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

Amply (owned by BP) offers smart charging services for transit fleets and beyond through power demand services, telematics, schedul ed maintenance, and battery SOC monitoring. They work with the existing infrastructure to add charging capacity by analyzing the electrical capacity and redesigning the depot layout. Amply’s system integrates with onboard vehicle telematics to coordinate a nd manage the charging stations on schedules based on available electricity and bus SOC. They offer various payment mechanisms based on the customer’s need, such as a monthly licensing fees per charger or an energy-as-a-service per kWh model. Amply also offers charging infrastructure installation with the necessary electrical equipment to connect the systems and capital expenditures can be bundled into their Charging-as-a-Service (CaaS) solution. Their Pantograph In -Depot Equipment, or PIDE Canopy Mount, Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-201
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allows for overhead DC fast chargers to be installed to solar canopies, which can greatly optimize depot space and the use of solar energy. Pricing is customized to each fleet’s needs and varies based on numerous factors such as combined grants to offset costs, utility partnerships, and energy rates per utility. Amply works with EVSE OEMs to develop hardware agnostic warranties and the software includes a triage system to alert fleet operators of any potential issues before a contracted service technician is deployed to repair the system.

Proterra provides electric buses but also provides fleet planning and EV charging services. Through a turnkey solution, Proterra can provide an “energy delivery system” that offers a comprehensive solution for establishing EV infrastructure. This includes smart energy management, and electrical utility make-ready.

AmpUp is a software company and network provider for smart charge scheduling, dynamic access control, and energy optimization built into one platform. Their mobile app software was originally founded to offer peer-to-peer shared charging to increase charger access in residential areas and decrease the cost to EV owners. They have since expanded their product to include a solution for commercial entities and various customer types. All the charge management is facilitated through OCPP which allows the software to communicate with the hardware and means that the AmpUp solution is brand agnostic. The software determines when a charging station is on or offline, when it will become available, and when the plugged-in vehicle will charge based on customized pricing preferences. AmpUp’s service is offered on a monthly or yearly software subscription basis with an additional per vehicle cost for an added telematics bundle , which offers an integration with their partner’s (Smartcar) system. In California, AmpUp will also assist with fleet financing ROI by redeeming carbon credits on behalf of the customer and passing it along to them. The AmpUp system will pass on station d ata to the third-party carbon credit processor who will prepare and submit the required paperwork in order to receive the credit payment. These credits can be returned to the customer via check or can be directly put back into their AmpUp portal towards vehicle charge management expenses.

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Appendix E: Energy Storage Options

Tesla – Megapack: A 1 Gigawatt hour (GWh) project provides record energy capacity —enough to power every home in San Francisco for six hours. Every Megapack arrives pre-assembled and pre-tested in one enclosure from our Gigafactory—including battery modules, bi-directional inverters, a thermal management system, an AC main breaker and controls.

Tesla Megapack

SPECIFICATIONS SPECIFICTION VALUE(S)
Max Energy Capacity 3 MWh
Technology Lithium-ion
Inverter Capacity 1.5 MW
Connection AC output interface
Dimensions (L x W) 23 ft 5 in x 5 ft 3 in (7.14 m x 1.60 m) Size 250 MW, 1 GWh power plant per 3 acre
Weight 51,000 lbs
Source https://www.tesla.com/megapack

Appendix E
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BYD – Utility ESS: BYD mainly provides two kinds of indoor/outdoor solutions for on -grid, off-grid, and hybrid use. BYD energy storage systems can be fit for various needs based on its flexible and modular design.

BYD Utility ESS

SPECIFICATIONS SPECIFICTION VALUE(S)
Max Energy Capacity 250kW/1MWh
500kW/1MWh
1MW/1MWh

1.8MW/800kWh
Technology Lithium-ion Iron-Phosphate
Connection AC output & DC input interface
Size 40ft Container
Source https://en.byd.com/energy/utility-ess/

LG – ESS: LG Chem’s L&S (Lamination & Stacking) process minimizes dead space, enables higher energy density, and enhances the sustainability of cell structures. LG Chem’s SRS® (Safety Reinforced Separator) increases the mechanical and thermal stability of battery cells.

