrolysis .

Alternatively, the City of Glendale could opt to receive delivered gaseous or liquid hydrogen . Lastly, the City of Glendale could fuel at public fueling stations.

Several of these options can be eliminated immediately . Producing hydrogen on -site via electrolysis is not viable because the utility costs would be high. Producing one kg of hydrogen via electrolysis requires 55 kWh of energy. Furthermore, compressing the hydrogen so it can be dispensed at 350 bar consumes between 1.7 and 6.4 kWh per kg of hydrogen (Monterey Gardner, 2009). This analysis uses the average of this range, which is 4.1 kWh per kg. Based on these figures, the production of hydrogen via electrolysis would require 59.1 kWh per kg of hydrogen . Under Scenario 1, the City of Glendale would consume about 30,141 kWh per day to produce the hydrogen . Assuming the best -case scenario (that minimizes power demand) where the electrolyzer produces hydrogen 24 hours per day, power demand would be 1,256 kW. Under Scenario 2, the City of Glendale would consume approximately 33,096 kWh per day. Under the best-case scenario, this would entail power demand of 1,379 kW. The amount of energy required to produce this much hydrogen would exceed the amount of energy that the entire BEB fleet uses by a factor of four. In addition, there would still be high power demand for electrolysis. As a result, the resulting utility bills would be about $1,706,141 under Scenario 1 and $1,820,801 under Scenario 2, which is higher than a BEB fleet and makes this option financially infeasible . In addition, utility upgrades might be required to deliver this much power to the electrolyzer.

The use of delivered gaseous or liquid hydrogen is also financially infeasible. Hydrogen can be delivered in gaseous form .

However, gaseous hydrogen can only be delivered in limited quantities . Most trucks can only deliver approximately 250-280 kg of hydrogen . As a result, the City of Glend ale would need to receive multiple truck deliveries per day , which is likely not compatible with their operations. Liquid hydrogen is typically delivered in larger quantities, and most liquid hydrogen trucks can deliver up to 4,500 kg of hydrogen. When the City of Glendale's fleet is fully zero-emission, the fleet would consume enough fuel to justify the use of liquid hydrogen. The annual hydrogen fuel price is projected to be approximately $1,619,093 under Scenario 1 and $1,727,903 under Scenario 2 . This greatly exceeds the utility charges that the City of Glendale would pay for charging a BEB fleet.

Another option would be to use retail fueling . At the time of writing, there are no heavy -duty hydrogen stations currently in existence or that have be en planned in or near Glendale. However, there are some light -duty stations near Glendale. While the Glendale Dial-A-Ride fleet could theoretically fuel at a light-duty station, the price of retail hydrogen is currently high. At this point in time, the use of retail fueling is currently infeasible due to the lack of heavy-duty hydrogen fueling stations and the high price of hydrogen at light -duty stations. However, the market for retail hydrogen fueling is rapidly changing and the CEC has Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-119
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awarded grants to expand California’s retail hydrogen fueling market (CEC, 2020). As a result, the market for retail hydrogen fueling can change rapidly.

The most financially viable option available to the City of Glendale for fueling an FCEB fleet would be to use on-site SMR. On-site SMR is only economically viable at volumes of at least 200 kg per day . Although delivered ga seous hydrogen is not a viable method of fueling the entire fleet, it could be used temporarily until enough buses are deployed to consume 200 kg per day. To do this, the City of Glendale would need to build a hydrogen station . The station would be designed to accept hydrogen from a tube trailer. The City of Glendale would then schedule deliveries of hydrogen . Once the City of Glendale's demand reaches 200 kg per day, an on-site SMR can be deployed on-site. Based on the fleet replacement plan, if the City of Glendale chose to adopt FCEBs, they would be expected to reach a demand of 200 kg per day in 2024. When the on-site SMR is installed, the equipment used to accept delivered hydrogen can be left on -site. This will allow the City of Glendale to accept delivered hydrogen when the SMR is undergoing scheduled maintenance or there is an equipment fault . The City of Glendale is projected to pay approximately $1,268,966 per year for hydrogen under Scenario 1 and $1,354,246 per year for hydrogen under Scenario 2. This amount also exceeds the utility costs that would be associated with charging a BEB fleet.

It is important to note that , in addition to the cost of the fuel, there are capital expenditures associated with some of these options. In order to dispense the hydrogen, a hydrogen fueling station needs to be constructed. The City of Glendale would need to invest in a fueling station if it decided to obtain hydrogen via on-site electrolysis, delivered liquid hydrogen, or on -site SMR.

The City of Glendale could avoid this capital expense if it obtained hydrogen from retail fueling stations. Table 3-10 and Table 3- 11 display the capital expenditures a nd annual hydrogen fuel costs for each hydrogen pathway. There are additional costs associated with deploying on-site hydrogen production equipment, which are explored further in Appendix N.

Table 3-10: Hydrogen Cost Analysis – Scenario 1
Expense On-site Electrolysis Delivered Liquid
Hydrogen
Offsite Retail Fueling On-site SMR
Capital Expenditures $6,575,972 $2,467,776 $0 $4,814,959 Annual Cost
of Hydrogen Fuel
$ 1,706,141 $1,619,093 Offsite fueling not
currently available
$1,268,966

Table 3-11: Hydrogen Cost Analysis – Scenario 2
Expense On-site Electrolysis Delivered Liquid
Hydrogen
Offsite Retail Fueling On-site SMR
Capital Expenditures $6,575,972 $2,467,776 $0 $4,814,959 Annual Cost of
Hydrogen Fuel
$1,820,801 $1,727,903 Offsite fueling not
currently available
$1,354,246

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Resiliency
FTM Resiliency
GWP has stated that there are limited options for providing FTM resiliency for the City of Glendale's depot. The depot can be connected to two feeders, which would help to provide some resiliency. The chances of both feeders failing at the same time is extremely unlikely. However, it would be difficult to provide other forms of resiliency. While GWP does have a local power plant, this asset is used to power the grid as a whole. As a result, there is no guarantee that the City of Glendale's depot would be able to access that power plant as a FTM resiliency solution in the event of an outage .

Other utilities provide FTM resiliency options by deploying FTM batteries and energy assets so they can continue to provide power to their customers in the event of an outage. These utilities typically finance this resiliency through a special utility tariff.

Under this tariff, customers pay a higher rate for energy (per kWh) in exchange for res iliency. This strategy allows the transit agency to obtain resiliency while avoiding the capital expenses associated with deploying resiliency assets . GWP does not currently offer this model for obtaining resiliency . However, if the City of Glendale is interested in this resiliency model , they could initiate discussions with GWP to explore the possibility of establishing a special resiliency utility tariff.

BTM Resiliency
The City of Glendale has several options for providing BTM resiliency for their depot. The City of Glendale is currently planning to install a 135 kW solar PV system on the roof of the bus maintenance bays/office space and the bus wash . This may be accompanied by a battery storage system . This solar and storage system will be sized to provide resiliency for the bus maintenance bays and offices only . The City of Glendale is also considering installing solar panels over the bus lanes to provide additional power generation . GWP has engaged an engineering firm to explore the deployment of battery storage at multiple locations across the city . However, the City of Glendale's depot is not one of the locations that will be hosting battery storage through this program. As a result, the depot would need to independently obtain batteries.

GWP has stated that a natural gas backup generator would probably be the most appropriate form of resiliency for the site .

Since batteries have a large physical footprint, there are space constraints to how much battery storage can be placed on -site.

Furthermore, batteries are costly, which creates a financial constraint. GWP recommended that a natural gas backup generator be used as it is more economically feasible and can provide resiliency over a longer period than energy storage. Resiliency options for Scenario 1 and Scenario 2 are explored below.

Scenario 1
The City of Glendale has multiple options for providing resiliency for the fleet. The fleet would have a peak power demand of 2,570 k W and the buses would consume between approximately 8,100-8650 per day under Scenario 1 . Based on modeling results from NREL’s REopt Lite tool, resiliency for the entire fleet during a seven-day grid outage entirely using solar and storage would require a 3,624 kW PV solar array and an energy storage system with a power capacity of 2,400 kW and storage capacity of 15,890 kWh . On the assumption that the panels have an efficiency of 19 percent, a solar array with a surface area of approximately 19,073.7 square meters (4.7 acres) would be required to fully power the fleet during a seven-day outage.

The City of Glendale's depot does have the ability to host some solar assets . The City of Glendale is considering installing solar panels over the bus lanes to provide additional power generation . However, this area only has the c apacity to host a 300 kW solar array. This is a much smaller solar array than would be required to provide full resiliency to the fleet . Furthermore, most battery systems are packed in a 40-ft container and require a large amount of space. Since the site is already space constrained, there are limits on how much battery storage capacity can fit on the site . As a result, an on-site, BTM solar and storage system Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-121
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would not be a viable method to providing full resiliency for the fleet.

Alternatively, the City of Glendale could use generators. To provide full resiliency in the event of a grid outage, the City of Glendale would need three 1000 kW/1250 kVA generators. In theory, the City of Glendale can choose to use either a natural gas generator or a diesel generator. However, the City of Glendale already has a CNG fueling station on-site. In addition, natural gas generators produce fewer emissions. As a result, a natural gas generator would be the preferred resiliency option. A natural gas turbine would need access to a gas pipeline to obtain fuel . If the generator maintains access to fuel, it is capable of powering the fleet indefinitely. However, if the generator is permitted as a backup generator, its operations would be limited to 200 hours per year. It is theoretically possible that the generator could lose access to fuel if the natural gas network is disrupted during an emergency. However, disruptions to the natural gas network are rare, and a s imultaneous disruption to both the grid and the natural gas network is exceedingly rare. If the City of Glendale wanted to protect against this possibility, it would be advisable to install a 2,000 gallon CNG storage tank. The addition of the natural gas storage tank would provide one day of fuel in the event of a gas network disruption.

The addition of three 1000 kW/1250 kVA natural gas generators and the CNG storage tank would require 1,310 square feet. This figure includes the appropriate equipment clea rances. Under the current site layout, the City of Glendale's depot is space - constrained, and it would not be possible to add these assets without obstructing traffic through the depot. The City of Glendale could also consider scaling-down the resiliency assets to decrease the physical footprint. According to MDT modelling, two 1000 kW/1250 kVA generators could provide 87 percent of the required energy needs of the fleet during a grid outage and one 1000 kW/1250 kVA generator could provide 49 percent of the required energy needs of the fleet.

Scenario 2
Under Scenario 2, the fleet would have a peak power demand of 2,910 kVA and the buses would consume between approximately 9,000-9,550 kWh per day. Based on modeling results from NREL’s REopt Lite tool, resiliency for the entire fleet during a seven-day grid outage entirely using solar and storage would require a 3,273 kW PV solar array and an energy storage system with a power capacity of 2,698 kW and storage capacity of 25,591 kWh . On the assumpti on that the panels have an efficiency of 19 percent, a solar array with a surface area of approximately 17,226.3 (4.25 acres) square meters would be required to fully power the fleet during a seven-day outage. Under Scenario 2, the City of Glendale would have the same solar production capability and space constraints for energy storage as in Scenario 1 . As a result, a solar and storage system would not be a feasible option for providing full resiliency to the fleet.

Under Scenario 2, the City of Glendale could also use natural gas turbines . Under Scenario 2, the City of Glendale would also need three 1000 kW/1250 kVA natural gas generators. However, the City of Glendale would face the same space constraints as in Scenario 1 . The City of Glendale could also consider scaling down their resiliency assets to decrease the physical footprint.

According to MDT modelling, two 1000 kW/1250 kVA natural gas generators can provide 80 percent of the required energy needs of the fleet during a grid outage and a single 1000 kW/1250 kVA natural gas generator can provide 46 percent of the fleet’s energy needs.

Financial Analysis and Cost Estimates
CALSTART developed cost estimates for the City of Glendale's transition to both a BEB fleet and a n FCEB fleet. This financial analysis assumes that the buses are deployed according to the Fleet Replacement Plan (see page 99).

Table 3-12 outlines the expected cost of purchasing and operating a CNG fleet . This scenario represents a continuation of the status quo between 2021 until 2040. Under this scenario, the City of Glendale is projected to spend $45,671,981 between 2021 Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-122
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and 2040. A discount rate of 4 percent per year (discounted to 2021 dollars) amounts to a net present value of $ 32,420,044.

Since the City of Glendale already has access to CNG fueling infrastructure, this figure includes the capital expenditures associated with purchasing buses. In addition, this analysis takes into account operational costs like maintenance costs, midlife bus repairs, and the cost of fuel. This analysis does not include the cost of labor associated with operating the buses.

Table 3-12: CNG Bus Financial Analysis

Table 3-13 and Table 3-14 outline the expected cost of purchasing and operating a BEB fleet under Scenario 1 and Scenario 2, respectively. The cost of transitioning to a fully BEB fleet is outlined below:
• The cost of transitioning to a fully BEB fleet under Scenario 1 is projected to cost $66,709,857 between 2021 and 2040.

A discount rate of 4 percent per year (discounted to 2021 dollars) amounts to a net present value of $ 48,495,006. • The cost of transitioning to a fully BEB fleet under Scenario 2 is projected to cost $76,804,452 between 2021 and 2040.

A discount rate of 4 percent per year (discounted to 2021 dollars) amounts to a net present value of $54,606,233.

Since there are limited options for providing on-site resiliency, the cost of resiliency assets was not included. It is important to Year
Transit Buses
Shuttle Buses
Bus Maintenance
Midlife Repairs
CNG Fuel Costs
Total Cost
Net Present Value (2021 dollars)
2021
2022
2023 $3,250,000 $44,446 $235,000 $64,103 $3,593,549 $3,194,652 2024 $5,200,000 $115,561 $376,000 $166,667 $5,858,227 $5,007,637 2025 $6,500,000 $204,453 $470,000 $294,872 $7,469,325 $6,139,241 2026 $360,000 $223,206 $25,200 $320,513 $928,919 $734,138 2027 $223,206 $320,513 $543,719 $413,182
2028 $223,206 $320,513 $543,719 $397,290
2029 $5,850,000 $540,000 $331,340 $460,800 $474,359 $7,656,499 $5,379,355 2030 $900,000 $378,223 $63,000 $538,462 $1,879,685 $1,269,848 2031 $378,223 $538,462 $916,685 $595,461
2032 $5,850,000 $458,226 $423,000 $653,846 $7,385,073 $4,612,695 2033 $458,226 $653,846 $1,112,073 $667,882
2034 $458,226 $653,846 $1,112,073 $642,194
2035 $458,226 $653,846 $1,112,073 $617,494
2036 $458,226 $653,846 $1,112,073 $593,745
2037 $458,226 $653,846 $1,112,073 $570,908
2038 $458,226 $653,846 $1,112,073 $548,950
2039 $458,226 $653,846 $1,112,073 $527,837
2040 $458,226 $653,846 $1,112,073 $507,535
Total $26,650,000 $1,800,000 $6,245,904 $2,053,000 $8,923,077 $45,671,981 $32,420,044 Capital Expenditures Operational Expenditures Total Costs Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-123
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note that these figures assume that the only utility upgrade the City of Glendale will need to pay for is a utility transformer .

These figures do not include any additional utility infrastructure upgrade costs.

Table 3-13: BEB Fleet Financial Analysis (Scenario 1)

Year
Transit Buses
Shuttle Buses
Driver and Maintenance Training
Charging Infrastructure
Utility Infrastructure
Bus Maintenance
Midlife Repairs
Infrastructure Maintenance
Utility Costs (fueling costs)
Total Cost
Net Present Value (2021 dollars)
2021
2022 $6,000,000 $21,000 $6,021,000 $5,566,753
2023 $4,000,990 $78,750 $74,006 $271,630 $21,000 $75,470 $4,521,846 $4,019,905 2024 $6,401,584 $1,000,000 $192,416 $434,608 $21,000 $196,222 $8,245,830 $7,048,570 2025 $8,001,980 $340,429 $543,260 $21,000 $347,162 $9,253,830 $7,605,974 2026 $560,000 $376,305 $42,000 $21,000 $377,350 $1,376,654 $1,087,990 2027 $376,305 $21,000 $377,350 $774,654 $588,674
2028 $376,305 $21,000 $377,350 $774,654 $566,032
2029 $7,201,782 $840,000 $563,330 $551,934 $21,000 $558,478 $9,736,523 $6,840,752 2030 $1,400,000 $653,019 $105,000 $21,000 $633,947 $2,812,967 $1,900,340 2031 $653,019 $21,000 $633,947 $1,307,967 $849,630
2032 $7,201,782 $786,231 $488,934 $21,000 $769,793 $9,267,740 $5,788,603 2033 $786,231 $21,000 $769,793 $1,577,024 $947,120
2034 $786,231 $21,000 $769,793 $1,577,024 $910,692
2035 $786,231 $21,000 $769,793 $1,577,024 $875,665
2036 $786,231 $21,000 $769,793 $1,577,024 $841,986
2037 $786,231 $21,000 $769,793 $1,577,024 $809,602
2038 $786,231 $21,000 $769,793 $1,577,024 $778,463
2039 $786,231 $21,000 $769,793 $1,577,024 $748,522
2040 $786,231 $21,000 $769,793 $1,577,024 $719,733
Total $32,808,118 $2,800,000 $78,750 $6,000,000 $1,000,000 $10,681,208 $2,437,366 $399,000 $10,505,415 $66,709,857 $48,495,006 Capital Expenditures Operational Expenditures Total Costs Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-124
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Table 3-14: BEB Fleet Financial Analysis (Scenario 2)

If the City of Glendale were to transition to an FCEB fleet, it will need to select a hydrogen fueling pathway. The hydrogen fueling pathway impacts the costs associated with deploying an FCEB fleet. Table 3-15 provides an overview of the costs associated with each hydrogen production pathway.

Table 3-15: Hydrogen Production Pathways Financial Analysis Hydrogen Production Pathway Cost Estimates Net Present Value (2021 dollars) Scenario 1
On-site SMR $88,713,803 $63,160,164
On-site Electrolysis $96,440,961 $68,383,941
Delivered Gaseous Hydrogen $89,628,514 $62,845,754
Delivered Liquid Hydrogen $93,132,243 $65,094,561
Scenario 2
On-site SMR $91,564,649 $64,887,964
On-site Electrolysis $99,618,886 $70,308,438
Delivered Gaseous Hydrogen $92,678,702 $64,693,267
Delivered Liquid Hydrogen $94,617,179 $65,989,489

The most cost-effective method for obtaining hydrogen under both Scenario 1 and Scenario 2 would be through on-site SMR.

The cost of transitioning to a fully FCEB fleet using on-site SMR hydrogen production is detailed in Table 3-16 (Scenario 1) and Table 3-17 (Scenario 2). The costs of transitioning to a full FCEB fleet are outlined below:
• Transitioning to a fully FCEB fleet under Scenario 1 is projected to cost $88,713,803 between 2021 and 2040. A discount rate of 4 percent per year (discounted to 2021 dollars) amounts to a net present value of $63,160,164. • Transitioning to a full FCEB fleet under Scenario 2 is projected to cost $91,564,649 between 2021 and 2040. A discount Year
Transit Buses
Shuttle Buses
Driver and Maintenance Training
Charging Infrastructure
Utility Infrastructure
Bus Maintenance
Midlife Repairs
Infrastructure Maintenance
Utility Costs (fueling costs)
Total Cost
Net Present Value (2021 dollars)
2021
2022 $6,000,000 $24,000 $6,024,000 $5,569,527
2023 $4,000,990 $78,750 $92,758 $271,630 $24,000 $76,256 $4,544,384 $4,039,940 2024 $6,401,584 $1,000,000 $241,170 $434,608 $24,000 $198,265 $8,299,627 $7,094,556 2025 $8,001,980 $426,685 $543,260 $24,000 $350,777 $9,346,702 $7,682,308 2026 $560,000 $461,978 $42,000 $24,000 $381,280 $1,469,258 $1,161,176 2027 $461,978 $24,000 $381,280 $867,258 $659,045
2028 $461,978 $24,000 $381,280 $867,258 $633,697
2029 $7,201,782 $840,000 $681,882 $551,934 $24,000 $564,294 $9,863,892 $6,930,240 2030 $1,400,000 $770,116 $105,000 $24,000 $640,550 $2,939,666 $1,985,933 2031 $770,116 $24,000 $640,550 $1,434,666 $931,931
2032 $12,803,168 $1,048,389 $869,216 $24,000 $869,318 $15,614,090 $9,752,515 2033 $1,048,389 $24,000 $869,318 $1,941,706 $1,166,138
2034 $1,048,389 $24,000 $869,318 $1,941,706 $1,121,287
2035 $1,048,389 $24,000 $869,318 $1,941,706 $1,078,161
2036 $1,048,389 $24,000 $869,318 $1,941,706 $1,036,693
2037 $1,048,389 $24,000 $869,318 $1,941,706 $996,820
2038 $1,048,389 $24,000 $869,318 $1,941,706 $958,481
2039 $1,048,389 $24,000 $869,318 $1,941,706 $921,616
2040 $1,048,389 $24,000 $869,318 $1,941,706 $886,169
Total $38,409,504 $2,800,000 $78,750 $6,000,000 $1,000,000 $13,804,159 $2,817,648 $456,000 $11,438,390 $76,804,452 $54,606,233 Capital Expenditures Operational Expenditures Total Costs Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-125
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rate of 4 percent per year (discounted to 2021 dollars) amounts to a net present value of $ 64,887,964.

These figures include the capital expenditures associated with building a hydrogen fueling station (see Appendix N for the methodology for estimating the hydrogen fueling station costs) and the cost of the buses. In addition, this analysis takes in to account operational costs like maintenance costs, the cost of hydrogen, and the cost of maintaining hydrogen infrastructure.

This analysis does not include the cost of labor associated with operating the buses.

Table 3-16: FCEB Fleet Financial Analysis (Scenario 1)

Year
Transit Buses
Shuttle Buses
Driver and Maintenance Training
Hydrogen Infrastructure
Bus Maintenance
Midlife Repairs
Infrastructure O&M
Hydrogen Costs
Total Cost
Net Present Value (2021 dollars)
2021
2022 $4,814,959 $4,814,959 $4,451,700
2023 $5,524,947 $153,325 $94,190 $168,400 $190,564 $124,408 $6,255,834 $5,561,414 2024 $8,839,915 $244,893 $269,440 $190,564 $323,462 $9,868,274 $8,435,442 2025 $11,049,894 $433,273 $336,800 $190,564 $572,279 $12,582,809 $10,342,152 2026 $510,000 $478,933 $190,564 $622,042 $1,801,540 $1,423,783 2027 $478,933 $190,564 $622,042 $1,291,540 $981,464
2028 $478,933 $190,564 $622,042 $1,291,540 $943,715
2029 $9,944,904 $765,000 $716,965 $366,120 $190,564 $920,623 $12,904,176 $9,066,303 2030 $1,275,000 $831,115 $105,000 $190,564 $1,045,031 $3,446,711 $2,328,474 2031 $831,115 $190,564 $1,045,031 $2,066,711 $1,342,496 2032 $9,944,904 $1,000,657 $303,120 $190,564 $1,268,966 $12,708,212 $7,937,511 2033 $1,000,657 $190,564 $1,268,966 $2,460,187 $1,477,525 2034 $1,000,657 $190,564 $1,268,966 $2,460,187 $1,420,697 2035 $1,000,657 $190,564 $1,268,966 $2,460,187 $1,366,055 2036 $1,000,657 $190,564 $1,268,966 $2,460,187 $1,313,514 2037 $1,000,657 $190,564 $1,268,966 $2,460,187 $1,262,994 2038 $1,000,657 $190,564 $1,268,966 $2,460,187 $1,214,418 2039 $1,000,657 $190,564 $1,268,966 $2,460,187 $1,167,709 2040 $1,000,657 $190,564 $1,268,966 $2,460,187 $1,122,797 Total $45,304,563 $2,550,000 $153,325 $4,814,959 $13,594,265 $1,548,880 $3,430,152 $17,317,659 $88,713,803 $63,160,164 Capital Expenditures Operational Expenditures Total Costs Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-126
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Table 3-17: FCEB Fleet Financial Analysis (Scenario 2)

Financing Strategy
The City of Glendale will need a financing strategy to transition to a zero -emission fleet. Because the City of Glendale already has a depot, it can focus its attention on procuring funding for charging infrastructure, utility upgrades, and ZEBs.

The financial resources for charging infrastructure can be obtained by winning a grant that funds capital expenditures , like Caltrans’s TIRCP. A TIRCP grant can also be used to finance utility and BTM infrastructure upgrades . The U.S. Department of Transportation also provides federal grants like the Bus & Bus Facilities grant , which is used to fund the purchase of buses and related equipment and the construction of bus facilities. Additionally, GWP offers a charger rebate of up to $6,000 for commercial customers (GWP, n.d.).

Once the infrastructure upgrades have been completed, the operational costs are expected to be covered by the City of Glendale's operating budget. However, the purchase of the buses also needs to be financed. Bus purchases can be financed with various grant and funding sources (see Financing Strategies & Resources on page 40). Most of these grant and finance programs will only partially finance the cost o f the buses. To maximize funding for bus purchases , it would be advisable to apply for and stack multiple grants. It is unlikely that grants will pay for the entire transition to a zero-emission fleet. The main objective when pursuing grants should be to cover the incremental cost of zero emission buses, or the difference between the cost of a ZEB and a CNG bus. Using grants to cover the incremental cost of the buses would allow the City of Glendale to purchase ZEBs with the funding sources they normally employ to purchase buses.

The City of Glendale should also consider which finance methods would be most appropriate for their agency. If Glendale Beeline Year
Transit Buses
Shuttle Buses
Driver and Maintenance Training
Hydrogen Infrastructure
Bus Maintenance
Midlife Repairs
Infrastructure O&M
Hydrogen Costs
Total Cost
Net Present Value (2021 dollars)
2021
2022 $4,814,959 $4,814,959 $4,451,700
2023 $5,524,947 $153,325 $108,860 $168,400 $190,564 $132,769 $6,278,865 $5,581,888 2024 $8,839,915 $283,035 $269,440 $190,564 $345,200 $9,928,154 $8,486,627 2025 $11,049,894 $500,754 $336,800 $190,564 $610,739 $12,688,750 $10,429,228 2026 $510,000 $546,414 $190,564 $663,846 $1,910,824 $1,510,152 2027 $546,414 $190,564 $663,846 $1,400,824 $1,064,511
2028 $546,414 $190,564 $663,846 $1,400,824 $1,023,569
2029 $9,944,904 $765,000 $810,852 $366,120 $190,564 $982,492 $13,059,932 $9,175,735 2030 $1,275,000 $925,002 $105,000 $190,564 $1,115,262 $3,610,828 $2,439,346 2031 $925,002 $190,564 $1,115,262 $2,230,828 $1,449,103 2032 $9,944,904 $1,120,949 $303,120 $190,564 $1,354,246 $12,913,784 $8,065,911 2033 $1,120,949 $190,564 $1,354,246 $2,665,760 $1,600,986 2034 $1,120,949 $190,564 $1,354,246 $2,665,760 $1,539,410 2035 $1,120,949 $190,564 $1,354,246 $2,665,760 $1,480,202 2036 $1,120,949 $190,564 $1,354,246 $2,665,760 $1,423,271 2037 $1,120,949 $190,564 $1,354,246 $2,665,760 $1,368,530 2038 $1,120,949 $190,564 $1,354,246 $2,665,760 $1,315,894 2039 $1,120,949 $190,564 $1,354,246 $2,665,760 $1,265,283 2040 $1,120,949 $190,564 $1,354,246 $2,665,760 $1,216,618 Total $45,304,563 $2,550,000 $153,325 $4,814,959 $15,281,290 $1,548,880 $3,430,152 $18,481,480 $91,564,649 $64,887,964 Capital Expenditures Operational Expenditures Total Costs Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-127
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is amenable to capital expenditures, then traditional financing models would be the appropriate. However, if the City of Glendale prefers to avoid or reduce capital expenditures, then financing models like bus/battery leasing or IAAS would be more appropriate. These financing models would effectively allow the City of Glendale to pay for capital expen ditures from their operational budget.

There are additional financial considerations that need to be considered when deploying resiliency assets. If the City of Glendale deploys resiliency assets, the most likely candidates would be solar and storage or natural gas turbines . However, there are unique financial considerations that need to be evaluated when selecting an asset . One major drawback of natural gas turbines is that they are subject to air quality regulations and would likely be permitted as backu p generators. As a result, they can only be used in the event of a grid outage, meaning they would be idle for the vast majority of the time. This is problematic because generators have a high capital cost meaning that the levelized cost of energy (per kWh ) produced by the generator would be very high. Unlike generators, there are no restrictions on when solar and storage can be used . A solar and storage system is eligible for net metering and excess energy produced can be exported to the grid and sold back to the utility. Furthermore, the storage system can be used to “peak shave" to provide energy during times of high power and reduce overall power draw from the grid. This is useful because it can reduce demand charges, which are a major component of utility costs. Furthermore, a solar and storage system could potentially generate revenue by providing ancillary grid services . Since solar and storage can provide a transit agency with savings and/or revenue, the levelized cost of energy would be much lower than for a natural gas generator.

In addition, solar and storage is better situated to take advantage of the ITC . The ITC provides a tax credit for the investment in particular DERs. Solar is eligible for a 10 percent ITC. The ITC for solar is permanent. Generators are only eligible for a 10 percent ITC if they are used in a combined heat and power system (a system where waste heat from the generator is captured and used to provide heating for a building or industrial process). Since air quality regulations limit backup generator use to 200 hours per year, they would likely not be considered a combined heat and power system . Furthermore, the ITC for combined heat and power systems expires at the end of 2023.

If the City of Glendale opts to deploy ITC-eligible DERs, acquiring them through a third-party ownership model, like IAAS, would likely be the best option . The entity that owns the DER is eligible for the ITC . As a public agency, the City of Glendale is a tax - exempt entity and would not be able to benefit from the ITC. However, if the City of Glendale were to finance the DERs through an IAAS model where a third-party owns the asset, the infrastructure provider could realize the benefits of the ITC and pass the benefits on to Glendale Beeline in the form of lower PPA rates. If the City of Glendale opts to deploy DERs that are eligible for the ITC, the use of an IAAS financing model should be seriously considered.

LCFS Credits
Once the buses are deployed, LCFS credits can also be used to finance capita l expenditures and operational expenses . LCFS credits can be used in many ways. If Glendale Beeline owns the charging equipment, they would earn the LCFS credits and could redeem them for cash. However, there are other ways that the LCFS credits can be used. Transit agencies can transfer their LCFS credits to their utility for a certain period of time to fund utility upgrades . LCFS credits can also benefit a transit agency even if they do not own the charging equipment or if they opt to use an IAAS financin g model. If this were to occur, the infrastructure provider would receive the LCFS credits . The infrastructure provider could then pass on the benefits of the LCFS credits to the transit agency in the form of lower PPA rates.

The estimated value of the LCFS credits generated by Glendale Beeline's Fixed-Route Fleet is shown in Table 3-18 and Table 3-

19. These projections provide the nominal revenue generated by LCFS credits . They also provide a net present value which assumes a 4 percent discount rate (discounted to 2021 dollars) and a LCFS credit value of $200.

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Table 3-18: Glendale Beeline's Fixed-Route Fleet LCFS Credit Value – Scenario 1 (displacing diesel fuel)

Year Revenue Net Present Value Levelized cost per kWh
2021 $0 $0 $0.00
2022 $0 $0 $0.00
2023 $81,941 $75,759 $0.23
2024 $209,232 $186,007 $0.22
2025 $363,488 $310,711 $0.21
2026 $356,742 $293,216 $0.20
2027 $350,049 $276,649 $0.19
2028 $343,303 $260,882 $0.18
2029 $468,328 $342,202 $0.17
2030 $458,942 $322,446 $0.16
2031 $458,942 $310,045 $0.15
2032 $588,019 $381,966 $0.14
2033 $588,019 $367,275 $0.14
2034 $588,019 $353,149 $0.13
2035 $588,019 $339,566 $0.13
2036 $588,019 $326,506 $0.12
2037 $588,019 $313,948 $0.12
2038 $588,019 $301,873 $0.11
2039 $588,019 $290,263 $0.11
2040 $588,019 $279,099 $0.11
Total $8,383,137 $5,331,562

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Table 3-19: Glendale Beeline's Fixed-Route Fleet LCFS Credit Value – Scenario 2 (displacing diesel fuel)

Year Revenue Net Present Value Levelized cost per kWh
2021 $0 $0 $0.00
2022 $0 $0 $0.00
2023 $89,110 $82,387 $0.23
2024 $227,539 $202,281 $0.22
2025 $395,290 $337,896 $0.21
2026 $387,954 $318,870 $0.20
2027 $380,676 $300,853 $0.19
2028 $373,339 $283,707 $0.18
2029 $509,302 $372,142 $0.17
2030 $499,095 $350,658 $0.16
2031 $499,095 $337,171 $0.15
2032 $639,466 $415,385 $0.14
2033 $639,466 $399,408 $0.14
2034 $639,466 $384,047 $0.13
2035 $639,466 $369,276 $0.13
2036 $639,466 $355,073 $0.12
2037 $639,466 $341,416 $0.12
2038 $639,466 $328,285 $0.11
2039 $639,466 $315,658 $0.11
2040 $639,466 $303,518 $0.11
Total $9,116,592 $5,798,029

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Table 3-20 displays the estimated value of the LCFS credits generated by the dial-a-ride Fleet.

Table 3-20: Glendale Dial-A-Ride Fleet LCFS Credit Value (displacing gasoline) Year LCFS Revenue
Present value of
Revenue Levelized Cost per kWh
2021 $0 $0 $0.00
2022 $0 $0 $0.00
2023 $0 $0 $0.00
2024 $0 $0 $0.00
2025 $0 $0 $0.00
2026 $27,117 $22,288 $0.21
2027 $26,634 $21,049 $0.20
2028 $26,147 $19,870 $0.19
2029 $64,161 $45,079 $0.18
2030 $125,889 $88,447 $0.16
2031 $125,889 $85,046 $0.16
2032 $125,889 $81,775 $0.15
2033 $125,889 $78,630 $0.15
2034 $125,889 $75,606 $0.14
2035 $125,889 $72,698 $0.14
2036 $125,889 $69,902 $0.13
2037 $125,889 $67,213 $0.13
2038 $125,889 $64,628 $0.12
2039 $125,889 $62,142 $0.12
2040 $125,889 $59,752 $0.11
Total $1,528,838 $914,124

The number of LCFS credits awarded depends on the quantity of GHG emissions avoided by using BEBs. As the grid becomes less carbon intensive, the number of LCFS credits awarded is likely to increase and the value of the LCFS credits earned has the potential to increase. The methodology used to make these calculations can be found in Appendix N.

Implementation Plan
The City of Glendale has many options for deploying a ZEB fleet . The most practical option would be to deploy a BEB fleet . As discussed on page 108, a fully BEB fleet would be a cheaper option than deploying a fully FCEB fleet . In addition, due to space constraints at Glendale Beeline’s depot, it is not feasible to deploy hydrogen fueling infrastructure.

Because the City of Glendale already has prope rty to house the bus fleet, the main barrier s to deploying a BEB fleet are the installation of charging infrastructure and FTM utility improvements so there is enough utility distribution capacity to prov ide power to the depot . The first step towards insta lling the upgrades is to apply for electrical service . Once an application for electrical service has been submitted, GWP can conduct studies and provide a finalized list of required utility upgrades. GWP has stated that they will be updating their grid to 12 kV. They will also likely need to upgrade a substation . Based on GWP’s current load and grid capacity, there is enough power for nine bus charger plugs charging at 150 kW . Based on the fleet replacement plan, the City of Glendale will start deploying b uses in 2023 and will have more than nine buses by 2024 . As a result, utility Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-131
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upgrades will need to take place to allow the entire fleet to electrify.

FTM utility upgrades can have a lengthy project timeline . The City of Glendale will likely need a substa tion upgrade. A typical construction timeline for a substation upgrade is 18 months to three years. In addition, more loads are being added to GWP’s grid, which can reduce the amount of grid distribution capacity available . Due to the lengthy timeline asso ciated with utility upgrades, it would be advisable for the City of Glendale to submit an application for electrical service as soon as possible to start this process. To apply for electrical service, the City of Glendale will need to provide GWP with the specifications of the chargers that will be used and single -line diagrams . GWP will also need to provide a final site plan and determine where the meters/switchgear will be located on-site.

Construction will also need to occur for BTM on the depot . Typically, the utility will deliver power to the site at a utility transformer. The transformer is then connected to switchgear, which then connects to the chargers . Most BTM construction involves installing switchgear, the chargers, and the wires that connect t he chargers to the switchgear. Generally, the wires are installed underground, which requires trenching. The City of Glendale has the option of using GWP’s transformer and accepting secondary voltage or accepting power at primary voltage and using their own transformer to step-down the voltage. However, if the City of Glendale opts to use GWP’s transformer, they might need to have a vault room installed. This is problematic because a vault room has a physical footprint, and the site is already space constrained. To reduce the space required, the City of Glendale should consider installing their own transformer and accepting primary voltage from GWP . Regardless of which option the City of Glendale uses, a new transformer and switchgear will likely be needed. In addition, trenching will need to be carried out to install conduit, circuits, and chargers.

It is important to note that the buses are scheduled to be phased in over time and they will not all arrive during the same year .

With this in mind , it is important to plan ahead . It does not make sense to install all the chargers at once and expose unused chargers to wear and tear . Instead, the chargers that are going to be used should be installed . The rest of the site should be constructed so that it is “EV Ready.” This entails installing electrical panels as well as conduit and wires running to the locations where the chargers will eventually be installed . Constructing an EV Ready site is important because it allows chargers to be installed quickly as they are needed . In addition, it minimizes the cost of construction by ensuring the site only needs to be trenched once. Site construction can take up to two years, especially if environmental permits are required. The City of Glendale should also install any resiliency or backup power during initial construction.

It is vital that both the utility upgrades and the BTM construction occur before the buses arrive . If this is not completed, then the buses will not be able to charge . In addition, during the construction process, the site can be unusable, especially during trenching. The City of Glendale should coordinate with GWP to ensure that the utility upgrades are coordinated with the delivery of the buses. To this end, it would be advisable to submit th e application for electrical service as soon as possible . If the buses arrive before the utility upgrades and/or site construction is completed, the City of Glendale can use temporary chargers until the permanent charging infrastructure is ready for use . As the buses are phased in over time, the City of Glendale can hire electricians to install additional chargers.

The City of Glendale, however, does face a couple barriers to deploying the fleet. The main challenge is space constraint. There is limited space available for installing charging infrastructure. The site was designed to house up to 60 transit buses and 10 dial- a-ride vehicles. However, since the charging infrastructure has a large physical footprint , there is only room to house 42 bus es on the yard. This will constrain the City of Glendale's ability to expand the size of the fleet beyond its current size . In addition, there is an easement that prevents construction on certain places within the yard . This easement runs through the area where the dial-a-ride vehicles are parked and effectively precludes the installation of charging infrastructure for these vehicles . There is no other place on the yard where these vehicles can be parked , effectively preventing these vehicles from transitioning to zero-emission. Furthermore, space constraints will limit the City of Glendale ability to deploy resiliency assets.

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Section IV: BurbankBus Executive Summary
BurbankBus is a transit agency that serves Burbank, California, and provides both demand response service and fixed -route service. Bus route modeling showed the current daily transit energy needs can be served with a 1:1 drop -in replacement using either BEBs or FCEBs for the fixed-route and dial-a-ride service. Based on the current cost of ZE buses, fueling Infrastructure, and BurbankBus's needs, BEBs are recommended.

Transitioning to a zero-emission fleet will be more expensive than operating a CNG bus fleet . The cost of operating a CNG bus fleet is projected to cost $16,847,735 between 2021 and 2040 . When this amount is discounted at a rate of 4 percent per year (discounted to 2021 dollars), this amounts to a net present value of $9,714,672 . The cost of transitioning to a fully BEB fleet is projected to cost $ 30,229,373 between 2021 and 2040. When this amount is discounted at a rate of 4 percent per year (discounted to 2021 dollars), this amounts to a net present value of $19,626,301. This figure includes the capital expenditures associated with utility upgrades, purchasing and installing chargers, and the cost of the buses. In addition, this analysis t akes into account operational costs like maintenance costs, the cost of electricity from the utility, and the cost of maintaining charging infrastructure. This analysis does not include the cost of acquiring land or labor associated with operating the buses.

The cost of transitioning to an FCEB fleet depends on the pathway used to obtain hydrogen . The most cost-effective hydrogen pathway would be to receive delivered gaseous hydrogen. Based on this pathway, t he cost of transitioning to a fully FCEB fleet is projected to cost $ 31,712,460 between 2021 and 2040. When this amount is discounted at a rate of 4 percent per year (discounted to 2021 dollars), this amounts to a net present value of $ 18,706,071. This figure includes the capital expenditures associated with building a hydrogen fueling station and the cost of the buses. In addition, this analysis takes into account operational costs like maintenance costs, the cost of hydrogen, and the cost of maintaining hydrogen infrastructure. This analysis does not include the cost of acquiring land or labor associated with operating the buses.

The Senior and Disabled Fleet is expected to make their first ZE vehicle purchase in 2027. This will lead to a full ZE fleet conversion by 2032. For the fixed-route fleet, BurbankBus should plan to begin purchasing ZE buses in 2027, leading to 100 percent ZE fleet by 2039.

BurbankBus is looking at 2 options for housing their bus fleet. Option A has the Senior and Disabled Fleet and fixed-route fleet housed separately, and Option B has the Senior and Disabled Fleet and fixed -route fleet housed at the same location. If BurbankBus chooses to adopt BEBs for their fleet, the following table has a breakdown of the annual utility costs per option and charging logic.

Section IV: Executive Summary
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Annual Utility Costs
($/year)
Option A Unmanaged $721,807
Sequential $318,783
Option B Unmanaged $720,383
Sequential $337,055

A ZEB fleet will need resiliency so the fleet can continue to operate in the event of a grid outage . BWP currently does not offer FTM resiliency options. For BTM resiliency, BurbankBus could use a solar and storage system or a natural gas generator . If BurbankBus used a solar and storage system, they would require a 1000 kW PV solar array and a battery that can provide 982kW of power and has storage capacity of 9070 kWh . Because BurbankBus is currently searching for a new facility to house the bus fleet, It Is not known what solar potential would be available at the site . BurbankBus could also employ natural gas generators; they would need to be 1 500 kW rated at minimum . Based on the findings of these report, the minimum site area required to implement Option B is 62,265 square feet.

BurbankBus needs to secure new land to house their buses and facilities. Until a depot is identified, it is difficult to plan for the fleet. Fleet planning is site -specific. As a result, it is not possible to make decisions about key factors until a site i s identified.

Without a depot, it is impossible to determine what type of utility upgrades will need to be performed and what resiliency options will be viable. These are crucial questions that a transit agency needs to address early in the planning process. Identifying a site will allow BurbankBus to gain clarity on these key questions and begin planning for a zero-emission fleet.

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Section IV: BurbankBus
BurbankBus Overview
BurbankBus is a transit agency that serves Burbank, California , and provides both demand response service and fixed -route service. BurbankBus’s demand response service provides curb -to-curb transit services for senior and disabled residents of Burbank. Prior to the COVID-19 pandemic, demand response service was provided all seven days of the week. On Mondays and Tuesdays, the service area for demand response extends into parts of North Hollywood and Glendale for medical-related travel.

Since the COVID -19 pandemic started, Sunday demand response serv ice has been suspended . Fixed-route service provides transit services to key locations in Burbank including the Media District, Downtown Burbank, the Bob Hope Airport, and the Burbank Metrolink Station . Fixed-route service also connects with Metro’s North Hollywood Red Line Station and Metro’s Universal City Station. Fixed-route service is provided Monday through Friday.

BurbankBus Senior and Disabled Transit demand response service provides curb -to-curb service for seniors and disabled residents of Burbank. Eligible riders can call BurbankBus dispatch to schedule their ride and are then picked up at their location and transported to their destination . Prior to the COVID-19 pandemic, BurbankBus demand response service was typically provided by six to seven shuttle buses. However, due to reduced Senior & Disabled ridership during the pandemic, one to three shuttle buses are currently being used for weekday service and only bus is being used for Saturday operations. This service is provided every day except on Sundays, with the service expanded on Mondays and Tuesdays to include parts of North Hollywood and Glendale for medical -related travel. Since this is a dial-a-ride service, the buses do not adhere to a fixed route . The buses normally drive between 50 and 100 miles per day and are driven on residential streets, arterial streets, and freeways. The buses also typically drive in hilly areas with high grade.