LG Energy Storage System
(ESS)

SPECIFICATIONS SPECIFICTION VALUE(S)
Max Energy Capacity 6.8MWh
Technology Lithium-ion
Voltage Flexibility 14 Modules
(~800V)
17 Modules
(~1000V)
24 Modules
(~1500V)
Connection AC/DC Panel
Energy Flexibility 1) 25.8in
2) 37.4in
3) 47.2in
Size 40ft HC ISO Enclosure with HVAC
Grid Scale Energy
JH3, JH4
• Duration for ≥ 1 hour
• Continuous power supply
Power
JP3
• Duration for < 1 hour
• High power supply
Source https://www.lgessbattery.com/us/grid/intro.lg

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NGK Insulators – NAS Battery Cell: The NAS battery system is designed to easily expand the capacity as much as needed in one site or several separate sites. The scalability of NAS installation to many tens or hundreds of MW for durations of six to seven hours is at a scale that can defer or eliminate some transmission, distribution and generation investments especially when used in association with variable renewables for a clean solution.

NGK NAS Battery
System

SPECIFICATIONS SPECIFICTION VALUE(S)
Energy Density 367 Wh/l
222 Wh/kg per battery cell
Power Density 36 W/kg per battery cell
Technology Sodium-sulfur
Voltage 2V per battery cell
Connection PCS (AC/DC power conversion system)
C-Rate 1/6 = 0.17 per battery cell
Dimensions (L x W) 9cm x 50 cm per battery cell
Weight 5 kg per battery cell
Size Up to 50MW, 300MWh
Source https://www.ngk-insulators.com/en/product/nas-
about.html

NGK Insulators – NAS Container Type Unit: The NAS battery system is a "Plug and Play" design built around standard 20 -foot ocean freight containers. The containerized design expedites transportation and installation and helps minimize installation costs.

NGK NAS Battery
Container Type Unit

SPECIFICATIONS SPECIFICTION VALUE(S)
Rated Output 800 kW and 4,800 kWh

Configuration Four container subunits, series connected.

A subunit includes six NAS modules, each rated at
33 kW and 200 kWh
Dimension (W x D x H) 6.1 x 5.6 x 5.5 m
Weight 86 tonnes
Source https://www.ngk-insulators.com/en/product/nas-
configurations.html

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NGK Insulators – NAS Package Type Unit: The enclosure package and battery modules are installed on site. This design achieves more compact system comparing with containerized design.

NGK NAS Battery
Package Type Unit

SPECIFICATIONS SPECIFICTION VALUE(S)
Rated Output 1,200kW and 8,640kWh
Configuration 40 NAS modules,
each rated at 30kW and 216kWh
Dimension (W x D x H) 10.2 x 4.4 x 4.8 m
Weight 132 tonnes
Source https://www.ngk-insulators.com/en/product/nas-
configurations.html

NEC - GBS-C53-LD40: Long-Duration (LD) Grid Battery Systems NEC - GBS-C53-LD40

SPECIFICATIONS SPECIFICTION VALUE(S)
Energy Storage 4 MWh
Power Rating 4 MW
Technology Nanophosphate® lithium ion battery
DC Voltage 944V nominal (750V – 1050V DC operating range) Connection 50Hz or 60Hz connection frequency options
Optional step-up transformer to MV AC output
480VAC output (typical)
DC Efficiency 97% (C/2 rate)
Dimensions (LxWxH) 53’ x 8.5’ x 9.5’
(16.2m x 2.6m x 2.9m)
Mass 140,000 lbs
Source http://www.cls-
energy.com/files/nec_grid_brochure.pdf

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NEC - GBS-C40-LD28: Long-Duration (LD) Grid Battery Systems

NEC - GBS-C40-LD28

SPECIFICATIONS SPECIFICTION VALUE(S)
Energy Storage 2.8 MWh
Power Rating 2.8 MW
Technology Nanophosphate® lithium ion battery
DC Voltage 944V nominal (750V – 1050V DC operating range) Connection 50Hz or 60Hz connection frequency options
Optional step-up transformer to MV AC output
480VAC output (typical)
DC Efficiency 97% (C/2 rate)
Dimensions (LxWxH) 40’ x 8.5’ x 9.5’
(12.2m x 2.6m x 2.9m)
Mass 100,000 lbs
Source http://www.cls-
energy.com/files/nec_grid_brochure.pdf

NEC - GBS-C20-LD12: Long-Duration (LD) Grid Battery Systems

NEC - GBS-C20-LD12

SPECIFICATIONS SPECIFICTION VALUE(S)
Energy Storage 1.2 MWh
Power Rating 1.2 MW
Technology Nanophosphate® lithium ion battery
DC Voltage 944V nominal (750V – 1050V DC operating range) Connection 50Hz or 60Hz connection frequency options
Optional step-up transformer to MV AC output
480VAC output (typical)
DC Efficiency 97% (C/2 rate)
Dimensions (LxWxH) 20’ x 8.5’ x 9.5’
(6.1m x 2.6m x 2.9m)
Mass 47,000 lbs
Source http://www.cls-
energy.com/files/nec_grid_brochure.pdf