BurbankBus operates three fixed routes on weekdays . The Green Route serves North Hollywood and the Media District. The Green Route operates during peak hours in the morning from 6 am to 10 am and in the afternoon from 3 pm to 7 pm . This schedule means that there is a gap between morning and afternoon service. The Orange Route serves North Hollywood and the Bob Hope Airport. This route operates continuously between 5:30 am and 11 pm , and there are no gaps in service hours . The Pink Route is a bidirectional route that runs between termini at Universal City Walk and the Downtown Burbank Metrolink Station. This route operates continuously between 6 am and 11 pm . However, due to the COVID -19 pandemic, changes have

Section IV
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been made to the service hours for fixed -route service. The Green Route currently operates in the morning from 6 am to 9 am and in the afternoon fro m 3 pm to 6:30 pm . The Orange Route currently operates from 6 am to 8 pm . Lastly, the Pink Route currently operates from 6 am to 7:45 pm.

BurbankBus Fleet and Bus Depots
BurbankBus owns all the buses that are used in transit operation. The operations and maintenance for BurbankBus’s fixed-route fleet are contracted to a transit services company . The Senior and Disabled fleet is operated and maintained by BurbankBus’s staff. Currently, the fixed -route buses in the fleet have internal combusti on engines and are fueled with CNG. The Senior and Disabled fleet is fueled with gasoline and consists of nine Allstar 25-foot shuttle buses. Four of these buses are due to be replaced in 2020, two are due to be replaced in 2029, and the remaining three ar e due to be replaced in 2032 . Prior to the COVID -19 pandemic, s ix to seven buses were put into service each day to provide demand response service , with each bus driv ing approximately 50 to 100 miles per day . Due to reduced Senior & Disabled ridership duri ng the pandemic, one to three shuttle buses are being used for weekday service and only bus is being used for Saturday operations.

The Senior and Disabled fleet is currently housed at 124 South Lake Street, Burbank, California, which is a property owned b y the City of Burbank. This property houses Burbank Public Works facilities and the City of Burbank’s municipal fleet . This facility has a gasoline fueling station to fuel municipal vehicles. In addition, it houses a hydrogen station that will be managed by a third- party fueling company. This hydrogen station can fill vehicles at 700 bar and is designed to fill light -duty vehicles. The site also houses maintenance bays for the vehicles, ventilation equipment, and a server/data room . This depot is space cons trained because it also houses the City of Burbank’s municipal fleet . This problem is expected to worsen as the municipal fleet grows .

As a result, it is not possible to store additional buses at this depot.

The fixed-route fleet consists of seventeen transit buses, including one President 30-foot bus, ten Bluebird L4RE 35-foot buses, and six additional ElDorado Axess 35-foot buses. Six buses are due to be replaced in 2023, five are due to be replaced in 2027, and six are due to be replaced in 2035. Fourteen of the buses are put into transit service each day. The fixed-route fleet is housed at a facility located at 1242 Los Angeles Street, Glendale, CA 91204 . This property is not owned by the City of Burbank and is leased. BurbankBus contracts its maintenance to a transit services contractor. As of June 2021, the fixed-route fleet is maintained and repaired at a depot that is located at 1242 Los Angeles Street, Glendale, California 91204. BurbankBus aims to acquire a new depot to permanently house the fixed-route fleet.

There are multiple options for housing a zero -emission fleet on a bus depot . This study examines two options for housing BurbankBus’s fleet. The details of these options are included below:

• Option A: Status Quo - Option A represents the status quo where the Senior and Disabled Fleet is housed at the 124 South Lake Street depot and the Fixed-route Fleet is housed at a separate depot. • Option B: Combined Depot - Option B represents a scenario where both the Senior and Disabled Fleet and the Fixed- route Fleet are housed at a combined depot. Under this scenario, the Senior and Disabled Fleet would be removed from the 124 South Lake Street depot and stored with the Fixed-route Fleet at a new depot.

The analysis provided in this study a ssumes that BurbankBus will resume pre-pandemic operation levels after the COVID -19 pandemic ends.

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These variables include factors like the speed of the bus, ridership, and HVAC setpoints . CALSTART worked with BurbankBus to obtain parameters for these variables. EBCM also considers variables that are specific to the route and the environment the bus will encounter while in operation . This includes factors like grade and temperature (which affects HVAC load) . To obtain data about grade, CALSTART collected GIS data to determine the path that the buses travel on their route . This data was used to obtain the elevation at multiple points along the bus’s route. HVAC load is also a major factor because in extreme climates, HVAC can consume more energy than the propulsion system. As a result, HVAC load has a major impact on energy needs and the range of the bus. The Los Angeles region has mild winters and summers. However, the region is known to have occasional heat waves, with extremely hot temperatures. To ensure that the buses will be able to perform under worst case conditions, EBCM was programmed to model 120°F temperatures in the summer.

These results can be used to determine whether ZEBs can serve as a drop-in replacement for the current fleet and which routes are most suitable to deploy ZEBs on. A BEB is considered a drop-in replacement if it can complete its shift with a SOC of at least 20 percent. Likewise, an FCEB is considered a drop -in replacement if it can complete its shift with 10 percent of its hydrogen capacity remaining.

Senior and Disabled Fleet
BurbankBus’s Senior and Disabled Fleet provides dial-a-ride service. To estimate the energy needs for the fleet, CALSTART hosted a bus demonstration. During this demonstration, a manifest was provided to the OEM's driver. The manifest provided a list of locations that a Senior and Disabled Fleet bus would drive to on a typical service day. During the demonstration, the bus deployed the wheelchair lift to ensure that energy consumption from this equipment was included in the energy consumption figures. To represent a worst -case scenario, the wheelchair lift was used on twenty -five stops during the demonstration. During the demonstration, the bus drove 99 miles over seven hours. The bus consumed approximately 61 kWh during this demonstration.

Key variables from the demonstration are outlined below in Table 4-1.

Table 4-1: BurbankBus Senior and Disabled Fleet Demonstration Parameters Variable Value
Number of people on the bus 2
Average Driving Speed 15 miles per hour
Average Temperature 66° F

Based on the results of the demonstration, the energy needs estimates for an electric shuttle bus are provided in Table 4-2.

Table 4-2: BurbankBus Daily Energy Needs Analysis for Senior and Disabled Fleet Service

Demonstration Metric OEM 4
Mileage 99
Energy (kWh) 61
Energy Economy (kWh per mile) 0.616

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These figures estimate the amount of energy that one Senior and Disabled Fleet bus will consume over the course of a typical service day. Based on these results, the buses are considered a drop -in replacement for BurbankBus’s duty cycle because it requires less than 80% of the battery's storage capacity to complete service. BurbankBus deploys seven buses per day for Senior and Disabled Fleet service . Consequently, the daily energy needs for the Senior and Disabled Fleet Is estimated to be approximately 427 kWh per day. It is important to note that the majority of the driving during the demonstration took place on surface streets, with a few trips on the freeway. As a result, this estimate should be valid for service that is primarily driven at low speeds.

While a battery electric shuttle bus can service as a drop-in replacement, a fuel cell shuttle bus could also theoretically be used.

Currently, the only FCEB available on the market is not yet Altoona tested and there is no performance data for this bus .

However, the bus can be installed with a 13 kg or 19 kg hydrogen tank . On the assumption that 90 percent of the hydrogen in a tank is recoverable, this equates to an energy equivalence of 185 kWh and 259.51 kWh, respectively. On the assumption that an FC shuttle bus achieves the same energy performance as the modeled electric shuttle buses, CALSTART deems that a FC shuttle bus will be a drop-in replacement for the current buses. Each kg of hydrogen has 33.333 kWh of energy. However, the efficiency of the fuel cell is 50 percent, meaning 16.667 kWh is available to the drivetrain. If the buses use approximately 427 kWh per day, each bus will use a maximum of approximately 3.65 kg of hydrogen per day. If seven buses are put into service on a daily basis, this equates to about 26 kg of hydrogen per day for the entire Senior and Disabled Fleet.

Fixed-route Fleet
BurbankBus’s fixed -route fleet provides service to the Green Route, the Orange Route, and the Pink Route . To estimate the energy needs for the fixed-route fleet, EBCM was used to estimate the amount of energy that the buses will consume on these routes. CALSTART worked with BurbankBus to calibrate the assumptions for those variables. The assumptions used in EBCM are outlined below in Table 4-3.

Table 4-3: BurbankBus Fixed-Route Fleet EBCM Parameters Variable Value
Average Number of People on the Bus During Service 14
Average Driving Speed 14.5 miles per hour
Heating HVAC Setpoint 72° F
Cooling HVAC Setpoint 68° F

CALSTART also obtained data that is specific to each route. BurbankBus provided information about the different shifts that the buses were driven on and the time of day they operate . BurbankBus provided information for 17 shifts . The schedule for these shifts is detailed below in Figure 4-1.

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Figure 4-1: BurbankBus Fixed-Route Fleet Bus Shifts

Based on the schedule and the provided inputs, the model produced the following daily energy needs estimates for each shift , as seen in Table 4-4.

Table 4-4: BurbankBus Daily Energy Needs Analysis for Fixed-Route Service Route Shift Laps OEM 1 (kWh) OEM 2 (kWh) OEM 3 (kWh)
Orange 1 10 174.14 185.04 190.44
Orange 2 9 165.75 176.33 176.33
Orange 3 8 144.4 153.81 149.94
Orange 4 9 150.23 160.81 160.81
Pink 5 8 147.83 223.21 246.02
Pink 6 9 162.53 247.35 273.01
Orange 7 8 173.29 151.68 149.05
Orange 8 8 142.83 152.24 152.24
Pink 9 3 54.32 82.59 91.14
Pink 10 8 150.13 225.52 248.33
Pink 11 8 150.13 225.52 248.33
Pink 12 6 113.94 170.49 187.59
Pink 13 10 261.24 279.48 308.01
Green 14 10 107.58 118.88 127.38
Green 15 9 84.83 107.26 114.91
Green 16 9 84.83 107.26 114.91
Green 17 10 107.58 118.88 127.38
Total 2,375.58 2,886.25 3,065.82

The route modelling results estimate the total amount of energy that the buses will consume over the course of a day. Based on this criterion, BEBs are drop-in replacements for all seventeen of BurbankBus’s shifts. This is true for all OEMs.

An FCEB is considered a drop-in replacement if it can complete its shift with 10 percent of its hydrogen capacity remaining. The useable hydrogen tank capacity of each OEM was calculated . Each kg of hydrogen has 33.333 kWh of energy . However, the efficiency of the fuel cell is 50 percent, meaning that 16.667 kWh is available to the drivetrain. Based on these assumptions, the energy capacity of these FCEBs is detailed below in Table 4-5.

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Table 4-5: Hydrogen Fuel Analysis for FCEBs
OEM KWh Equivalent
OEM 6 562.51
OEM 7 750.02

Based on these figures, both FCEB OEMs can serve as a drop -in replacement for all 17 shifts because their energy capacity exceeds energy demand for each shift . It is estimated that FCEBs will consume approximately 175 kg of hydrogen per day, and each bus would consume 10.3 kg of hydrogen per day.

Fleet Replacement Plan
BurbankBus will replace th eir current fleet with ZEBs over multiple years . BurbankBus plans to replace the current fleet as the buses reach the end of their useful life. CALSTART developed a fleet replacement plan based on BurbankBus’s fleet replacement schedule. This fleet replacement plan assumes that BurbankBus will begin purchasing buses after 2026, when the ICT regulation comes into effect for small transit agencies . The plan also assumes minimum compliance with the ICT regulation’s purchasing requirements. The fleet replacement plan is displayed below in Figure 4-2.

Figure 4-2: BurbankBus Fleet Replacement Plan

According to this plan, the first zero -emission shuttle buses in the Senior and Disabled Fleet will be purchased in 202 7, and the first purchases of ZEBs in the Fixed -route Fleet will begin in 202 7. The Senior and Disabled Fleet will be fully zero -emission by 2032, and the Fixed-route Fleet will be fully zero-emission by 2039.

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BurbankBus has the option to purchase either BEBs or FCEBs . There are mul tiple factors that need to be considered when selecting a technology. The main factors that need to be considered are the capability of the technology, capital costs and total cost of ownership, and infrastructure viability. Based on the energy analysis, both technologies are capable of serving as a drop- in replacement for a CNG bus and are capable of handling BurbankBus’s duty cycle . The capital expenditures and total cost of ownership are also a major factor. BEBs have a lower capital cost and are projected to have a lower total cost of ownership (see Financial Analysis and Cost Estimate on page 142 for more details). Lastly, due to space constraints, installing hydrogen fueling infrastructure would be challenging (see Charging and Hydrogen Fueling Infrastructure Analysis on page 1344 for more details).

As a result, CALSTART recommends that BurbankBus transitions their fleets to BEBs.

BEB Charging Cost Analysis
BWP Overview
BurbankBus is served by BWP, which is a municipal utility that serves the City of Burbank . BWP is owned by the City of Burbank and is also a member of the Southern California Public Power Authority (SCPPA) . BWP uses a variety of assets to provide power for the city. BWP operates the Magnolia Power Plant, which is the largest power plant in Burbank . The Magnolia Power Plant is a natural gas and biomethane-fired plant that typically operates between 160 and 242 MW but can reach 310 MW during times of high demand . BWP has a 31 percent share in the Magnolia Power Plant, which also provides power to Anaheim, Glendale, Pasadena, Colton, and Cerritos. BWP also operates the Lake One Power Plant . This power plant is a natural gas -fired plant that can produce up to 45 MW. The Lake One Plant is typically used to produce reserve power that can be deployed in the event of a grid outage or when demand is exceedingly high. The Lake One Plant can ramp up to full power within ten minutes. Lastly, the City of Burbank, Public Works Department owns and operates Burbank Landfill Site Number 3 . BWP has an agreement with the Public Works Department to use the gas from the landfill to produce power . BWP has installed a microturbine at this facili ty.

This microturbine has an output of 800 kW.

BWP also obtains imported power from several power plants that they jointly own through SCPPA or that are remotely owned .

Some of these plants are located in other states like Utah, Nevada, Arizona, Oregon, a nd Washington. The power from these sites is transported through the transmission system to BWP . BWP also obtains electricity through purchased power contracts and market purchases.

In FY2020, BWP had retail sales of 1,019,000,000 kWh, and peak demand was 283 MW. For FY2020, renewable energy resources made up 33.6 percent of BWP’s electric supply . BWP’s renewable energy comes from solar PV, landfill gas, wind, geothermal, and hydroelectric power (BWP, 2020).

BurbankBus Electric Utility Tariffs
When BurbankBus transitions to BEBs, they will incur utility costs as the fleet electrifies . BurbankBus will be purchasing power from BWP. BWP’s tariffs consist of bureaucracy charges, demand charges, and energy charges . Demand charges are assessed based on the maximum kW that is consumed over the course of a year. This demand charge is assessed based on the maximum kW that occurs over the course of a year . Energy charges are assessed on all kWh consumed . BWP’s applicable tariffs are TOU rates. Under a TOU rate, the day is divided into three periods: on-peak, mid-peak, and off-peak. From June through October, or the Summer Season, on-peak hours occur from 4-7 pm on weekdays and mid-peak hours occur from 8 am – 4 pm and 7 pm – 11 pm on weekdays. All other times are off-peak hours. From November through May, or the Winter Season, mid-peak hours occur from 8 am – 11 pm on weekdays. All other times are off-peak hours. During the Winter Season, there are no on -peak hours. In this analysis, the buses are assumed to charge only overnight during off-peak hours.

BWP has multiple tariffs . The tariff that BurbankBus will be eligible for is dependent on the power demand of the facility . The Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-141
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most likely tariff rates that BurbankBus will be levied are the Schedule L tariff and the Schedule XL tariff . To qualify for the Schedule L tariff, power demand must be under 1,000 kVA. The Schedule XL tariff applies to facilities whose power demand exceeds 1,000 kVA.

Option A Utility Analysis
Under the current plan, BurbankBus’s fleet will be located across two yards. The Senior and Disabled Fleet will be located at 124 South Lake and th e fixed-route fleet will be located at a separate yard . The 124 South Lake Street depot is a large facility with high power demand. As a result, the Senior and Disabled Fleet will be eligible for BWP’s Schedule XL rate . Since the Senior and Disabled Fleet will be charging with non-networked chargers, it is assumed that managed charging is not an option for the shuttle buses and that charging for the Senior and Disabled Fleet will be unmanaged . Since this facility has a utility transformer, BurbankBus would receive power at secondary voltage.

Under Option A, the Fixed -route Fleet will be at a different yard . The Fixed-route Fleet could potentially be eligible for two different tariffs . If BurbankBus uses unmanaged charging, the power demand will exceed 1,00 0 kW, which would require BurbankBus to purchase power according to the Schedule XL TOU rate. However, if BurbankBus opts to use sequential charging, it is expected that the power demand from the fleet would be under 1,000 kW, which would qualify for the Schedule L TOU rate.

Based on the Schedule XL tariff and the energy and projected power demand, Table 4-6 shows the projected annual utility costs for operating the Senior and Disabled Fleet . These figures assume that the entire fleet has been converted t o BEB. In addition, these figures assume that the buses begin charging at 9 pm at night and are ready for service at about 6 am, as seen in Figure 4-

3. Table 4-6: Senior and Disabled Fleet Annual Utility Costs (Option A) OEM 4
Charge Unmanaged
Bureaucracy
Charges
$1,424
Energy
Charges (per
kWh)
$13,341
Demand
Charges (per
kW)
$17,889
Total

$32,654

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Figure 4-3: Senior and Disabled Fleet Load Schedule

The projected annual utility costs for operating the Fixed-route Fleet are displayed below in Table 4-7. The figures for sequential charging assume that BurbankBus will be levied utility charges based on the Schedule L tariff and the Schedule XL tariff for unmanaged charging . These figures also assume that the buses will charge u sing the standard charger offered by the OEM .

Furthermore, the figures for sequential charging assume that the fleet will be charged in two batches , as seen in Figure 4-4.

Table 4-7: Fixed-Route Fleet Annual Utility Costs - Plug-in Charging Annual Utility Costs (Option A) OEM 1 OEM 2 OEM 3
Charge Unmanaged Sequential Unmanaged Sequential Unmanaged Sequential Bureaucracy
Charges
$1,424 $1,424 $1,424 $1,424 $1,424 $1,424

Energy
Charges (per
kWh)
$70,739 $70,739 $89,956 $89,956 $95,391 $95,391
Demand
Charges (per
kW)
$296,208 $142,044 $394,944 $189,392 $315,955 $185,183
Total

$368,371 $214,207 $486,324 $280,772 $412,770 $281,998

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Figure 4-4: Fixed-Route Fleet Load Schedule

BurbankBus could also opt to charge the fixed -route fleet with high power 150 kW chargers . The projected annual utility costs associated with 150 kW charging is displayed in Table 4-8. The figures for sequential charging assume that BurbankBus will be levied utility charges based on the Schedule L tariff and the Schedule XL tariff for unmanaged charging . These figures assume that the buses are charged at 150 kW. Furthermore, the figures for sequential charging assume that the fleet will be charged in three batches, as seen in Figure 4-5.

Table 4-8: Fixed-Route Fleet Annual Utility Costs – 150 kW Charging Annual Utility Costs (Option A) OEM 1 OEM 2 OEM 3
Charge Unmanaged Sequential Unmanaged Sequential Unmanaged Sequential Bureaucracy
Charges
$1,424 $1,424 $1,424 $1,424 $1,424 $1,424

Energy
Charges (per
kWh)
$70,739

$70,739

$89,956

$95,391 $95,391

Demand
Charges (per
kW)
$592,416 $189,392 $592,416 $189,392 $592,416 $189,392
Total

$664,579 $261,555 $683,796 $280,772 $689,231 $286,207

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Figure 4-5: Fixed-Route Fleet 150 kW Charging Load Schedule

Option B Utility Analysis
Under Option B, the charging for the Fixed -route Fleet and the Senior and Disabled Fleet will be combined at a new depot . The projected annual utility costs for operating the Combined Fleet are displayed below in Table 4-9. The figures for sequential charging assume that BurbankBus will be levied utility charges based on the Schedule L tariff and the Schedule XL tariff for unmanaged charging. These figures also assume that the buses will charge using the standard charger offered by the OEM. These figures assume that the Senior and Disabled Fleet will charge between 9:00 pm and 6:15 am and will be ready for service at 7:30 am. Furthermore, the figures for sequential charging assume that the fleet will be cha rged in two batches , as seen in Figure 4-

6. Table 4-9: Combined Fleet Annual Utility Costs – Plug-in Charging (Option B) OEM 1 + OEM 4 OEM 2 + OEM 4 OEM 3 + OEM 4
Charge Unmanaged Sequential Unmanaged Sequential Unmanaged Sequential Bureaucracy
Charges
$1,424 $1,424 $1,424 $1,424 $1,424 $1,424

Energy
Charges (per
kWh)
$94,032

$94,032

$113,248

$118,683 $118,683

Demand
Charges (per
kW)
$314,097 $174,705 $412,833 $226,977 $333,844 $185,159
Total

$409,553 $270,161 $527,505 $341,649 $453,951 $305,266

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Figure 4-6: Combined Fleet Load Schedule

BurbankBus could also opt to charge the fixed -route fleet with high power 150 kW chargers . The projected annual utility costs associated with 150 kW charging is displayed below in Table 4-10. The figures for sequential charging assume that BurbankBus will be levied utility charges based on the Schedule L tariff and the Schedule XL tariff for unmanaged charging . These figures assume that the buses are charged at 150 kW. These figures assume that the Senior and Disabled Fleet will charge between 9:00 pm and 6:15 am and will be ready for service at 7:30 am. Furthermore, the figures for sequential charging assume that the fleet will be charged in three batches, as seen in Figure 4-7.

Table 4-10: Combined Fleet Annual Utility Costs – 150 kW Charging (Option B) OEM 1 + OEM 4 OEM 2 + OEM 4 OEM 3 + OEM 4
Charge Unmanaged Sequential Unmanaged Sequential Unmanaged Sequential Bureaucracy
Charges
$1,424 $1,424 $1,424 $1,424 $1,424 $1,424

Energy
Charges (per
kWh)
$94,032

$94,032

$113,248

$118,683 $118,683

Demand
Charges (per
kW)
$610,305 $226,977 $610,305 $226,977 $610,305 $226,977
Total

$705,761 $322,433 $724,977 $341,649 $730,412 $347,084

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Figure 4-7: Combined Fleet Load Schedule – 150 kW Charging (Option B)

Utility Infrastructure
To power fleet charging, the utility needs appropriate infrastructure to deliver sufficient power to the depot . Analysis needs to be conducted to determine if there is enough power that can be drawn from the distribution system to power charging . If the distribution system does not have enough power capacity, then utility upgrades need to be conducted. This can entail upgrades to the distribution circuits, utility substations, and/or utility transformer.

The majority of BWP’s utility infrastructure was constructed between 1940 and 1960 . During this period, BWP primarily constructed a distribution system that consisted of 4 kV circuits. Since then, Burbank has experienced major growth underpinned by large developments in the Media District. To serve this increased load, BWP has begun to modernize the distribution system and aims to upgrade 4 kV circuits to 12 kV. BWP is also considering upgrading the existing substations from 34 kV to 69 kV. BWP aims to carry out this modernization over the course of 20 years and intends to use the Capital Improvement Budget to fund this (BWP, 2015).

Despite these upgrades, BWP is concerned about how muc h power will be available on their circuits . BWP expects that power demand from the grid will increase rapidly as building electrification occurs and as more EVs are deployed . As a result, FTM distribution infrastructure might need to be upgraded to bring enough power to serve charging equipment . According to BWP, the customer is responsible for financing required FTM distribution infrastructure upgrades, like transformers . The cost of upgrades can be high . For example, a recent project that BWP worked on i nvolved the installation of 20 DC fast chargers . The utility upgrades for this project were approximately $1 million.

CALSTART held discussions with BWP to obtain an estimate for utility infrastructure costs. During these discussions, BurbankBus identified possible locations for their future depot (see Bus Depot Site Analysis section). In discussions with BWP, representatives stated the estimated that the cost for utility and infrastructure upgrades would be a maximum of $5 million. This cost estimate does not include any substructure work that may be needed. Due to the amount of electricity needed, BurbankBus will need Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-147
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primary service and a backup feeder will need to be run to the site as a resiliency measure. When a site is identified BurbankBus can submit an engineering deposit to BWP for a detailed electrical plan . It is recommended that the engineering deposit be provided about 2-6 months in advance of beginning work. BWP can create the plan, but is not responsible for the actual construction of the equipment which can take a few years. The engineering deposit also informs BWP how much electricity they will need to provide and allows them to prepare t o energize the service. BWP was unable to provide more specifics because BurbankBus does not have a specific site identified.

To mitigate the amount of power that is drawn from the grid by charging, BWP has also expressed an interest in battery swapping. BWP stated that excess solar power is produced during the day . If batteries can be swapped out, excess solar power could be used to charge the batteries during the day and then the batteries could be installed on the bus when it returned to the yard at the end of its day. At the time of writing, no electric bus OEM offers battery swapping.

Charging and Hydrogen Fueling Infrastructure Analysis
BEB Charging Infrastructure Deployment Plan
Installing charging infrastructure is vital for the successful deployment of a BEB fleet. Deploying BEB chargers is more than simply installing the chargers. In addition to utility infrastructure, electrification requires the deployment of BTM infrastructure (on the customer’s side of the meter). BTM infrastructure carries the power from the utility transformer, where the utility delivers power to the depot to the actual chargers . BTM infrastructure upgrades entails installing appropriately sized transformers and switchgear. In addition, conduit through which the circuits can deliver power to the chargers is required . Conduit is typically underground, and the depot must be trenched to install this.

This section will outline a plan for deploying BTM infrastructure to serve BurbankBus’s fleet. An infrastructure plan for Option A and Option B is detailed below:
124 South Lake Street Depot:

If BurbankBus opts to use a BEB fleet, they will need to install charging infrastructure . BurbankBus’s Senior and Disabled Fleet consists of nine shuttle buses that are located at the 124 South Lake Street depot . The 124 South Lake Street depot houses Burbank Public Works’s fleet and maintenance bays. The Senior and Disabled Fleet is currently parked in the employee parking lot in the depot . To charge the shuttle buses, CALSTART recommends that BurbankBus deploys nine Level 2 chargers . This arrangement would allow each bus to have its own charger to charge overnight. CALSTART also recommends that two DCFCs be deployed. The DCFCs would be used in emergency situations if BurbankBus needs to quickly charge a bus.

The 124 South Lake Street depot currently has a BWP utility transformer. Power from BWP is delivered to the yard at this point.

To serve BurbankBus’s charging infrastructure, additional infrastructure will need to be deployed . BurbankBus will need to Install the following equipment to charge a fleet of BEBs:
• 300 kVA utility transformer
• Main Disconnect
• Automatic Transfer Switch (If natural gas generators are used to provide resiliency) • Panel Board (600A, 480/277 V)
• 225 kVA Transformer
• 9 Shuttle Bus Chargers
• Electrical Panel Board (600 A, 120/208 V)

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The conceptual design for the 124 South Lake Street depot can be found in Appendix M.

BurbankBus’s Senior and Disabled Fleet will fully transition to zero -emission between 202 7 and 2032. Since the fleet will be transitioning in a short period of time, it would be advisable to install all of the BTM upgrades at the same time . This entails installing all charging infrastructure and installing conduit directly to the location where each of the chargers will be located .

This strategy allows BurbankBus to insta ll the infrastructure without having to do multiple rounds of trenching . This will make the site “charger ready,” and as the buses are deployed, additional chargers can be added by simply running circuit through the conduit to the chargers.

Combined Fleet Depot:

Under Option B, both fleets will be housed at the same depot . To serve the charging equipment, infrastructure needs to be deployed on the depot. We anticipate that BWP will deliver power to the yard at a utility transformer . BurbankBus will need to install the following equipment to charge a fleet of BEBs:

• 1500 kVA utility transformer.
• Main Disconnect
• Automatic Transfer Switch (if natural gas generators are used to provide resiliency) • Switchboard (2000A, 480 V)
• 6 Transit Bus Power Cabinets
• 18 Transit Bus Depot Chargers
• 9 Shuttle Bus Chargers
• 2 DC Fast Chargers (shuttle bus backup chargers)
• 225 kVA Transformer
• Electrical Panel Board (600 A, 120/208 V)

The specifications for this equipment can be found in the single-line diagram in Appendix M.

BurbankBus’s Senior and Disabled Fleet will fully transition to zero-emission between 2027 and 2032. The Fixed-route Fleet will transition to zero -emission between 2027 and 2039 . To mi nimize the amount of construction work needed to install BTM infrastructure, it is advisable to install all BTM upgrades at the same time . This entails installing charging infrastructure and installing conduit directly to the location where each of the chargers will be located. This strategy allows BurbankBus to install the infrastructure without having to do multiple rounds of trenching . This will make the site “charger ready ,” and as the buses are deployed, additional chargers can be added by simply running circuitry through the conduit to the chargers. To achieve this, preplanning will need to be conducted to identify where each of the chargers will be located on the site . This will allow conduit to be run to where the charger will exist when it is installed.

We estimate that this depot will need a minimum area of 62,265 square feet to accommodate the parked buses, the charging equipment, and additional infrastructure.

FCEB Hydrogen Fueling Infrastructure Deployment Plan
If BurbankBus were to rollout a fleet of FCEBs, the main requirement would be to obtain hydrogen for the fleet. Since it is possible to drive buses from any depot to city-owned hydrogen infrastructure, the hydrogen fueling infrastructure deployment plan would be the same for both Optio n A and Option B . BurbankBus's Senior and Disabled Fleet is projected to consume about 42 kg of hydrogen per day , and the Fixed -Route Fleet is projected to consume about 175 kg per weekday . This equates to about Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-149
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1,170 kg per week or about 60,800 kg of hydrogen per year if the fleet fully transitions to FCEBs.

BurbankBus would have several options for obtaining hydrogen for the fleet . BurbankBus could produce hydrogen on-site via SMR or electrolysis. Alternatively, BurbankBus could opt to receive delivered gaseous or liquid hydrogen . Lastly, BurbankBus could fuel at public fueling stations.

59.1 kWh per kg of hydrogen. An FCEB fleet would require about 220 kg of hydrogen per day. Producing this much hydrogen via electrolysis would require about 13,000 kWh per day, which is more than the amount of energy required by the entire BEB fleet.

Assuming the best-case scenario (that minimizes power demand) where the electrolyzer produces hydrogen 24 hours per day, power demand would be 542 kW. The resulting utility bills are estimated to cost $547,808 per year which would be higher than that of a BEB fleet. Furthermore, utility upgrades might need to be installed to facilitate the delivery of power to the depot.

The use of delivered liquid hydrogen is also infeasible . Liquid hydrogen is typically delivered in large quantities . Most liquid hydrogen trucks can deliver up to 4,500 kg of hydrogen . Based on BurbankBus’s projected consumption, this would amount to 21 service days of hydrogen. However, liquid hydrogen storage loses hydrogen from off-gassing. These losses can be as high as 1 percent per day. To avoid these losses, liquid hydrogen needs to be consumed quickly. Since BurbankBus consumes a relatively small amount of hydrogen, the time between deliveries would be l engthy and there would be significant losses. As a result, the use of delivered liquid hydrogen is not a viable option. Lastly, BurbankBus cannot rely on retail stations to fuel their fleet. At the time of writing, there are no heavy-duty hydrogen stations that are currently in existence or that have been planned in Burbank.

While the Senior and Disabled Fleet could theoretically fuel at a light-duty station, the price of retail hydrogen is high. As a result, this option is also infeasible.

The viable options that BurbankBus ha s to fuel an FCEB fleet would be to use delivered gaseous hydrogen or on-site SMR. On- site SMR is only economically viable at volumes of at least 200 kg per day . As a result, the most viable way to deploy hydrogen infrastructure would be to start with delivered hydrogen . To accept delivered hydrogen, BurbankBus would need to build a hydrogen station . The station would be designed to accept hydrogen from a tube trailer . BurbankBus would then schedule deliveries of hydrogen. Delivered hydrogen is expected to cost about $492,480 per year for the fleet. Once BurbankBus’s demand reaches 200 kg per day, an on-site SMR can be deployed on-site. Based on the fleet replacement plan, BurbankBus would be expected to reach a demand of 200 kg per day in 2035 . When the on-site SMR is installed, the equipment used to accept delivered hydrogen can be left on-site. This will allow BurbankBus to accept delivered hydrogen when the SMR is undergoing scheduled maintenance or there is an equipment f ault. The cost of hydrogen that is produced via on-site SMR is approximately $6 per kg. At this price, BurbankBus would pay approximately $400,672 per year for hydrogen . This amount also exceeds the utility costs that would be associated with charging a BE B fleet with sequential changing. Furthermore, as discussed in On-site Steam Methane Reforming on page 18, an on-site SMR would have a physical footprint of approximately 3,600 square feet.

It is important to note that in addition to the cost of the fuel, there are capital expenditures associated with some of these options. In order to dispense the hydrogen, a hydrogen fueling station needs to be constructed. In addition, hydrogen production equipment needs to be deployed. BurbankBus would need to invest in a fueling station if it decides to obtai n hydrogen via on- site electrolysis, delivered liquid hydrogen, or on-site SMR. If BurbankBus is able to obtain hydrogen from retail fueling stations, there would be no capital expenditures. This cost analysis is summarized in Table 4-11.

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Table 4-11: Hydrogen Cost Analysis
Expense On-site Electrolysis Delivered Liquid
Hydrogen
Offsite Retail
Fueling
On-site SMR
Capital
Expenditures
$5,510,361 $1,825,150 $0 $3,749,348
Annual Cost of
Hydrogen Fuel
$ 547,808 $492,480 Offsite fueling not
currently available
$400,672

Resiliency
BWP has a very resilient grid : according to BWP’s FY2020 Annual Report, the grid had a very high availability rate of 99.998 percent. When an outage occurred, the average interruption length was 8.58 minutes , and the outage frequency rate was approximately 0.38 outages per customer served per year (BWP, 2020). However, grid outages are becoming a more frequent occurrence in California. If there was a grid outage, it would compromise BurbankBus’s ability to charge their buses and provide service. This is especially problematic because BurbankBus connects to areas with major economic activity and helps Burbank’s residents access other forms of public transit, like Metro’s rail system . This means that any disrupti on to the fleet would have impacts on the Los Angeles region as a whole . As a result, BurbankBus needs to have a resiliency option in the event of an extended outage. This section outlines the options that BurbankBus has for resiliency.

FTM Resiliency
At the time of writing, BWP does not offer a n FTM resiliency option . It is important to note that other utilities provide FTM resiliency options by deploying FTM batteries and energy assets so they can continue to provide power to their customers in the event of an outage. These utilities typically finance this resiliency through a special utility tariff. Under this tariff, customers pay a higher rate for energy (per kWh) in exchange for resiliency . This strategy is beneficial because it allows the transit ag ency to obtain resiliency while avoiding the capital expenses associated with deploying resiliency assets. BWP does not currently offer a special utility rate for resiliency. A utility can feasibly offer a special utility rate if there are multiple customers that can make use of it. Since there are few entities within BWP's service territory that could make use of this rate , it is unlikely that BWP will be able to offer this type of resiliency.

BTM Resiliency
This section will outline a BTM resiliency strat egy for both Option A and Option B . To develop these resiliency strategies, CALSTART used Sandia National Laboratory’s MDT . MDT can be programmed with information that is specific to the site being analyzed. This includes factors like the load profile and energy needs of the site/fleet. Furthermore, factors like the type of assets that can be included in the energy portfolio and the cost of different energy assets can be programmed into MDT. Users can also input objectives and criteria that the microgrid needs to be able to meet. This can include criteria like minimizing the capital and operational costs of the microgrid, the percent of energy needs the microgrid meets, or ensuring that a certain percentage of the energy produced comes from renewable energy . Once this information is input into the model, MDT projects the performance of all possible combinations of energy assets. It then selects the set of energy assets that can meet the objectives.

MDT and the assumptions programmed into the model are explained in more detail in Appendix I. The results produced by MDT are outlined below.

Option A:

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measures in place , with two diesel-fired backup generators . These generators have nameplate capacities of 600 kW/750 kVA and 160 kV/200 kVA, respectively. These backup generators are already permitted by AQMD. Burbank Public Works stated that these backup generators are intended to power the maintenance bays, ventilation equipment, server/data room, and lighting on the depot in the event of an outage . However, there is room to install additional ba ckup generators to expand resiliency capabilities.

The South Lake Street depot also has substantial solar capacity. The buildings are not able to support solar PV panels. However, the depot has a large amount of parking and Burbank Public Works is open to installing carport solar PV arrays over the employee parking lot. Using NREL’s PVWatts tool, CALSTART estimates that there is approximately 240 -250 kW of solar capacity in the yard. See Figure 4-8 for an aerial photograph of the yard.

Figure 4-8: Solar Potential at the 124 South Lake Street Depot

To provide full resiliency for the Senior and Disabled Fleet, there are several options. The Senior and Disabled Fleet has relatively low energy needs compared to the Fixed -Route Fleet. Peak power demand for t he Senior and Disabled Fleet is 99 kW and the seven buses put into daily service are expected to consume approximately 710 kWh per day . The employee parking lot has the ability to host 240-250 kW of carport solar. According to modeling from MDT, to provide sufficient energy storage to power the fleet in the event of a grid outage, a battery with a storage capacity of 1200 kWh would be needed.

Other options for providing resiliency would be to install an additional generator with nameplate capacity of 250 kW. This generation capacity can be met with either a natural gas generator or a diesel generator . However, natural gas generators are the cleaner option as they produce fewer NOx and PM emissions . A natural gas turbine would need access to a gas pipeline to obtain fuel. If the generator maintains access to fuel, it is capable of powering the fleet indefinitely. However, if the generator Is permitted as a backup generator, it can only be operated for up to 200 hours per year . It is theoretically po ssible that the generator could lose access to fuel if the natural gas network is disrupted during an emergency. However, disruptions to the natural gas network are rare, and a simultaneous disruption to both the grid and the natural gas network is exceedi ngly rare. If BurbankBus wanted to protect against this possibility, it would be advisable to install a 1,000 -gallon CNG storage tank . The addition of the natural gas storage tank would provide one day of fuel in the event of a gas network disruption.

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There are also multiple options for providing resiliency for the Fixed-Route Fleet. The Fixed-route Fleet has a peak power demand of 900 kW, and the buses consume approximately 2,375 and 3,065 kWh of energy per day. According to NREL’s Reopt Lite tool, to prov ide resiliency for the entire Fixed -route Fleet during a seven -day grid outage, entirely using solar and storage would require an 800 kW PV solar array , in addition to a battery storage system that can provide 900 kW of power and has a storage capacity of at least 7,648 kWh. On the assumption that the panels have an efficiency of 19 percent, a solar array with a surface area of approximately 4,210 square meters (1.04 acres) would be required to fully power the fleet during a seven-day grid outage.

Alternatively. A 1,000 kW generator could provide full resiliency to the fleet in the event of a grid outage . In theory, either a natural gas generator or a diesel generator could be used . However, a natural gas generator will produce fewer emissions and would be the preferred option . A natural gas turbine would need access to a gas pipeline to obtain fuel . If the generator maintains access to fuel, it is capable of powering the fleet indefinitely. To mitigate the risk of a natural gas network disruption, it would be advisable to install a 1,500-gallon CNG storage tank, which could provide one day of fuel in the event of a gas network disruption.

It is important to note that other factors can affect the viability of resiliency options . Resiliency is typically customized to a particular site and the specific qualities of a depot can affect the viability of resiliency options. Since BurbankBus has not yet identified a site to house the Fixed -Route Fleet, it is not possible to determine which resiliency soluti on would be the best fit .

This topic should be revisited once a site for the bus depot has been selected. In addition, there are financial considerations that should affect the decision about which resiliency option to deploy. These considerations are discussed in the Financing Strategy section.

Option B:

There are multiple options for providing resiliency for the Combined Fleet. The Combined Fleet has a peak power demand of 977 kW and the buses consume approximately 3,000 and 3,750 kWh per day. Based on modelling results from NREL’s REopt Lite tool, to provide resiliency for the entire Combined Fleet during a seven -day grid outage, entirely using solar and storage would require a 1,000 kW PV solar array and a battery that can provide 982kW of power and has storage capacity of 9 ,070 kWh. On the assumption that the panels have an efficiency of 19 percent, a solar array with a surface area of approximately 5,168 square meters (1.28 acres), would be required to fully power the fleet during a seven-day outage.

As a result, it would be more practical to use a generator to provide resiliency. 1,500 kW of generator capacity would be needed to provide full resiliency to the fleet in the event of a grid outage . The market for 1,500 kW generators is limited . However, BurbankBus could deploy a 1 ,000 kW generator and a 500 kW generator. In theory , either natural gas generator s or diesel generators could be used. However, a natural gas generator will produce fewer emissions and would be the preferred option. A natural gas turbine would need access to a gas pipeline to obtain fuel. If the generator maintains access to fuel, it is capable of powering the fleet indefinitely. If the generators are permitted as backup generators, a 200 -hour per year operational limit would apply. It is theoretically possible that the generator could lose access to fuel if the natural gas network is disrupted during an emergency. However, disruptions to the natural gas network are rare, and a simultaneous disruption to both the grid and the natural gas network is exceedingly rare. If BurbankBus wanted to protect against this possibility, it would be advisable to install a 1,500-gallon CNG storage tank. The addition of the natural gas storage tank would provide one day of fuel in the event of a gas network disruption.

It is important to note that other factors can affect the viability of resiliency options . Resiliency is typically customized to a particular site and the specific qualities of a depot can affect the viability of resiliency options . Since BurbankBus has not yet identified a site to house the Fixed -Route Fleet, it is not possible to determine which resil iency solution would be the best fit .

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BWP recognizes the need for BurbankBus to have a resiliency option and is supportive of BurbankBus deploying any type of DER assets to provide resiliency to the fleet.

Bus Depot Site Analysis
Both Option A and Option B require the acquisition of a new depot to house the fleet and required infrastructure . Although the exact location of the new depot is unknown, BurbankBus intends to use land that is already owned by the City of Burbank. There are three existing city properties that could serve as examples of possible locations for the bus depot . The first is an empty lot located at the southeast corner of Victory Place and Lincoln Street (highlighted in blue in Figure 4-9).

Figure 4-9: Victory Place and Lincoln Street Lot

The second site is a current parking lot that is located at 323 South Front Street, Burbank, C alifornia 91502 (highlighted in blue in Figure 4-10).

Figure 4-10: 323 South Front Street, Burbank, California 91502

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Based on the depot configuration outlined in the conceptual design , BurbankBus would need a site with dimensions of about 237 feet 6 inches by 262 feet 2 inches to house the buses, charging infrastructure, and resiliency equipment. This equates to an area of approximately 62,265 square feet. Additional space would be required to install a bus maintenance facility, office space, and employee parking. Glendale Beeline’s maintenance, office, and employee parking facilities occupy a space with dimensions of approximately 155 feet by 75 feet, which occupies a physical footprint of approximately 11,625 square feet . The total space required for the bus infrastructure and a maintenance/office building is approximately 73,890 square feet.

Based on these dimensions, it appears that neither site would be suitable to house the Combined Fleet. The Victory Place/Lincoln Street Lot is crescent-shaped and has a surface area of 93,654 square feet. However, this site would not be suitable for housing the Combined Fleet. This site has a width of approximately 135 feet at its widest point . As a result, the site is not wide enough to support the infrastructure required for the Combined Fleet . However, this site does have enough space to house the Senior and Disabled Fleet.

The 323 South Front Street location has dimensions of approximately 735 feet by 55 feet. This equates to a surface area of approximately 40,425 square feet . This location does not have enough surface area to host the Combined Fleet . In addition, since the yard is narrow, it would be difficult to build a useable maintenance facility on this site . However, this site does have enough space to house the Senior and Disabled Fleet.

The third site is a property at the intersection of West Magnolia B oulevard and North Front Street. This parcel of land is owned by the City of Burbank. This property is approximately 596 feet by 180 feet, which equates to a surface area of approximately 107,280 square feet. This site has enough surface area to host the Combined Fleet. It is also wide enough to accommodate the fleet. As a result, this site is able to accommodate the Combined Fleet, from a space perspective.

Figure 4-10: 323 South Front Street, Burbank, California 91502

It is important to note that there are multiple factors beyond physical footprint that need to be evaluated when selecting a bus depot. Numerous site-specific factors affect suitability for hosting a bus depot . These factors include , but are not limited to, existing utility infrastructure on the site, the availability of utility grid power, the ability to obtain construction and environmental permits, and other site-specific factors that can hinder construction . These factors should be considered before selecting a site to host a bus depot. Furthermore, site-specific construction and engineering documents should be developed before proceeding Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-155
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with construction on a selected site.

Financial Analysis & Cost Estimates
CALSTART developed cost estimates for BurbankBus’s transition to a zero -emission fleet. CALSTART developed cost estimates for the status quo with a CNG fleet . CALSTART also provided estimates for the cost of transitioning to both a BEB fleet and a n FCEB fleet. This financial analysis assumes that the buses are deployed according to the Fleet Replacement Plan (see page 1266).

Table 4-12 outlines the expected cost of purchasing and operating a CNG fleet . This scenario represents a continuation of the status quo between 2021 until 2040. Under this scenario, BurbankBus is projected to spend $16,847,735 between 2021 and 2040. When this amount is discounted at a rate of 4 percent per year (discounted to 2021 dollars), this amounts to a net present value of $9,714,672. Since BurbankBus already has access to CNG fueling infrastructure, this figure includes the capital expenditures associated with purchasing buses. In addition, this analysis takes into account operational costs like maintenance costs, midlife bus repairs, and the cost of fuel. This analysis does not include the cost of acquiring land or labor associat ed with operating the buses.

Table 4-12: CNG Fleet Financial Analysis

Year
Transit Buses
Shuttle Buses
Bus Maintenance
Midlife Repairs
CNG Fuel Costs
Total Cost
Net Present Value (2021 dollars)
2021
2022
2023
2024
2025
2026
2027 $1,300,000 $720,000 $28,005 $144,400 $64,615 $2,257,021 $1,715,150 2028 $28,005 $64,615 $92,621 $67,677
2029 $360,000 $37,772 $25,200 $86,154 $509,126 $357,705 2030 $37,772 $86,154 $123,926 $83,720
2031 $37,772 $86,154 $123,926 $80,500
2032 $540,000 $52,423 $37,800 $118,462 $748,685 $467,626 2033 $52,423 $118,462 $170,885 $102,629
2034 $52,423 $118,462 $170,885 $98,682
2035 $7,800,000 $103,246 $564,000 $247,692 $8,714,939 $4,839,096 2036 $103,246 $247,692 $350,939 $187,369
2037 $103,246 $247,692 $350,939 $180,163
2038 $103,246 $247,692 $350,939 $173,233
2039 $1,950,000 $115,952 $141,000 $280,000 $2,486,952 $1,180,413 2040 $115,952 $280,000 $395,952 $180,707
Total $11,050,000 $1,620,000 $971,489 $912,400 $2,293,846 $16,847,735 $9,714,672 Capital Expenditures Operational Expenditures Total Costs Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-156
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The cost of transitioning to a fully BEB fleet, as detailed in Table 4-13, is projected to cost $30,229,373 between 2021 and 2040.

When this amount is discounted at a rate of 4 percent per year (discounted to 2021 dollars), this amounts to a net present value of $19,629,301. This figure includes the capital expenditures associated with utility upgrades, building a depot (purchasing and installing chargers), and the cost of the buses . In addition, this analysis takes into account operational costs like maintenance costs, the cost of electricity from the utility, and the cost of maintaining charging infrastructure.

There are a few caveats in th e figures for BEBs. First, the utility upgrades are projected to be $1 mill ion. However, this figure is based on other EV charger installations that took place in BWP territory. The cost of utility upgrades is site-specific and can vary greatly depending on the location . If BurbankBus selects a site that requires substantial up grades to the utility distribution system, the cost of utility upgrades can be substantially higher. In addition, since the cost of building the depot and installing the chargers is expected to cost about $3 million (see Appendix N for more information about the cost assumptions). This figure does not include the construction of maintenance bays or office space . Since further investigation needs to be taken to understand the most best resiliency option, the cost of resiliency was not included in the capital expenditures section. Lastly, this analysis does not include the cost of acquiring land or labor associated with operating the buses.

Table 4-13: BEB Fleet Financial Analysis

If BurbankBus were to transition to a n FCEB fleet, it will need to select a hydrogen fueling pathway . The hydrogen fueling pathway impacts the costs associated with deploying an FCEB fleet. Table 4-14 provides an overview of the costs associated with each hydrogen production pathway.

Year
Transit Buses
Shuttle Buses
Driver and Maintenance Training
Charging Infrastructure
Utility Infrastructure
Bus Maintenance
Midlife Repairs
Infrastructure Maintenance
Utility Costs (fueling costs)
Total Cost
Net Present Value (2021 dollars)
2021
2022
2023
2024 $5,000,000 $5,000,000 $4,274,021
2025 $3,000,000 $3,000,000 $2,465,781
2026
2027 $1,600,396 $1,120,000 $78,750 $58,446 $192,652 $9,000 $77,782 $3,137,026 $2,383,882 2028 $58,446 $9,000 $77,782 $145,228 $106,116
2029 $560,000 $78,830 $42,000 $9,000 $103,709 $793,539 $557,530 2030 $78,830 $9,000 $103,709 $191,539 $129,397
2031 $78,830 $9,000 $103,709 $191,539 $124,420
2032 $840,000 $109,406 $63,000 $9,000 $142,600 $1,164,006 $727,035 2033 $109,406 $9,000 $142,600 $261,006 $156,753
2034 $109,406 $9,000 $142,600 $261,006 $150,724
2035 $9,602,376 $215,471 $651,912 $9,000 $298,164 $10,776,923 $5,984,043 2036 $215,471 $9,000 $298,164 $522,635 $279,039
2037 $215,471 $9,000 $298,164 $522,635 $268,307
2038 $215,471 $9,000 $298,164 $522,635 $257,987
2039 $2,400,594 $241,987 $162,978 $9,000 $337,055 $3,151,615 $1,495,890 2040 $241,987 $9,000 $337,055 $588,043 $268,375
Total $13,603,366 $2,520,000 $78,750 $3,000,000 $5,000,000 $2,027,454 $1,112,542 $126,000 $2,761,261 $30,229,373 $19,629,301 Capital Expenditures Operational Expenditures Total Costs Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-157
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Table 4-14: Hydrogen Production Pathways Financial Analysis Hydrogen Production Pathway Cost Estimates Net Present Value On-site SMR $33,107,799 $20,014,698
On-site Electrolysis $35,995,414 $22,076,954
Delivered Gaseous Hydrogen $31,712,460 $18,706,071
Delivered Liquid Hydrogen $32,481,060 $19,164,387

The most cost-effective method for obtaining hydrogen would be through the delivery of gaseous hydrogen. The cost of transitioning to a fully FCEB fleet using delivered gaseous hydrogen is detailed in Table 4-15. It is projected to cost $31,712,460 between 2021 and 2040. When this amount is discounted at a rate of 4 percent per year (discounted to 2021 dollars), this amounts to a net present value of $18,706,071. This figure includes the capital expenditures associated with building a hydrogen fueling station (see Appendix N for the methodology for estimating the hydrogen fueling station costs) and the cost of the buses.

In addition, this analysis takes in to account operational costs like maintenance costs, the cost of hydrogen, and the cost of maintaining hydrogen infrastructure. This analysis does not include the cost of acquiring land or labor associated with operating the buses.

Table 4-15: FCEB Fleet Financial Analysis

Financing Strategy
BurbankBus will need a financing strategy to transition to a zero -emission fleet. The most important item that BurbankBus will need to obtain is land for a bus depot. If BurbankBus can utilize land that is already owned by the City of Burbank, they can avoid Year
Transit Buses
Shuttle Buses
Driver and Maintenance Training
Hydrogen Infrastructure
Bus Maintenance
Midlife Repairs
Infrastructure O&M
Hydrogen Costs
Total Cost
Net Present Value (2021 dollars)
2021
2022
2023
2024
2025 $1,825,150 $1,825,150 $1,500,140
2026
2027 $2,209,979 $1,020,000 $153,325 $68,186 $122,396 $130,111 $98,407 $3,802,404 $2,889,515 2028 $68,186 $130,111 $98,407 $296,705 $216,799
2029 $510,000 $91,968 $27,518 $130,111 $125,925 $885,522 $622,156 2030 $91,968 $130,111 $125,925 $348,004 $235,099
2031 $91,968 $130,111 $125,925 $348,004 $226,057
2032 $765,000 $127,640 $41,277 $130,111 $167,203 $1,231,231 $769,023 2033 $127,640 $130,111 $167,203 $424,954 $255,216
2034 $127,640 $130,111 $167,203 $424,954 $245,400
2035 $13,259,872 $251,383 $404,160 $130,111 $427,425 $14,472,950 $8,036,316 2036 $251,383 $130,111 $427,425 $808,918 $431,888
2037 $251,383 $130,111 $427,425 $808,918 $415,277
2038 $251,383 $130,111 $427,425 $808,918 $399,305
2039 $3,314,968 $282,318 $101,040 $130,111 $492,480 $4,320,917 $2,050,891 2040 $282,318 $130,111 $492,480 $904,909 $412,989
Total $18,784,819 $2,295,000 $153,325 $1,825,150 $2,365,363 $696,391 $1,821,554 $3,770,858 $31,712,460 $18,706,071 Capital Expenditures Operational Expenditures Total Costs Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-158
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having to purchase land. However, if City of Burbank property cannot be used, land will need to be purchased to house the fleet.

The financial resources to purchase land can be obtained by winning a grant that fun ds capital expenditures , like Caltrans’s TIRCP. A TIRCP grant can also be used to finance utility and BTM infrastructure upgrades. The U.S. Department of Transportation also provides federal grants that could potentially be used to fund this . The U.S. Department of Transportation offers the Bus & Bus Facilities grant, which is used to fund the purchase of buses, related equipment, and to cons truct bus facilities.

Once a transit property has been acquired and the infrastructure upgrades have been completed, the operational costs are expected to be covered by BurbankBus’s operating budget . However, the purchase of the buses needs to be financed . Bus purchases can be financed with various grant and funding sources ( see Financing Strategies & Resources on page 40). Most of these grant and finance programs will only partially finance the cost of the buses . To maximize funding for bus purcha ses, it would be advisable to apply for multiple grants so they can be stacked. It is unlikely that grants will pay for the entire transition to a zero-emission fleet. The main objective when pursuing grants should be to cover the incremental cost of zero emission buses, or the difference between the cost of a ZEB and a CNG bus. Using grants to cover the incremental cost of the buses would allow BurbankBus to purchase ZEBs with the funding sources they normally employ to purchase buses.

BurbankBus should also consider which finance methods would be most appropriate for their agency. If BurbankBus is amenable to capital expenditures, then traditional financing models would be the appropriate. However, if BurbankBus prefers to avoid or reduce capital expenditures, then financing models like bus/battery leasing or IAAS would be more appropriate. These financing models would effectively allow BurbankBus to pay for capital expenditures from their operational budget.

There are additional financial considerations that need to be considered when deploying resiliency assets. If BurbankBus deploys resiliency assets, the most likely candidates would be solar and storage or natural gas turbines . However, there are unique financial considerations that need to be evaluated when selecting an asset . One major drawback of natural gas turbines is that they are subject to air quality regulations and would likely be permitted as backup generators. As a result, they can only be used in the event of a grid outage . This means that they would be idle for the vast majority of the time . This is problematic because generators have a high capital cost meaning that the levelized cost of energy (per kWh) produced by the generator would be very high. Unlike generators, there are no restrictions on when solar and storage can be used . A solar and storage system is eligible for net metering and excess energy produced can be exported to the grid and sold back to the utility. Furthermore, the storage system can be used to “peak shave.” This occurs when the battery is used to provide energy during times of high power to reduce overall power draw from the grid. This is useful because it can reduce demand charges, which are a major component of utility costs. Furthermore, a solar and storage system could potentially generate revenue by providing ancillary grid services .

Since solar and storage can provide a transit agency with savings and/or revenue, the levelized cost of energy would be much lower than for a natural gas generator.

In addition, solar and storage is better situated to take advantage of the ITC. The ITC provides a tax credit for the investment in particular DERs. Solar is eligible for a 10 percent ITC. The ITC for solar is permanent. Generators are only eligible for a 10 percent ITC if they are used in a combined heat and power system (a system where waste heat from the generator is captured and used to provide heating for a building or industrial process). Since air quality regulations limit backup generator use to 200 hours per year, they would likely not be considered a combined heat and power system . Furthermore, the ITC for combined heat and power systems expires at the end of 2023.

If BurbankBus opts to deploy ITC-eligible DERs, acquiring them through a third-party ownership model, like IAAS, would likely be the best option. The entity that owns the DER is eligible for the ITC. As a public agency, BurbankBus is a tax -exempt entity. As a result, BurbankBus would not be able to benefit from the ITC. However, if BurbankBus were to finance the DERs through an IAAS model where a third -party owns the asset, the infrastructure provider can realize the benefits of the ITC and pass the benefits on to BurbankBus in the form of lower PPA rates . If BurbankBus opts to deploy DERs that are eligible for the ITC , the use of an Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-159
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IAAS financing model should be seriously considered.

LCFS Credits
Once the buses are deployed, LCFS credits can also be used to finance capital expenditures and operational expenses . LCFS credits can be used in many ways . If BurbankBus owns the charging equipment, they would earn the LCFS credits and could redeem them for cash. However, there are other ways that the LCFS credits can be used. Transit agencies can transfer their LCFS credits to their utility for a certain period of time to fund utility upgrades . LCFS credits can also benefit a transit agency even if they do not own the charging equipment or if they opt to use an IAAS financing model . If this were to occur, the infrastructure provider would receive the LCFS credits . The infrastructure provider could then pass on the benefits of the LCFS credits to the transit agency in the form of lower PPA rates.

The value of the LCFS credits Is estimated below in Tables 4-16 and 4-17. These projections provide the nominal revenue generated by LCFS credits. They also provide a net present value which assume s a 4 percent discount rate (discounted to 2021 dollars) and a LCFS credit value of $200.

Table 4-16: Fixed-Route Fleet LCFS Credit Value (displacing diesel fuel)

Year Revenue Net Present Value Levelized cost per kWh
2021 $0 $0 $0.00
2022 $0 $0 $0.00
2023 $0 $0 $0.00
2024 $0 $0 $0.00
2025 $0 $0 $0.00
2026 $0 $0 $0.00
2027 $21,981 $17,372 $0.19
2028 $21,558 $16,382 $0.18
2029 $21,138 $15,445 $0.17
2030 $20,714 $14,553 $0.16
2031 $20,714 $13,994 $0.15
2032 $20,714 $13,455 $0.14
2033 $20,714 $12,938 $0.14
2034 $20,714 $12,440 $0.13
2035 $144,998 $83,733 $0.13
2036 $144,998 $80,512 $0.12
2037 $144,998 $77,416 $0.12
2038 $144,998 $74,438 $0.11
2039 $176,069 $86,912 $0.11
2040 $176,069 $83,570 $0.11
Total $1,100,376 $603,161 $0.12

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Table 4-17: Senior and Disabled Fleet LCFS Credit Value (displacing gasoline fuel)

Year Revenue Net Present Value Levelized cost per kWh
2021 $0 $0 $0.00
2022 $0 $0 $0.00
2023 $0 $0 $0.00
2024 $0 $0 $0.00
2025 $0 $0 $0.00
2026 $0 $0 $0.00
2027 $20,689 $16,351 $0.18
2028 $20,292 $15,420 $0.17
2029 $29,841 $21,805 $0.16
2030 $29,240 $20,544 $0.15
2031 $29,240 $19,754 $0.15
2032 $34,114 $22,160 $0.14
2033 $34,114 $21,307 $0.14
2034 $34,114 $20,488 $0.13
2035 $34,114 $19,700 $0.13
2036 $34,114 $18,942 $0.12
2037 $34,114 $18,213 $0.12
2038 $34,114 $17,513 $0.11
2039 $34,114 $16,839 $0.11
2040 $34,114 $16,192 $0.10
Total $436,325 $265,227 $0.13

It is important to note that the number of LCFS credits awarded depends on the quantity of GHG emissions that are avoided by using BEBs. As California’s grid becomes cleaner, this increases the amount of GHG emissions avoided. Consequently, as the grid becomes less carbon intensive, the number of LCFS credits awarded is likely to increase. This means that the value of the LCFS credits earned has the potential to increase as the utility grid becomes cleaner. The methodology used to make these calculations can be found in Appendix O.

Implementation Plan
BurbankBus has many options for deploying a ZEB fleet. The most practical option would be to deploy a BEB fleet . As discussed under Financial Analysis and Cost Estimates on page 142, a fully BEB fleet would be a cheaper option than deploying a fully FCEB fleet. Furthermore, since BEBs can serve as a drop -in replacement for all of BurbankBus’s shifts, there would not be any bus performance benefits to deploying an FCEB fleet.

Currently, the main barrier to deploying a BEB fleet would be the provision of a site to house the Fixed-Route Fleet (under Option A) or the Combined Fleet (under Option B) . Identifying a site that can house the fleet needs to be a priority . Until a depot is identified, it is difficult to plan for the fleet . Fleet planning is site -specific. Without a depot, it is im possible to determine what type of utility upgrades will need to be performed and what resiliency options will be viable . These are crucial questions that a transit agency needs to address early in the planning process. In addition, the provision of FTM utility infrastructure upgrades (if needed) and construction of the site can be a lengthy process . This can potentially delay the deployment of a fleet. Identifying a site will allow BurbankBus to gain clarity on these key questions and begin preparing to deploy a zero-emission fleet.

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The amount of time required to conduct utility infrastructure upgrades depends on the type of upgrade necessary. If the load of the buses is within the current capacity of existing feeders, then the site would likely need only a transformer upgrade . This upgrade can usually be completed in under a year . However, if the utility must upgrade their distribution system, then the upgrades can take substantially longer to install. As an example of a worst -case scenario, if a new substation must be built, the typical project timeline can take up to 2-4 years. If a substation upgrade is required, the construction process can take 18 months to 3 years . According to the Fleet Replacement Plan, the first buses are scheduled to arrive in 2027 . BurbankBus should work with BWP to identify sites that have access to sufficient grid distribution capacity and that will require the least amount of utility upgrades. Once the site is identified, BurbankBus should work with BWP to submit a request for electrical service. If the selected site will require substantial upgrades to the utility’s distribution system, a site selection and the requ est for electrical service should occur by 2023 to ensure that there is enough time to carry out the upgrades before the buses arrive . In addition, more loads are being added to BWP’s grid, which is reducing the amount of grid distribution capacity availab le. As a result, it would be advantageous to have a site selected and begin the request for electrical service as soon as possible to avoid being “crowded out.”

Once a site is identified, construction will also need to occur for BTM infrastructure on the depot. Typically, the utility will deliver power to the site at a utility transformer . The transformer is then connected to switchgear, which is then connect ed to the chargers by circuit. Most BTM construction involves installing switchgear, the chargers, and the circuits that connect the chargers to the switchgear. Generally, the wires are installed underground, which requires trenching.

It is important to note that the buses are scheduled to be phased-in over time, and they will not all arrive during the same year.

In light of this, it is important to plan ahead . Since all of the buses will not be arriving at the same time, it does not make sense to install all of the chargers at once ; the chargers that are not being used will experience wear and tear . Instead, the chargers that will be used more readily should be installed, and the rest of the site should be constructed so that it is “EV Ready.” This entails installing electrical panels as well as conduit and circuit running to the locations where the ch argers will eventually be installed. Constructing the site as EV Ready is important because it allows chargers to be installed quickly as they are needed. In addition, it minimizes the cost of construction as it ensures that the site only needs to be trenc hed once. Site construction can take up to two years, especially if environmental permits are required . BurbankBus should also install any resiliency or backup power during initial construction.

It is vital that both the utility upgrades and the BTM construction occurs before the buses arrive . If this is not completed, then the buses will not be able to charge . In addition, during the construction process, the site can be unusable, especially during trenching. BurbankBus should coordinate with BWP to ensure that the utility upgrades are coordinated with the delivery of the buses. If the buses arrive before the utility upgrades and/or site construction is completed, BurbankBus can use temporary chargers until the permanent charging infrastructure is ready for use.

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Section V: Executive Summary
In addition to combating climate change, ZEBs provide a number of health benefits. Internal combustion engine buses produce GHG, NOx, and PM emissions within transit service areas that affect air quality and human respiratory systems. AVTO has already transitioned from diesel -powered buses to CNG -powered buses, which do produce fewer tailpipe emissions than diesel . ZEBs, however, produce no tailpipe emissions and therefore help improve local air quality. However, upstream emissions, which are emitting during production of bus fuels, must be taken into account. CNG, electricity, and hydrogen all generate emissions during production. Regardless of production location, which may be some distance from a transit agency's service areas, GHGs contribute to climate change. This section provides a comparison of both tailpipe and upstream emissions for each bus technology—CNG, BEBs, and FCEBs—based on each of the three transit agencies' ZEV implementation scenarios.

Table 5-1 through Table 5-5 demonstrate the estimated pollution produced when operating each bus type under each transit agency, as well as show the emissions produced through five different hydrogen production pathways . These calculations indicate that a fully BEB or FCEB fleet will produce significantly lower amounts of GHG emissions than a CNG fleet. BEBs produce the lowest operational GHG emissions, but if hydrogen is produced with renewable energy, an FCEB fleet would generate the lowest amounts of GHGs.

Table 5-6 through 5-10 indicate the upstream and tailpipe emissions from CNG buses for each transit agency. This distinction is important since tailpipe emissions occur locally in the community. ZEBs have zero tailpipe emissions, so the tailpipe emission figures for CNG buses represents the annual reduction in local pollution from transitioning to ZEBs. While GHG emissions contribute to climate change regardless of origin, criteria pollutants impact local air quality.

Renewable Natural Gas (RNG)
The ICT regulation does not require AVTO to purchase buses until 2026, so AVTO’s shift to a full ZEB fleet will be gradual. AVTO’s CNG-powered buses will not be replaced until the end of their useful life, but ther e are options to reduce emissions before the full transition to ZEBs is complete. One advantageous alternative is RNG, which is produced by capturing the methane that arises when organic waste (i.e., biotic material), such as manure, compost, or food waste , decomposes. This approach also prevents methane from entering the atmosphere and could have a beneficial effect on global warming. Transit agencies can sign RNG contracts with natural gas fuel providers to deliver specified volumes at designated carbon i ntensity; fuel prices will depend on RNG market conditions.

Section V: Executive Summary
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Battery and Fuel Cell Stack/Module Recycling
The lifecycle environmental impact of batteries is a concern that foundational stakeholders in battery recycling like Li -Cycle, RecycLiCo, and Redwood Materials are seeking to tackle. To lessen the environmental and social impacts of battery raw materials and reduce the amount of waste associated with batteries, these companies are innovating processes to break batteries back down to their raw materials and reinsert them back into the manufacturing process. Second life applications are also expected to increase in the future. Moreover, b atteries are typically replaced in transportation applications once they degrade to 80 percent capacity, but these batteries can theoretically be refurbished and reused in a second-life application, like in a stationary energy storage system or a microgrid, prior to final disposal at a battery recycling company.

Fuel cell manufacturers are also looking to optimize the usage and lifetime of the materials used in production of fuel cell stacks and modules. For example, Ballard Power Systems Inc—a manufacturer of proton exchange membrane (PEM) fuel cell products for heavy-duty vehicle applications —has developed a recycling process in which a key component of the module, platinum, is almost completely recovered. Research is underway to determine how all fuel cell components can be either recycled or reused.

This technology is still relatively new, however, and few FCEBs on the road are nearing end of life at this time.

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Section V: Sustainability and Environmental Impact
Emissions Comparisons
ZEB technology provides environmental benefits for transit service areas . As noted in detail under Se ction I: Benefits of ZEBs, buses with an internal combustion engine produce tailpipe emissions , such as GHGs, NOx, and PM, during operation that drive climate change, harm air quality, and affect human health. AVTO has transitioned from diesel-powered buses to CNG-powered buses, which produce fewer tailpipe emissions than diesel. ZEBs, however, produce no tailpipe emissions, and therefore aide in improving local air quality and residents' respiratory health.

Tailpipe emissions are not t he only emissions associated with the operation of buses . Buses also produce upstream emissions , which are emitted during the production of the fuel that buses use . For example, CNG must be extracted, processed, and transported to buses. The production processes of electricity and hydrogen also generate emissions. As a result, even ZEBs will produce some upstream emissions . Upstream emissions are generally emitted where the fuel is produced and not in the area where the buses operate, but GHGs contribute to climate change regardless of origin.

This section will provide comparisons of both tailpipe and upstream emissions for each bus technology, including CNG-powered buses, BEBs, and FCEBs. Table 5-1 through Table 5-5 show the estimated pollution produced by the operation of the buses used for each transit agency. The se figures do not encompass any emissions related to the manufacture of the buses. ZEBs are assumed to have no tailpipe emissions , and all emissions related to the operation of ZEBs oc cur upstream in the supply chain when the electricity or hydrogen is produced. By contrast, CNG buses produce both upstream and tailpipe emissions during operation. The majority of CNG bus operational emissions occur at the tailpipe.

In addition, Table 5-1 through Table 5-5 calculate the emissions produced through five different hydrogen production pathways:

1. Delivered Gaseous Hydrogen Pathway #1: SMR at central plants to produce gaseous hydrogen

2. Delivered Gaseous Hydrogen Pathway #2 : Electrolysis at central plants using solar energy to produce gaseous hydrogen (fully renewable gaseous hydrogen production)

3. On-site SMR Hydrogen Production Pathway: SMR at the refueling station to produce gaseous hydrogen

Section V
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4. On-site Electrolysis Hydrogen Production Pathway : Electrolysis at the refueling station using California grid electricity to produce gaseous hydrogen

5. Delivered Liquid Hydrogen Production Pathway: SMR at central plants to produce liquid hydrogen The figures in Table 5-1 through Table 5-5 represent the annual emissions that occur from the entire fleet. The methodology for these calculations is detailed in Appendix O.

Table 5-1: Emissions Calculations for the Pasadena Department of Transportation Scenario 1 Emission
Type CNG BEB FCEB SMR
Central
FCEB Solar
Electrolysis
Central
FCEB
On-
site
SMR
FCEB
On-site
Electrolysis
FCEB
Central
SMR LH2
GHG Emissions (metric tons per year)
CO2 1,828 431 630 60 700 643 742
CH4 10.35 0.842 1.159 0.117 1.818 1.255 1.369
N2O 0.37 0.008 0.006 0.001 0.017 0.011 0.007
Total GHGs 2,237 459 666 64 759 684 785
Criteria Pollutant Emissions (kg per year)
CO 38,902 444 202 62 419 662 314
NOx 2,163 422 265 59 513 629 386
PM10 20 68 30 9 24 101 48
PM2.5 16 29 24 4 19 43 32
SOx 297 107 125 15 124 159 151
Table 5-2: Emissions Calculations for the Pasadena Department of Transportation Scenario 2 Emission
Type CNG BEB FCEB SMR
Central
FCEB Solar
Electrolysis
Central
FCEB
On-
site
SMR
FCEB
On-site
Electrolysis
FCEB
Central
SMR LH2
GHG Emissions (metric tons per year)
CO2 2,596 616 870 86 967 888 1025
CH4 14.70 1.201 1.601 0.167 2.511 1.734 1.891
N2O 0.53 0.011 0.008 0.002 0.023 0.016 0.010
Total GHGs 3,177 654 920 91 1049 945 1085
Criteria Pollutant Emissions (kg per year)
CO 55,249 633 279 88 578 914 434
NOx 3,073 602 365 84 709 869 534
PM10 29 97 42 13 33 139 66
PM2.5 23 41 33 6 26 59 44
SOx 421 152 172 21 171 220 208

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Table 5-3: Emissions Calculations for Glendale Beeline Scenario 1 Emission
Type CNG
CA
Grid
BEB
FCEB
SMR
Central
FCEB Solar
Electrolysis
Central
FCEB
On-
site
SMR
FCEB
On-site
Electrolysis
FCEB
Central
SMR LH2
GHG Emissions (metric tons per year)
CO2 2,090 538 786 75 874 803 926
CH4 7.926 1.050 1.446 0.146 2.269 1.566 1.708
N2O 0.426 0.010 0.007 0.001 0.021 0.014 0.009
Total GHGs 2,441 572 831 80 947 853 980
Criteria Pollutant Emissions (kg per year)
CO 47,945 554 252 77.0 522 826 392
NOx 1,534 526 330 73.2 641 785 482
PM10 8 84 38 11.7 30 126 59
PM2.5 11 36 30 5.0 23 54 40
SOx 60 133 155 18.5 154 199 188

Table 5-4: Emissions Calculations for Glendale Beeline Scenario 2 Emission
Type CNG
CA
Grid
BEB
FCEB
SMR
Central
FCEB Solar
Electrolysis
Central
FCEB
On-
site
SMR
FCEB
On-site
Electrolysis
FCEB
Central
SMR LH2
GHG Emissions (metric tons per year)
CO2 2,366 585 855 81 950 873 1007
CH4 8.880 1.142 1.573 0.159 2.467 1.703 1.858
N2O 0.482 0.010 0.007 0.001 0.022 0.015 0.010
Total GHGs 2760 622 904 87 1030 928 1066
Criteria Pollutant Emissions (kg per year)
CO 54,360 602 274 84 568 898 426
NOx 1,714 573 359 80 697 854 524
PM10 8 92 41 13 33 137 64
PM2.5 13 39 33 5 25 58 43
SOx 62 145 169 20 168 216 205

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Table 5-5: Emissions Calculations for BurbankBus
Emission
Type CNG
CA
Grid
BEB

FCEB SMR
Central
FCEB Solar
Electrolysis
Central
FCEB
On-
site
SMR
FCEB
On-site
Electrolysis
FCEB
Central
SMR LH2
GHG Emissions (metric tons per year)
CO2 697 144 211 20 234 215 248
CH4 3.949 0.282 0.388 0.039 0.608 0.420 0.458
N2O 0.142 0.003 0.002 0.000 0.006 0.004 0.002
Total GHGs 853 153 223 21 254 229 263
Criteria Pollutant Emissions (kg per year)
CO 14837 149 68 21 140 221 105
NOx 825 141 89 20 172 210 129
PM10 8 23 10 3 8 34 16
PM2.5 6 10 8 1 6 14 11
SOx 113 36 42 5 41 53 50

The calculations indicate that a fully BEB or FCEB fleet will produce significantly lower amounts of GHG emissions than a CNG fleet. BEBs produce the lowest operational GHG emissions, compared to their hydrogen or CNG -powered counterparts . If hydrogen is produced with renewable energy, however, FCEBs will generate the lowest amounts of GHGs.

Natural gas is a fossil fuel composed primarily of methane . When burned, natural gas produces CO2, which is also a GHG .

Furthermore, methane itself is a GHG and is a more potent GHG than CO2. Methane contributes to climate change as it leaks into the atmosphere throughou t the natural gas supply chain . Over time, methane slowly decays into CO2, reducing its global warming potential. The calculations account for this occurrence and assume a 100-year time horizon for measuring the climate impact of methane leaks.

CNG buses use natural gas and produce GHG emissions during operation . BEBs also use natural gas indirectly . Natural gas is a major source of electricity generation in California’s grid . BEBs produce fewer GHG emissions than CNG buses because the combustion of methan e in power plants is more efficient than in an internal combustion engine in a bus . In addition, the opportunities for methane leakage are fewer. Furthermore, the California grid also uses a substantial and increasing amount of renewable energy sources such as solar, wind, and hydropower . In addition, an electric drivetrain is more efficient than an internal combustion engine. As a result, electricity is a less GHG-intensive fuel than CNG.

The GHG-intensity of hydrogen depends on the production pathway . SMR hydrogen pathways consume natural gas to produce hydrogen. As a result, SMR pathways essentially replace natural gas with a direct product of natural gas. A transition to FCEBs with hydrogen produced from SMR does have a net effect of reducing emissions due to the reduced leakage and the higher efficiency of the SMR process. If hydrogen is produced using electrolysis with electricity from the power grid, then there will still be a net reduction of emissions. However, this reduction is smaller than the benefit from a transition to BEBs or hydrogen using SMR, which occurs because of the lower efficiency of the electrolysis process . Of the energy that is used to produce hydrogen, only about half of it is stored as hydrogen . Lastly, liquid hydrogen has the hi ghest GHG-intensity of the hydrogen production pathways. Hydrogen must be produced and then converted into gaseous form in a process called liquefaction . The liquefaction process is extremely energy intensive.

The following tables indicate the emissions f rom CNG buses for each transit agency. They are broken into upstream emissions and tailpipe emissions. This distinction is important because tailpipe emissions occur locally in the community . ZEBs have zero Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-168
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tailpipe emissions . As a result, the tailpipe emi ssion figures for CNG buses represents the annual reduction in local pollution from transitioning to ZEBs . While GHG emissions contribute to climate change regardless of origin, criteria pollutants have a local impact on air quality . As a result, the reduction of criteria pollutants will provide local benefits for air quality and public health. The results are displayed in Tables 5-6 through 5-10.

Table 5-6: Projected Emissions from CNG Buses Operated by the Pasadena Department of Transportation Scenario 1 The Pasadena Department
of Transportation
Scenario 1 CNG Emissions
Upstream Tailpipe Total
GHG Emissions (metric tons per year)
CO2 197.00 1,630.53 1,827.52
CH4 4.83 5.52 10.35
N2O 0.04 0.33 0.37
Total GHGs 352.77 1,884.25 2,237.02
Criteria Pollutant Emissions (kg per year)
CO 912.80 37,988.89 38,901.69
NOx 1,125.76 1,037.64 2,163.39
PM10 17.37 3.06 20.43
PM2.5 13.23 3.20 16.42
SOx 296.61 - 296.61

Table 5-7: Projected Emissions from CNG Buses Operated by Pasadena Department of Transportation Scenario 2 The Pasadena Department
of Transportation Scenario
2 CNG Emissions
Upstream Tailpipe Total
GHG Emissions (metric tons per year)
CO2 279.78 2,315.73 2,595.51
CH4 6.86 7.84 14.70
N2O 0.06 0.47 0.53
Total GHGs 501.01 2,676.08 3,177.09
Criteria Pollutant Emissions (kg per year)
CO 1,296.38 53,953.10 55,249.49
NOx 1,598.84 1,473.68 3,072.52
PM10 24.67 4.34 29.01
PM2.5 18.79 4.54 23.33
SOx 421.25 - 421.25

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Table 5-8: Projected Emissions from CNG Buses Operated by Glendale Beeline Scenario 1 Glendale Regular CNG
Emissions (MT) Upstream Tailpipe Total
GHG Emissions (metric tons per year)
CO2 247.66 2,049.86 2,297.52
CH4 6.08 6.94 13.02
N2O 0.05 0.42 0.47
Total GHGs 443.49 2,368.84 2,812.33
Criteria Pollutant Emissions (kg per year)
CO 1,147.55 47,758.68 48,906.23
NOx 1,415.27 1,304.49 2,719.76
PM10 21.84 4.02 25.86
PM2.5 16.63 8.65 25.28
SOx 372.89 - 372.89

Table 5-9: Projected Emissions from CNG buses Operated by Glendale Beeline Scenario 2 Glendale Beeline Extended
CNG Emissions Upstream Tailpipe Total
GHG Emissions (metric tons per year)
CO2 280.90 2,325.03 2,605.93
CH4 6.89 7.87 14.76
N2O 0.06 0.47 0.53
Total GHGs 503.02 2,686.83 3,189.846
Criteria Pollutant Emissions (kg per year)
CO 1,301.59 54,169.71 55,471.30
NOx 1,605.26 1,479.60 3,084.86
PM10 24.77 4.56 29.33
PM2.5 18.86 9.81 28.67
SOx 422.94 - 422.94

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Table 5-10: Projected Emissions from CNG Buses Operated by BurbankBus BurbankBus CNG Emissions
(metric tons) Upstream Tailpipe Total
GHG Emissions (metric tons per year)
CO2 75.13 621.86 696.99
CH4 1.84 2.11 3.95
N2O 0.02 0.13 0.15
Total GHGs 134.54 718.63 853.17
Criteria Pollutant Emissions (kg per year)
CO 348 14,488 14,837
NOx 429 396 825
PM10 7 1 8
PM2.5 5 1 6
SOx 113 0 113

Renewable Natural Gas (RNG)
AVTO’s transition to ZEBs will take place over time. The ICT regulation does not require AVTO to purchase buses until 2026. Since the current buses will be replaced at the end of their useful life, many ZEBs will not be deployed until long after 2026 . During this time, the traditionally powered buses will continue to produce emissions.

AVTO has options for reducing emissions before the full transition to ZEBs is complete . The transit agencies in AVTO currently purchase CNG to fuel their fleets . However, the emissions from the fleet can be reduced by using RNG . RNG is produced by capturing the methane that arises when organic waste such a s manure, compost, or food waste decomposes. Like with fossil - based natural gas, the primary component is methane (CH 4, which is itself a potent GHG). Unlike with fossil-based natural gas, RNG is not sourced from fossil fuels but from biotic material. The carbon had previously been in the atmosphere before it was sequestered, which means that it does not have a net effect of moving carbon from the ground to the atmosphere. In fact, in the ideal case, capturing and burning the methane from the decomposition of biomass could prevent methane from entering the atmosphere, thus having a beneficial effect on climate change.

RNG can be obtained through a natural gas fuel provider . When using RNG as a fuel, a fleet does not typically use RNG directly .

To obtain RNG, a fleet signs a contract with a fuel provider. The fuel provider then produces RNG and injects it into a pipeline to introduce it into the natural gas network. Gas is then drawn from the natural gas network and dispensed/sold at a fueling station.

The fleet’s use of RNG is recorded and documented. Since fuel is drawn from the natural gas network, there is no guarantee that the specific natural gas molecules that a transit agency consumes is RNG . However, emissions savings occur because the RNG injected into the network displaces regular CNG that would have been produced in the absence of the RNG contract.

RNG contracts can be signed with natural gas fuel providers. A typical contract specifies the volume of RNG that will be delivered over a specified tim e period. The purchaser of RNG can also select a carbon intensity for the RNG that will be delivered . The desired carbon intensity will determine the viable pathways that can be used to produce the RNG. Prices for fuel will depend on market conditions for RNG.

The Pasadena Department of Transportation has already transitioned to RNG. The combustion of RNG still produces tailpipe emissions. However, since RNG prevents methane, which has a high GWP value, from reaching the atmosphere , it actually produces negative upstream GHG emissions. This helps to mitigate some of the tailpipe emissions. The GREET Model was used Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-171
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to calculate the emissions produced by using RNG. The results are displayed below in Table 5-11 and Table 5-12.

Table 5-11: Projected Emissions from RNG Buses Operated by the Pasadena Department of Transportation Scenario 1

The Pasadena Department
of Tra nsportation
Scenario 1 RNG Emissions
Upstream Tailpipe Total
GHG Emissions (metric tons per year)
CO2 -1,519.75 1,630.53 110.78
CH4 10.06 5.52 15.58
N2O -0.03 0.33 0.30
Total GHGs -1,225.84 1,884.25 658.41
Criteria Pollutant Emissions (kg per year)
CO -1,017.00 37,988.89 36,971.89
NOx -277.28 1,037.64 760.36
PM10 -133.54 3.06 -130.48
PM2.5 -136.58 3.20 -133.38
SOx 1.79 - 1.79

Table 5-12: Projected Emissions from RNG Buses Operated by the Pasadena Department of Transportation Scenario 2 The Pasadena Department
of Transportation Scenario
2 RNG Emissions
Upstream Tailpipe Total
GHG Emissions (metric tons per year)
CO2 -2,158.36 2,315.73 157.37
CH4 14.28 7.84 22.12
N2O -0.04 0.47 0.43
Total GHGs -1,740.97 2,676.08 935.11
Criteria Pollutant Emissions (kg per year)
CO -1,444.37 53,953.10 52,508.73
NOx -393.80 1,473.68 1,079.88
PM10 -189.66 4.34 -185.32
PM2.5 -193.98 4.54 -189.44
SOx 2.54 - 2.54

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Battery Recycling
As vehicle electrification expands across all market segments, the demand for batteries will increase . The growth of the EV industry and parallel renewable energy sectors has contributed to an exponentially increasing demand for critical materials such as lithium, nickel, and cobalt, among others. The extraction processes for these materials have environmental and social impacts.

Furthermore, batteries degrade over time and have a finite lifespan. These factors raise questions about how to process batteries when they reach the end of their useful life and the life-cycle sustainability of this technology. As demonstrated in the Emissions Comparisons section on page 1 51, BEBs have a lower life -cycle environmental impact than CNG buses . However, there are opportunities to further improve the life-cycle environmental impact by recycling and remanufacturing the materials that have been extracted. The technological benefit of EV batteries is that many of the materials used in primary production ca n be recycled nearly an infinite number of times and retain the same level of quality or performance. This means that recycled secondary materials maintain the same characteristics and quality as raw -earth primary materials, for a fraction of the environmental, social, and economic cost. This section outlines options for recycling and reusing batteries.

Battery Recycling Companies
One of the main concerns about using battery technology is its lifecycle environmental impact . The materials that are used to produce batteries have environmental and social consequences. Furthermore, as batteries reach the end of their useful life, they produce a waste stream that has environmental ramifications . Forward thinking leaders are already developing solutions to these problems. Battery recycling companies take batteries that have reached the end of their useful life, break them down into their raw materials, and reinsert them back into the manufacturing process . These steps help to lessen the impacts of battery materials and reduces the amount of waste associated with batteries . A few companies and research teams have emerged as foundational stakeholders in battery recycling and are highlighted below.

Li-Cycle is a rapidly growing company that is focused on the mission of transforming the lithium-battery economy into a circular supply chain. Li -Cycle is based on a “Spoke & Hub” model where batteries are transformed into a static product at the Spoke facility and are then transferred to the Hubs where the cathode and anode materials are processed into battery-grade materials for remanufacturing or other applications. Once this process is completed, materials such as copper, aluminum, and ferrous metals are provided back to the commodity markets. Their technology can recycle any type of lithium-ion battery from all kinds of vehicle with any cathode chemistry, any SOC (meaning that batteries do not require discharging prior to recycling), any format (pack, module, battery, cell), and any condition (damaged/undamaged). Li -Cycle works with all sources of batteries, including but not limited to, OEMs, fleets, battery collection organizations, and refurbishment centers. To incentivize parties to collaborate in battery sourcing, Li -Cycle offers different financial models based on the percentage of battery grade materials in collected batteries. As an additional value add, Li -Cycle offers services such as replacement kit management, logistics, and witnessed destruction. In a first for the industry, Li-Cycle is in the process of building a hydrometallurgical refinery in Rochester, New York, that will be able to take lithium, cobalt, nickel, manganese, and other materials from lithium-ion batteries and produce chemicals that can be used to make new batteries. The company currently serves the North American market ( the U.S., Canada, and Mexico) and expects to serve markets outside of the continent soon. In the future, Li -Cycle plans to build out a global network of recycling and refinery facilities to create a closed loop system across all markets.

RecycLiCo is a patented process of American Manganese Inc, a critical materials and metals company. In partnership with the Department of Energy (DOE), several universities, national laboratories, and research institutes, this is a research and development project in demonstration stage that aims to target the downstream phase of battery recycling in the commercial refining process. RecycLiCo can refine materials from many types of batteries, including lithium -manganese-cobalt-oxide and lithium manganese oxide, with a focus on chemistries with the highest recovery rates. Since it is not y et a commercialized process, the team has relied upon OEMs and other battery collection organizations to send pre-shredded materials for recycling, Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-173
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but they have the goal to serve a global market in the future, with Extended Producer Responsibility legisla tion emerging in many countries. RecycLiCo seeks a holistic approach to the battery supply chain to enable localized regions to become less reliant on raw materials from faraway places and achieve higher self-sufficiency in remanufacturing and production.

Redwood Materials is a battery materials company with a major focus on recycling as an input to produce advanced battery materials domestically while mining used products to do so. Once a battery is fully recycled, the secondary materials are funneled directly back to major battery production facilities such as Panasonic and Envision AESC. While the company recycles electronics beyond the vehicle sector, it has prioritized the EV industry as one where battery recycling can make the largest impact on sustainability, economics, and supply chain resiliency. Redwood Materials currently processes approximately 45,000 vehicle batteries per year with an estimated output of 20,000 tons of material and has built partnerships with several vehicle OEMs and fleets to s ource the batteries it recycles. While the batteries they process can come from anywhere, they have strategically placed their Nevada facilities in close vicinity to the largest EV market (i.e., California) to keep the logistics, economic, and environmental footprints as small as possible—with plans to scale up in the future in areas where EVs become more prevalent.

Their process is technology agnostic, meaning that they can process all lithium -ion battery technologies, as well as are researching recycling methods for future battery technologies, such as solid state. Redwood is committed to defining pathways for closing the loop to create a circular supply chain model in collaboration with its partners with the understanding that f uture critical material supplies will face shortages and with the goal to drive down the cost of battery production in the U .S.

Second Life Batteries
Batteries used in transportation applications have a large energy storage capacity. Many BEB OEMs install batteries in excess of 300 kWh. Batteries used in EVs are typically replaced when they degrade to 80 percent capacity. While these batteries are no longer suitable for transportation applications, they still retain high energy storage capacity . As a result, these batteries can theoretically be refurbished and reused in a second-life application. A second-life battery is most suited for an application where it would undergo fewer charge/discharge cycles, such as in a stationary energy storage system or a microgrid. Once the battery degrades to the point where it can no longer serve in a stationary energy storage application, the battery can be sent to a battery recycling company for disposal.

Reusing a battery is a promising way to extend its lifespan and reduce its lifecycle enviro nmental impact. Some EV OEMs have started experimenting with repurposing retired batteries for second-life applications. Nissan and Renault have formal programs for reusing retired batteries. In addition, many of the bus OEMs are examining ways to design batteries to easily integrated into second-life applications and are exploring the possibility of selling second -life batteries . The use of second -life batteries is expected to increase in the future.

Fuel Cell Stack/Module Recycling
Similar to batteries, fuel cell manufacturers are innovating processes to optimize the usage and lifetime of the materials used in the production of fuel cell stacks and modules. Although fuel cells function like batteries in zero -emissions vehicles, they are structurally different (consisting of an anode and cathode with hydrogen being supplied to the cathode to create a flow of electricity) and do not gradually degrade over time in the same way as a battery. While there is currently not a sound business model for fuel cell second life applications, the future of recycling this hardware looks positive.

Ballard Power Systems Inc is a manufacturer of proton exchange membrane (PEM) fuel cell products for heavy -duty vehicle applications. The company supplies its FCMove module for partner transit bus OEMs New Flyer of America and ElDorado National. Ballard has operationalized its fuel cell takeback system where fleet owners assume the responsibility of returning the fuel cell module after it reaches its end of life at 20,000 -30,000 hours. Once the module is sent back to the facility, it is disassembled into individual cells where some materials can be cleaned and reused up to six more times in newly Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-174
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produced modules. A key component of the module, platinum, is almost completely recovered during this process, which helps to reduce production costs since it is the most expensive material. Research to determine how all components of the fuel cell can be either recycled or reused is under way, but there are currently very few buses at the end of life on roads since the technology is still relatively new (the average transit bus lifetime is 12 years). Once the process is fully in place, Ballard will be able to serve all its global markets and is committed to making the ir entire value chain circular, including the production of the hydrogen that is used to fuel their modules (i.e., hydrogen produced from waste streams). Additionally, Ballard is exploring requirements that will mandate their upstream suppliers to use only recyclable components to ensure smoother and more economically viable recycling options for its customers.

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Appendix A: Zero Emission Bus Specifications
Battery Electric Transit Buses (BEBs)

Proterra – ZX5 features faster acceleration, industry -leading gradeability, and a range of more than 125 miles per charge. The ZX5 has a capacity of up to 29 passengers.

Proterra ZX5

SPECIFICATIONS SPECIFICTION VALUE(S)
Passenger Capacity 29
Lift Capable Yes
Battery Size 225 kWh
Approximate nameplate single-charge range 95-125 miles Length 35 Ft
Source https://www.proterra.com/wp-
content/uploads/2021/01/Proterra-ZX5-Spec-Sheet-
35-Foot-Bus-U.S..pdf

Appendix A
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Proterra – ZX5 MAX is approximately five feet longer than the standard Proterra ZX5 bus model, which can accommodate 40 passengers and run up to 329 miles on a single charge.

Proterra ZX5 MAX

SPECIFICATIONS SPECIFICTION VALUE(S)
Passenger Capacity 40
Lift Capable Yes
Battery Size 675 kWh
Approximate nameplate single-charge range 221-329 miles Length 40 Ft
Source https://www.proterra.com/wp-
content/uploads/2021/01/Proterra-ZX5-Spec-Sheet-
40-Foot-Bus-U.S..pdf

Proterra – ZX5+ is a 35-foot bus that can run up to 240 miles on a single charge and has a capacity of up to 29 passengers.

Proterra ZX5+

SPECIFICATIONS SPECIFICTION VALUE(S)
Passenger Capacity 29
Lift Capable Yes
Battery Size 450 kWh
Approximate nameplate single-charge range 172-240 miles Length 35 Ft
Source https://www.proterra.com/wp-
content/uploads/2021/01/Proterra-ZX5-Spec-Sheet-
35-Foot-Bus-U.S..pdf

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New Flyer – XCELSIOR XE is a 35 -foot bus that can be configured to carry up to 35 passengers standing and 32 seating. The XCELSIOR has two battery options at 350 kWh and 440 kWh.

New Flyer XCELSIOR XE 35’ All-Electric Transit Bus

SPECIFICATIONS SPECIFICTION VALUE(S)
Passenger Capacity Up to 32 seats, up to 35 standees
Lift Capable Yes
Battery Size 350 kWh, 440 kWh
Approximate nameplate single-charge range 179, 220 miles Length 35 Ft
Source https://www.newflyer.com/site-
content/uploads/2021/03/Xcelsior-CHARGE-NG-
Brochure-1.pdf

New Flyer – XCELSIOR XE , a more extended version of its 35 -foot counterpart, is capable of operating with three different battery sizes (350 kWh, 440 kWh, and 525 kWh). Each battery size gives varies in range, going up to 251 miles on a single charge.

New Flyer XCELSIOR XE 40’ All-Electric Transit Bus

SPECIFICATIONS SPECIFICTION VALUE(S)
Passenger Capacity Up to 40 seats, up to 44 standees
Lift Capable Yes
Battery Size 350 kWh, 440 kWh, 525 kWh
Approximate nameplate single-charge range 174, 213, 251 miles Length 40 Ft
Source https://www.newflyer.com/site-
content/uploads/2021/03/Xcelsior-CHARGE-NG-
Brochure-1.pdf

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BYD – K9S is a 35.8-foot bus with a maximum load of 33 passengers, including the driver. The K9S can travel up to 157 miles on a single charge.

BYD K9S 35’ All-Electric Transit Bus

SPECIFICATIONS SPECIFICTION VALUE(S)
Passenger Capacity 32 + 1
Lift Capable Yes
Battery Size 266 kWh
Approximate nameplate single-charge range Up to 157 miles Length 35.8 ft
Source https://en.byd.com/bus/35-electric-transit-bus/

BYD – K9M is a 40-foot plus bus with two battery sizes, 313 kWh and 352 kWh. The passenger load varies on configuration and can comfortably sit between 38 and 43 passengers depending on the battery size. This Altoona-tested model can run up to 160 miles contingent on the battery size selected.

BYD K9M 40’ All-Electric Transit Bus

SPECIFICATIONS SPECIFICTION VALUE(S)
Passenger Capacity Up to 37+1 / Up to 42+1 MD
Lift Capable Yes
Battery Size 313 kWh / 352 kWh MD
Approximate nameplate single-charge range Up to 156 miles / Up to 160 miles MD Length 40.2 ft / 40.9 ft MD
Source https://en.byd.com/bus/40-foot-electric-transit- bus/#specs

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Fuel Cell Electric Buses (FCEBs)

New Flyer – Xcelsior Charge H2 is a battery-electric vehicle that uses compressed hydrogen as an energy source. Fuel cell-electric technology is an innovative way to obtain extended-range operation similar to existing transit vehicles with a fully zero-emission solution.

New Flyer Xcelsior Charge H2

SPECIFICATIONS SPECIFICTION VALUE(S)
Passenger Capacity Up to 40 seats / Up to 42 standees
Lift Capable Yes
Battery Size 37.5 kg
Approximate nameplate single-charge range Up to 350 miles on a single charge Length 40’
Source https://www.newflyer.com/site-
content/uploads/2021/01/Xccelsior-CHARGE-H2-
Brochure_2021.pdf

EL Dorado – AXESS FC is the only hydrogen bus in the federally certified industry for 3-point seat belts. It features a heavy-duty low floor adapted for applications such as airport shuttles and college transit. The Axess-FC offers optional ADA -compliant wheelchair ramps, has completed Altoona testing, and passed numerous side -impact and roof crush tests to ensure passenger safety.

El Dorado AXESS FC

SPECIFICATIONS SPECIFICTION VALUE(S)
Passenger Capacity 43 Max
Lift Capable Yes
Approximate nameplate single-charge range Up to 260 miles Length 40’
Source https://en.byd.com/bus/40-foot-electric-transit- bus/#specs

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Shuttle Buses/Vans

Lightning eMotors — Electric Zero -Emission Transit Passenger Van is equipped with an electric drivetrain that delivers efficiency. The Lightning Electric Transit passenger van carries up to 15 passengers and can run up to 26 0 miles on a single charge.

Ford Transit Van (Mobility
Trans) with Lightning
System

SPECIFICATIONS SPECIFICTION VALUE(S)
Passenger Capacity 15 passengers (including driver)
Lift Capable Yes
Battery Size 80 kWh/120 kWh
Approximate nameplate
single-charge range
Up to 260 miles
Source https://lightningemotors.com/wp-
content/uploads/2021/05/LeM_G4_Transit_passenger_van_sheet_May2020_v1.0_online.pdf

Lightning eMotors – Ford E-Transit is currently unavailable in the market but is expected to be commercially available in 2022.

Ford E-Transit

SPECIFICATIONS SPECIFICTION VALUE(S)
Approximate nameplate single-charge range 126 miles estimated Availability 2022
Source https://lightningemotors.com/transit-vans-ford-vs- lightning/

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Lightning eMotors — Electric Zero Emission F-550 Bus has an estimated range of over 100 miles while producing zero emissions on the road. The F-550 Bus’s charging capabilities are flexible, with Level 2 AC charging as standard and DC Fast Charging also being available, providing up to 80 kW.

Electric ZE F-550 Bus

SPECIFICATIONS SPECIFICTION VALUE(S)
Battery Size 128 kWh
Approximate nameplate single-charge range 100 miles estimated Length About 18 ft
Source https://lightningemotors.com/lightningelectric- f550/

Phoenix Motorcars — Ford E -450 Cutaway Bus: The Starcraft Allstar is powered by Phoenix Motorcars, designed to offer sustainable transportation for shared mobility and commuter transporte r. The bus features seating configurations accommodating 12-20 (14 with two-seat ADA option available). Phoenix provides a five-year/60,000 drive system and provides an extended battery warranty of 8 years/300,000 miles.

Ford E-450 Cutaway Bus (Starcraft Allstar) with Phoenix Motorcars System

SPECIFICATIONS SPECIFICTION VALUE(S)
Passenger Capacity 12-20 Passengers (14 with 2 seat ADA option) Lift Capable Yes
Battery Size 86-129 kWh
Approximate nameplate single-charge range 80-110 miles Source https://www.creativebussales.com/featured-
product--Phoenix-Motorcars

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Phoenix Motorcars – ZEUS 400 Shuttle Bus is fully customizable w ith a battery capacity of 140 kWh and a single -charge range of up to 150 miles. The ZEUS 400 is eligible for the Phoenix Motorcar’s PMC Battery Warranty of 5 Years/150,000 Miles, the PMC Drive System Warranty of 5 Years/60,000 Miles, the Bumper -to-Bumper Warranty of 3 Years/36,000 Miles, and the Body Structure Warranty of 5 Years / 100,000 Miles.

ZEUS 400 Shuttle Bus

SPECIFICATIONS SPECIFICTION VALUE(S)
Passenger Capacity Up to 23 passengers forward seating, 12/2, 14/2, 16/2 ADA
Lift Capable Yes
Battery Size 140 kWh
Approximate nameplate single-charge range 150 miles
Length 22 ft
Source https://www.phoenixmotorcars.com/products/#shuttles

US Hybrid – H2 Ride offers the H2 Ride Fuel Cell Shuttle Bus, a 22-foot vehicle, and carries up to 12 passengers (two wheelchairs) plus a driver.

US Hybrid H2 Ride Fuel Cell Shuttle Bus

SPECIFICATIONS SPECIFICTION VALUE(S)
Passenger Capacity 12
Lift Capable Yes
Length 22’

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GreenPower — EV Star is a multi-purpose, zero-emission, min-E Bus with a range of up to 150 miles and offer s dual charging capabilities as a standard feature. The EV Star can be used for paratransit, employee shuttles, micro-transit, and vanpool service.

The EV Star is the only Buy America compliant and Altoona-tested vehicle in its class.

Green Power EV Star

SPECIFICATIONS SPECIFICTION VALUE(S)
Passenger Capacity 19 FF / 21 Perimeter
Lift Capable Yes
Battery Size 118 kWh
Approximate nameplate single-charge range Up to 150 miles Length 25’
Source https://greenpowermotor.com/gp-products/ev-star/

GreenPower – EV Star+ is a cutaway bus with a broader body to utilize the interior space . It is designed for paratransit fleet operations—a larger seating capacity and whe elchair position options are available. The bus is ideal for hospitals, carpooling services, airport shuttles, and campus transportation.

Green Power EV Star+

SPECIFICATIONS SPECIFICTION VALUE(S)
Passenger Capacity 24
Lift Capable Yes
Battery Size 118 kWh
Approximate nameplate single-charge
range
Up to 150 miles
Length 25’
Availability Yes
Source https://greenpowermotor.com/gp-
products/ev-star-plus/

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Appendix B: Charging Infrastructure Specifications
The following electrical cabinets and electric vehicle supply equipment (EVSE) units were evaluated by CALSTART. A side-by-side comparison between these products, including prices, is included. The cost of the plug-in charging equipment varies depending on the manufacturer. Most plug-in chargers cost approximately $40,000 to $60,000 per bus depending on the power level. This amount includes only the cost of the charging equipment and does not include construction and installation costs, nor the cost of an overhead structure if overhead plug-in charging is deployed.

Proterra 60 kW Power Control
System

Proterra
60 kW Power Control System
Proterra is a U.S. based electric bus manufacturer that builds chargers to support its heavy-duty EV product line. Proterra’s 60 kW Power Control System is one of the most straightforward charging station solutions specifically designed for electric buses. The cabinet module (shown left) provides up to 60 kW of power to a single EVSE unit to charge a single electric bus. The ground level EVSE can be swapped out for an overhead pantograph connector for a more compact bus yard design. Depending on the bus, the battery can be completely recharged in approximately 6 hours. Manual labor is limited to plugging the EVSE into the bus in the evening after returning to the bus yard, then unplugging it in the morning prior to beginning daily revenue service. Existing examples can be seen at Greensboro Transit Authority.

Appendix B
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Proterra 125 kW Power Control
System

Proterra
125 kW Power Control System

The 125 kW Power Control System is a simple solution with twice the power of the 60 kW version . The electrical cabinet (shown left) provides up to 125 kW of power to a single EVSE unit to charge a single electric bus. The bus’s battery can be recharged in approximately three hours, which gives the fleet manager the flexibility to park two electric buses next to each other and manually transfer the plug halfway through the night.

BTC Power 100 – 350 kW
Modular High Power DC Fast
Chargers

BTC Power
100 – 350 kW Modular High Power DC Fast Chargers

Based in Santa Ana, California, BTC Power manufactures High -Performance DC Charging Systems. The electrical cabinet (which BTC calls the “Power Engine”) can provide power at 100, 150, or 200 kW. Two Power Engines can also be interconnected to deliver up to 350 kW of power to one EVSE. The EVSE itself offers two dispenser units that can power two electric buses sequentially on a first -come, first-served basis. When the first bus has completed charging, the second bus will begin charging without needing manual intervention.

BTC Power also adds smart charging software to their EVSEs with the goal of making it very easy for a network provider to integrate a data management solution into the charging station. Existing examples include Los Angeles International Airport and Porterville Transit.

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BTC Power 200 –
475 kW High
Performance DC
Charging System

BTC Power
200 – 475 kW High Performance DC Charging System
BTC Power was selected to be the sole North American provider of Porsche’s High Performance DC Charging System. Capable of delivering up to 475 kW, this design utilizes two cabinet modules: one to convert the energy from AC to DC (called a “Power Box”) and the other to provide liquid cooling to the EVSE units (called a “Cooling Box”). These cabinets connect to two EVSEs and can charge both simultaneously. Additional EVSE can be added with the inclusion of another Power Box. Generally, one cooling box can support up to three power boxes and charge six buses simultaneously at whatever power level is desired.

Like BTC’s other chargers, the High Performance DC Charging System is smart charging software capable , which makes it very easy to integrate a data management solution. At the time of this writing, there are no existing examples at a transit agency.

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ABB
HVC 150 E-Bus
Charger (NAM)

ABB
HVC 150 E-Bus Charger (NAM)
ABB is a leading EV charger manufacturer that has been building electric bus chargers in Europe for several years and is expanding operations to the United States. Manufactured in Portland, Oregon, the HVC 150 E - Bus Charger, which uses CCS1 or CCS2 connectors, can deliver 150 kW to the bus . The system utilizes one electrical cabinet to support up to three EVSE, and charges e ach one on a first -come, first serve basis. The chargers are smart enough to smoothly transfer power from one EVSE to the next when the bus is fully charged, and ABB offers additional services like remote diagnostic and management through their ABB Ability data management program. Several transit agencies, including TriMet in Portland, Oregon and Utah Transit Authority, are utilizing their chargers.

HVC150C:
• HVC150C charger with one remote depot box, 7m cables:
• HVC150C charger with two remote depot boxes, 7m cables:
• HVC150C charger with three remote depot boxes, 7m cables:
• OPTION: Pedestal for one depot box:
• OPTION: Cable management for one depot box:
• OPTION: Long distance support package:
○ Extends distance between power cabinet and remote depot box to 150M • OPTION: Robustness package:
○ Required for systems installed in harsh climates

HVC-C Depot Plug-In
HVC100C (100 kW)
• 1:1 Charger: Depot with 7M cable
• 1:2 Charger: Depot, 7M cables, sequential charging package • 1:3 Charger: Depot, 7M cables, sequential charging package

HVC100C Buy America
• 1:1 Charger: Depot with 7M cable, BAA
• 1:2 Charger: Depot, 7M cables, sequential charging package, BAA • 1:3 Charger: Depot, 7M cables, sequential charging package, BAA

HVC150C (150 kW)
• 1:1 Charger: Depot with 7M cable
• 1:2 Charger: Depot, 7M cables, sequential charging package • 1:3 Charger: Depot, 7M cables, sequential charging package

HVC150C Buy America
• 1:1 Charger: Depot with 7M cable, BAA
• 1:2 Charger: Depot, 7M cables, sequential charging package, BAA • 1:3 Charger: Depot, 7M cables, sequential charging package, BAA

Options Robustness Package
• For installation in very cold / hot climates
• Long Distance Package
• Extends distance between power cabinet and depot to 150 M • Standard without LD Package is 20 M
• Power Cabinet Metal Frame Foundation
• Depot Box Pedestal
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• Cable Management
• Standard installation is mounted on Depot Box Pedestal • Commissioning Variable dependent on site

HVC-PD Overhead Pantograph
HVC150PD (150 kW)
• Charger with pantograph mounted on ABB mast
• Charger with pantograph mountable on existing structure

HVC150PD Buy America
• Charger with pantograph mounted on ABB mast, BAA
• Charger with pantograph mountable on existing structure, BAA

HVC300PD (300 kW)
• Charger with pantograph mounted on ABB mast
• Charger with pantograph mountable on existing structure

HVC300PD Buy America
• Charger with pantograph mounted on ABB mast, BAA
• Charger with pantograph mountable on existing structure, BAA

HVC450PD (450 kW)
• Charger with pantograph mounted on ABB mast
• Charger with pantograph mountable on existing structure

HVC450PD Buy America
• Charger with pantograph mounted on ABB mast, BAA
• Charger with pantograph mountable on existing structure, BAA

Options
• Robustness Package
• For installation in very cold / hot climates
• Long Distance Package
• Extends distance between power cabinet and depot to 150 M • Standard without LD Package is 20 M
• Power Cabinet Metal Frame Foundation
• RFID Antenna Kit
• For installing pantographs in close proximity
• Commissioning Variable dependent on site

Web Tools
ABB Connected Services
• Charger Connect
• Covers costs associated with cellular network connectivity, software upgrade support, data connection to ABB • Operator Pro / EVE Platform
• Data management, reporting, charger status visibility

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Terra -
Terra HP and
Terra 54HV:

Terra
Terra HP and Terra 54HV
Terra
Budgetary numbers on Terra HP and Terra 54HV:

Terra HP 175 kW unit w 1 power cabinet and dispenser:

Terra HP 350 kW unit w 2 power cabinets and dispenser:

Terra 54HV 50 kW unit:

OPTION: Terra 54HV Cable Management

Quick budgetary numbers for our HVC150C:
• HVC150C charger with one remote depot box, 7m cables:
• Same as above, BAA:
• HVC150C charger with two remote depot boxes, 7m cables:
• Same as above, BAA:
• HVC150C charger with three remote depot boxes, 7m cables:
• Same as above, BAA

• OPTION: Pedestal for one depot box:
• OPTION: Cable management for one depot box
• OPTION: Long distance support package:
○ Extends distance between power cabinet and remote depot box to 150M • OPTION: Robustness package:
○ Required for systems installed in harsh climates

Included in above:

Project management, Engineering, Transport and packaging in continental US, on-site commissioning and start up, Charger connection fees for 2 years. 2 year warranty.

Excluded in above:

Interconnection DC cables, installation and civil works, options as listed below

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Heliox – Fast DC 150 Charger
Heliox
Fast DC 150 Charger
Heliox is a Netherlands-based EV charging infrastructure company that develops charging infrastructure for electric vehicles. Manufactured in the Netherlands, this 150 kW charger charges one vehicle on a first-come, first serve basis. Heliox also has the world’s largest opportunity and depot charge network. This charger can charge any J1772 and/or J3105 compatible truck, bus, or heavy -duty vehicle. Most of Heliox’s customers are transit agencies in Europe, but the company is expanding into the U.S. market, having recently opened a headquarters in Portland, Oregon.

ChargePoint -
Express Plus Double Stacked Power
Block

ChargePoint
Express Plus Double Stacked Power Block
ChargePoint is a San Francisco Bay Area -based electrical vehicle charging company. Founded in 2007 , it operates over 57,000 charging stations worldwide. ChargePoint has multiple models of chargers and available for passenger vehicles, buses, and trucks. The Express Plus model is designed for ultra -fast DC charging. Thanks to its flexible modular archite cture, it can expand to high charging capacity without any stranded investment by adding power modules, stations, and power blocks, per demand. Speed and dynamic power sharing are some of the many benefits of the Express Plus model.

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Siemens -
RAVE US 750V 150 kW CCS
Cascade DC

Siemens
RAVE US 750V 150 kW CCS Cascade DC
Siemens is a German -based industrial giant with a major footprint in the bus charging infrastructure industry, with multiple models of depot and on-route charging to choose from. The RAVE brand charger can provide an EV with fast and efficient charging for both depot and on -route charging whenever necessary.

Examples of usage of Siemens chargers include Metro Transit in Minneapolis, Minnesota , and TriMet in Portland, Oregon.

Sicharge UC 200
• Sicharge UC 200 power control cabinet rated at 200A, 480V input with 150kW, 100 -1,000Vdc output. Canada version will have 600Vac input. Supports up to four (4) sequential remote dispensers. Enclosure is NEMA 3R/IP54, with UL, CE, cU L certifications. Communications is OCPP 1.6 and future to OCPP 2.0 over cellular. Emergency stop is on the cabinet and the dispenser. Cabinet size is: 43.3" width x 39.4" depth x 87.0" height. Requires a concrete pad. Warranty is two years.

Sicharge UC 400
• Sicharge UC 400 is two Sicharge UC 200 power control cabinets that provide 300kW of power rated at 100 -1,00Vdc.

Supports up to four (4) sequential remote dispensers. Incoming power can be two dedicated conduit runs, one to each cabinet, or an AC Combiner Box can be used for the incoming location. This means less conduit work under the cabinets.

The outgoing DC power cabinet can also be used to simplify the installations. Enclosures are NEMA 3R/IP54, with UL, CE, cUL certifications. Communications is OCPP 1.6 and future to OCPP 2.0 over cellular. Emergency stop is on the cabinet and the dispenser (if used). Two Power Cabinets are approx. 86.7" width x 39.4" depth x 87.0" height. Height will increase if a combiner cabinet is provided. Requires a concrete pad. Warranty is two years. 200 Amp Dispenser
• Sicharge UC free-standing dispenser with one CCS1 cable and cable holder. Siemens touch screen 7" display and emergency stop button also included. NEMA 3R/IP54 rated enclosure. Unit will have communications to the power control cabinets via fiber optic or CAT5/6 copper ethernet. Warranty is two years.

BYD -
EVA100KS/02 and EVA200KS/01

BYD
EVA100KS/02 and EVA200KS/01
BYD is a Chinese automotive company known for building EVs. Their market consists of buses (transit and coach), vans, cars, and trucks. BYD also has a variety of chargers that it markets with its vehicles. All BYD EVs come with standard AC-DC Quick Charge Inverters. This makes for simplified fleet integration. BYD chargers are available in configurations from 40kW to 100kW per charging connector. Due to the proprietary design of the BYD charging connector and architecture, BYD buses can only be paired with BYD chargers. Each BYD bus comes with its own charger. Examples of usage are Antelope Valley Transit Authority (AVTA) in Lancaster-Palmdale, California.

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Blink -
DC Fast Charger

Blink
DC Fast Charger
Blink Charging is a Florida-based charging company that produces multiple lines of charging infrastructure.

Blink has a variety of business models that can work for all different types of fleets. Blink’s DC Fast Charger has a simplified 2-piece design that connects with an advanced metering infrastructure interface and smart meter capability for demand response and energy management. This charger can provide an 80 percent charge in 30 minutes (pending battery size).

Blink Charging Station Highlights:
• Blink Level 2 charging stations are currently the fastest Level 2 networked chargers on the market. • Blink Level 2 charging stations can add up to 80 miles of charge to EVs in one hour. • Blink charging stations are equipped with an easy-to-use payment processing system that can be accessed via the Blink Mobile app.
• The Blink Network offers real-time online access to revenue and usage reports. • Every Blink unit comes with a 1 year manufacturer’s warranty. • The Blink Network offers remote maintenance, software upgrade, and support capability.

Delta -
EVHU503 and EVHU104

Delta
EVHU503 and EVHU104
Delta is a Taiwan -based company that provides power and thermal solutions . Delta provides DC fast chargers and has 50 kW and 100 kW models . Their chargers are compatible with CHAdeMO and CCS -1 protocols. Delta chargers have two charging receptacles and can charge buses simultaneously . Delta also offers energy management software.

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Efacec -
HV350

Efacec
HV350
Efacec is a Portugal-based charging company that has a variety of high-power chargers, which includes 160, 175, and 350 kW models. The high-power models can charge both in a standalone mode or integrated in any network with any central system. These chargers can charge both cars and buses and has a DC output of up to 920 V. Efacec chargers can be customized with graphic, logos, and colors to cater to each specific entity brand.

Tritium -
Veefil PK

Tritium
Veefil PK
Tritium is an Australian DC fast charger manufacturer with a large global market that is partially owned by fueling infrastructure giant Gilbarco Veeder -Root. Tritium’s sophisticated modular, scalable architecture consists of three main free-standing components: a user unit that holds one or two connectors, a power unit, and a control unit. Depending on
the number of power units and user units, the system output can be scaled from 175 kW to 475 kW of power.

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WAVE – Inductive Charger

WAVE
Inductive Charger
WAVE delivers fast, safe, high -power charging within seconds of scheduled stops and natural dwell times.

Medium- and heavy-duty EVs gain substantial range and operation time without manual plug-in operations or mechanical contact. With power ranging from 125kW to 500kW and higher, WAVE’s high-power systems are ideal for powering EVs for mass transit, warehouse and distribution centers, shuttle services, seaports, and more.

What is commercially available today is a 250 -kW charger that can supply power in va rious configurations; where power is split down to two (2) 125 kW chargers and soon split to four (4) 62.5 kW plates with smart charging for the depot.

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Clipper Creek – CS-100, 70/80 Amp
(Selectable) EVSE, 240V, with 25 ft
cable

Clipper Creek
CS-100, 70/80 Amp (Selectable) EVSE, 240V, with 25 ft cable The CS 100 is the world's first UL listed EV charging station manufactured in the United States. The CS-100 is a UL Listed Level 2 EVSE offering 19.2 kW for EV charging. The CS -100 works with all SAEJ1772 compliant vehicles. This charger is ideal for vehicles that can accept high power charging, and future proofing installations.

This is the recommended charger for charger for the GreenPower and Phoenix Motorcars buses.

• 208V to 240V - 100 Amp Branch Circuit (70/80 Selectable Amps continuous) • 25 foot charging cable
• Rugged, fully sealed NEMA 4 for installation indoors or outdoors • Automatic circuit reclosure after minor power faults
• Cold Load Pickup: Time-delayed and randomized to allow seamless re-energizing of unit following power outages • External Control Input: Allows external control from smart meter (AMI), billing or load management device • UL Listed
• ETL LISTED

Compatible Accessories:
• The Wall Mount Retractor from ClipperCreek is the ideal solution for sites that need cable management, keeping charging cables off the ground and vehicle connectors protected.

Compatible Mounting Solutions:
• CS Pedestal (0300-00-015)
• EVSE Size Comparison Chart (click to view larger)

Charging Power
• 70/80 Amp Selectable (19.2kW max)
Product Dimensions
• 17” W x 22” H x 12” (mounting holes 16” on center)
Product Weight
• 36 lbs
Installation
• Hardwired
Supply Circuit
• 208/240V, 100A
Warranty
• 1 year
Charge Cable Length
• 25 feet (22 feet usable)
Vehicle Connector Type
• SAE J1772
Accessories Included
• Connector Lock & Keys
Enclosure
• Fully Sealed NEMA 4
Environment Rating
• Indoor and Outdoor
Operating Temperature
• -22°F to 122°F (-30°C to +50°C)
Certifications
• UL, cULus, ETL, cETLus
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Appendix C: Hydrogen Fueling Infrastructure Specifications If a transit agency opts to transition to an FCEB fleet, they will need to install hydrogen fueling infrastructure . Typical hydrogen fueling infrastructure includes a compressor, hydrogen storage tanks, and a hydrogen dispenser . In addition, either on-site hydrogen production equipme nt or infrastructure to accept delivered hydrogen is required . This section provides an overview of the market for hydrogen fueling infrastructure.

NEL Hydrogen offers reliable, cost -efficient electroly zers and is recognized as an industry leader of Alkaline and PEM water electrolysis. Their water electroly zers make a superior choice for Industry, Transport and Power -to-X applications. Multiple, scalable, flexible, modular product ranges are set to meet any customer requirements. The H2Station® is the new generation fast 70MPa fueling of Fuel Cell Electric Vehicles (FCEV).

Compared with its market-leading predecessor, CAR-100, fueling capacity is up three times – at one third of the space – enabling installation at even compact gas stations. The peak rush-hour capacity of up to 100 kg in three hours, allows a flexible scaling of capacity as demand grows. Storage can be dimensioned to address a fueling demand of up to 500 kg per day for cars, up to 1500 kg per day for buses, trucks, and any hydrogen supply c onfiguration. Consider their compact and user -friendly hydrogen dispenser for fueling of both 35 and 70 MPa vehicles from a H2Station™.

One H2 is emerging as a leader in providing scalable hydrogen fuel systems coupled with cost effective delivered hydrogen fuel for use in industrial vehicle and truck markets. Their holistic, end- to-end solution guarantees the production, delivery, and monitoring of zero -emission hydrogen fuel. The hydrogen fuel dispenser is manufactured and designed in -house and made of durable stainless-steel construction with a 15+ year life. The dispenser has 350 bar or 700 bar refueling options along with various safety features, such as a flame detector gas sensor e -stop on dispenser with secondary reset safety relays (inside cabinet).

Bayotech is a full-service hydrogen supplier, offering localized production, transport, storage and fueling solutions. Their expanded product line now includes hydrogen dispensing equipment and zero-emission fuel cell power generators and light towers. The MicroPak Series of multi -cylinder trailers with 350 bar/5075 psig cylinders is designed primarily for hydrogen, helium, and air. The smallest MicroPak trailer weighs less than 1,000lbs which allows for a non -HazMat licensed driver to haul it, while the Gas Transp ort Series allows for gas storage that can be towed with a standard sized pick-up truck. Cylinders can range from 3,600 psig to 7,500 psig and can incorporate gas specific accessories, such as a heated regulator system (hrs -2) for CNG, booster pumps for CNG

Appendix C
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refueling and defueling, and pressure reduction systems for other gases. Customers pay for fuel by the kilogram and choose from multiple modes of supply. Advantages include minimal capital investment in infrastructure, short term contracts and flexibility to meet fluctuating demands. BayoTech produces the hydrogen locally and distributes to nearby consumers via three- times more efficient high -pressure transport trailers. Avoiding long transportation distances saves money while minimizing carbon intensity.

Air Products is the world’s largest supplier of merchant hydrogen and a leader in hydrogen fuel infrastructure. Their SmartFuel® technology brings safe, reliable, and cost -effective hydrogen to hydrogen -powered applications around the world. On-site generation of hydrogen is an alternative to delivered product and offers customers a unique way to supply their fueling station. Two technologies are available: methane reformers and electrolyzers. Air Products' PRISM® hydrogen generators are steam methane re formers that use a highly efficient, robust process that minimizes operating costs. PRISM hydrogen generators are designed to supply fueling stations up to 1,800 kgs per day. The hydrogen purity from these generators will meet the stringent requirements of fuel cell applications. Their SmartFuel® portable fueling units provide totally self - contained hydrogen dispensing capabilities with zero -emissions and no utility hook -ups. The fueling station holds up to 150 kg of hydrogen and can be used for both short - and long-term deployments. A familiar hose -and-nozzle dispenser automatically fills the vehicle’s fuel cell with hydrogen gas at a pressure of ~5,000 psi (350 bar). These stations have been deployed in numerous locations around the world and can be delive red to customers with very short lead -times. It provides a highly reliable, cost - effective, automated capability at the convenience of your location.

Air Liquide has been developing unique expertise in the mastery of the entire hydrogen chain (production , storage, and distribution) for more than 40 years. In the U.S., Air Liquide will utilize an innovative pathway for hydrogen sourcing at the Braintree, Massachusetts hydrogen fueling station using a water electrolysis system , Proton On- site PEM electrolysis, to generate on-site produced hydrogen. Their stations can fill the fuel tanks of vehicles with hydrogen stations ranging from 35mpa up to 70mpa. Air Liquide offers a range of standardized or tailor -made products and solutions to meet specific needs. Th ey have supplied a hydrogen station in Oslo, Norway, to recharge five buses operated by a Norwegian transportation company, and another one in Aargau, Switzerland, where the local authorities also operate five buses. At this point, 100 hydrogen stations have been designed and built by Air Liquide around the world.

Linde has established a leading position in the H2 fueling space and is particularly renowned for its high -performance technologies to refuel fuel -cell vehicles, and is also offering more and mo re concepts for green hydrogen. Multiple Ionic Compressors from Linde are available for refueling, each one compressing the gaseous H2 to the 350 -bar pressure required for the buses and to 700 bar for passenger cars. This combined bus/car fueling station can serve up to 15 buses and numerous cars. The station’s carbon footprint is neutral, since it generates hydrogen using three electrolyzers powered by energy from certifiable renewable sources for zero emissions from source to service. Their compression technologies are at the heart of every H2 fueling station. Ionic technology is used to compress gaseous H2 to up to 100 MPa and the cryopump efficiently supplies hydrogen in liquid form ready for refueling. Linde has already built over 190 H 2 fueling station s around the world and in San Francisco, C alifornia. Linde is leading the way in sustainable production of H2 through its joint venture in ITM Linde Electrolysis, the cutting edge of electrolysis technologies.

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Appendix D: Managed Charging Solutions

Networked or managed charging is helpful as it allows transit agencies to minimize their peak power demand. This helps to lower utility costs for transit agencies and helps utilities manage the grid. Networked and managed chargi ng is typically a separate service from the physical hardware of the EVSE and electrical cabinets. Companies that specialize in this space call themselv es “Electric Vehicle Service Providers” or simply “network providers.” However, unlike the EVSEs , there are a small, but growing, number of companies that focus on charging heavy -duty vehicles, like electric buses . This section provides an overview of networked charging companies.

I/O Control Corporations offers software to inform smart systems, including remote monitoring, analytics, and prioritizing charging on specific buses. Their Electrical Load Management System (ELMS) product offering is a cloud-based application that enables remote electric bus charging management across multiple depot locations. It allows transit operators to set up their preferred parameters so that buses can be charged automatically according to specific schedules and vehicle limits. I/O Controls supplies a charging control gateway for each charging station. The pricing for the g ateway includes a monthly fee for the first year with a 1 year warranty, and the transit entity is charged a yearly fee for the hardware for subsequent years of use. Currently, the ELMS and charging gateway combination is only offered for charging of BYD b uses but I/O Controls can work with other vehicle manufacturers to make their hardware and software compatible with other bus technologies. I/O Controls also offers a Health Alert Management System (HAMS) which is currently being used by Antelope Valley Transit Authority in Lancaster, C alifornia. This operating system functions as a control for how much power a particular bus draws from the grid. The HAMS features AIMS (Alert, Inquire, Manage, Store) functionality. The Alert function sends a tex t or email m essage when there is an issue with the vehicle’s charge cycle or during regular route service. The Inquire feature monitors the health status of the vehicle such as SOC, mileage, battery voltage, and other parameters and is updated once per minute. The Man age feature uses cloud-based software to maintain and edit information provided by the HAMS module. The Store feature allows for unlimited data uploads to the cloud for future use and analytics.

Appendix D
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ViriCiti is a trusted solution for over 350+ operators worldwide and offers a system that is integrated with over 50 OEMs. The company is known for its telematic data logging system for buses on the road, but also offers solutions for managing electric bus chargers through their Charger Monitoring an d Smart Charging packages . Both of these systems are OCPP compliant and OEM agnostic, meaning they support open standards and can communicate with a variety of charging station and vehicle types. No additional hardware is needed to monitor the chargers if they are OCPP1.6 compliant or higher. The first package offers a single dashboard view for easy visualization of vital Key Performance Indicators (KPIs) (e.g., charger status and location, connected vehicle ID and SOC, energy consumption, etc.) which serves to quickly identify and troubleshoot bugs, increase EVSE uptime, and reduce maintenance time and costs. Their new Depot View product provides a visual overview of the vehicle and chargers in the fleet’s depot. It shows which vehicles are connected to whi ch chargers and their remaining SOC. Depot View also shows the status of the chargers (available, busy, faulted). ViriCiti’s data management solution can track EVSE performance and enable smart charging capabilities. Viriciti’s smart charging systems allow for fleet -wide management of charging through scheduled load balancing and can provide benefits like peak shaving, demand response, and renewables integration . Their system can also be used to track fleet data like battery SOC, bus energy efficiency, and bus downtime. ViriCiti offers modular based license subscriptions which allows customers to customize and only pay for the features they need. Licensing is offered per charger socket on a yearly subscription basis. The average cost of charger monitoring is $18 per socket/month and the average cost for smart charging is $25 per socket/month (as of Summer 2021). The ViriCiti team offers 24/7 customer support . ViriCiti was purchased by ChargePoint, which is a charging infrastructure provider, in August 2021.

Greenlots (a member of the Shell Group) is another network provider that specializes in smart charging and fleet scheduling
services. Greenlots provides a turnkey solution for EV charging , which includes a site evaluation, hardware procurement and valid ation, engineering and construction services, and operation and maintenance services. Greenlots works closely with Shell’s Solutions Development team to provide battery systems that integrate with charging stations to provide additional microgrid and energy management solutions. Their Greenlots SKY EV Charging Network Software offers real-time network management and status of EV chargers, a variable pricing engine which can set pricing based on usage, time intervals, or sessions, and a billing and payment m anagement system through the Greenlots mobile app or charging station. Additionally, the SKY EV system provides access to advanced analytics and customizable reporting with alerts to improve EVSE uptime and access to data such as revenue, energy delivered, and avoided CO2 emissions. The SKY EV system utilizes the OCPP standard and features a multi - layer security system to protect sensitive data. In addition to EVSE manufacturer hardware warranties, Greenlots offers a quality assurance program called “Greenl ots Care” which provides trained technicians to make on-site repairs within 24 -48 hours as well as a supplemental parts warranty to ensure a charger uptime guarantee of 95 percent. Other included services are preventative and corrective maintenance, warranty management, reporting, and performance SLAs. Finally, Greenlots offers a Charging-as-a-Service package, which is based on a recurring annual fee which aims to reduce steep upfront costs for the fleet customer. Greenlots is currently working with Foothill Transit on their electric buses.

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Electriphi is a wholly owned subsidiary of Ford Motor Company that offers end-to-end fleet electrification solutions including charging management and infrastructure deployment. Electriphi works alo ngside fleets to simplify EV management and ease the transition from conventional to electric fleets through planning, deployment assistance, and ongoing operational services. On the implementation side, Electriphi offers testing and integration services for vehicle telematics systems prior to service deployment at the customer site. Their monthly software-as- a-service (SaaS) monitoring and management system tracks charging station status, network connectivity, and equipment fault detection, as well as offers sophisticated smart charging algorithms that ensures that vehicles are charged on time at the most optimal energy cost (while taking into account vehicle dispatch schedules, route information, TOU energy rates, demand charge windows, and more). Customers may purchase a baseline operational charging system for remote fleet control and data access and may add on managed/smart charging features which can be accessed from the same online dashboard. Electriphi also offers advanced energy services such as ESS system integration, active demand response, and V2G management. Electriphi’s software compatibility is constantly evaluated based on current market offerings and is suitable for use with most major EV charging equipment manufacturers for both Level 2 and L evel 3/DCFC stations. Pricing is available as an upfront, non-recurring cost or a yearly SaaS fee.

The Mobility House is a network provider that serves over 350 fleets and offers charging system management software
called ChargePilot. Their software helps transit agencies engage in peak shaving and schedule charging to reduce demand charges . While their system does not connect to onboard vehicle telematics, it is compliant with multiple EVSEs at once, yielding high interoperability. To keep the fleet charged when vehicles need to be deployed and to optimize costs, the system monitors the bus SOC while plugged into the charger and calculates charge times and duration based on site-specific electricity rates. The fleet only has to supply the desired departure time and desired SOC per vehicle, and the system coordinates the rest via a local controller that is instal led on-site and is c onnected to all the chargers. Mobility House is able to assist fleets with the charger procurement process to ensure that they are OCPP compliant, and therefore ChargePilot compliant, before purchase and installation. ChargePilot can also take solar resour ces and distributed generation assets into account when managing charging by integrating the data from renewables on-site into the system operations. Mobility House offers a hybrid business model with a one time setup cost per site which includes hardware installation and commissioning, and then operates its software service on a monthly, yearly, or multi-year subscription basis according to the customer’s business needs and plans. The pricing is project and volume - dependent with flexibility to operate on a Charging-as-a-Service (per mile) system. As part of this package, Mobility House provides 24/7 monitoring on all sites with quick alerts and remote fixes in the case that there is a system failure. Mobility House offers a complimentary demonstration works hop for interested customers to help calculate an individual fleet’s cost savings with their managed charging solution.

Burbank City CouncilJuly 25, 2023

Burbank City Council
July 25, 2023