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NEC - GBS-C53-HR20: High-Rate (HR) Grid Battery System

NEC - GBS-C53-HR20

SPECIFICATIONS SPECIFICTION VALUE(S)
Energy Storage 575kWh
Power Rating 2 MW
Technology Nanophosphate® lithium ion battery
DC Voltage 960V nominal (750V – 1050V DC operating range) Connection 50Hz or 60Hz connection frequency options
Optional step-up transformer to MV AC output
480VAC output (typical)
DC Efficiency 96% (1C rate)
Dimensions (LxWxH) 53’ x 8.5’ x 9.5’
(16.2m x 2.6m x 2.9m)
Mass 64,000 lbs
Source http://www.cls-
energy.com/files/nec_grid_brochure.pdf

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Saft – Intensium® Max 20 High Energy: Initially developed for grid installations, Intensium® Max brings rail energy -efficiency and smart-grid technologies to an aging transport infrastructure and has the potential to transform the relationship between the transport and energy industries.

Saft – Intensium®
Max 20 High Energy

SPECIFICATIONS SPECIFICTION VALUE(S)
Energy Storage 2.5 MWh
Storage Capacity 420 kWh
Voltage (V) 1000 V Class
811
1500 V Class
1216
Technology Lithium-ion
Peak Charge 1.5 MW
Battery System 1000 V Class
9 Energy Storage System Units (ESSU)
14 battery modules in series
One Battery Management Module (BMM)
1500 V Class
6 Energy Storage System Units (ESSU)
21 battery modules
One Battery Management Module (BMM)
Dimensions (LxWxH) w/o HVAC 6.1 x 2.4 x 2.9

Size 20 ft container
Weight <30 tons
Source https://www.saftbatteries.com/products-
solutions/products/intensium%C2%AE-max-
efficient-trackside-energy-storage

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Samsung – E3-M123: To maximize economics and efficiency , the high efficiency battery solution minimizes power loss by enabling high power output and minimizes total footprint by reducing footprint of PCS and battery systems.

Samsung – E3-M123

SPECIFICATIONS SPECIFICTION VALUE(S)
Energy Storage 6.0MWh
Cell Capacity 111 Ah
Technology
Energy 12.3 kWh
Operating Voltage 96-126 V
Dimension (W x D x H) 344 x 160 x 1,012 mm
Weight 90 kg
Size 40 ft container
Source http://www.samsungsdi.com/upload/ess_brochure/201803_SamsungSDI%20ESS_E N.pdf

Samsung – E3-R135: To maximize economics and efficiency, the high efficiency battery solution minimizes power loss by enabling high power output and minimized total footprint by reducing footprint of PCS and battery systems.

Samsung – E3-R135

SPECIFICATIONS SPECIFICTION VALUE(S)
Energy Storage 6.0MWh
Cell Capacity 111 Ah
Energy 135 kWh
Technology
Operating Voltage 1,056~1,386 V
Dimension (W x D x H) 415 x 1,067 x 2,124 mm
Weight 1,170 kg
Size 40 ft container
Source http://www.samsungsdi.com/upload/ess_brochure/201803_SamsungSDI%20ESS_E N.pdf
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Kokam by SolarEdge – KCE (Kokam Containerized ESS) 20ft.: In addition to offering customers a wide range of standard battery solutions, Kokam also works with customers to create customized solutions to address their unique needs.

Compared to general system, Kokam's system saves 70 percent of power consumption.

Kokam by SolarEdge – KCE
(Kokam Containerized ESS)
20ft

SPECIFICATIONS SPECIFICTION VALUE(S)
Energy Storage 1MWh
System Configuration 1 Bank
Technology
Bank Configuration 10 Racks (2C5R)
Installed Energy Natural Air Cooling Forced Air Cooling Nominal Voltage 1,516kWh 1,516kWh
Operating Voltage Range 736Vdc 736Vdc
Max. Charge Power 670 ~ 826Vdc 670 ~ 826Vdc
Peak Discharge Power 1,516kW (1P) 1,516kW (1P)
Max. Discharge Power 3,032kW (2P) 4,548kW (3P)
Round Trip DC Efficiency 1,516kW (1P) 2,880kW (1.9P)
Size 20 ft container
Source https://kokam.com/ess-solution

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Kokam by SolarEdge – KCE (Kokam Containerized ESS) 40ft.: KCE racks have an extremely compact design (Max.194.3kWh per Rack) with parallel connection up to 1MWh~10MWh. They accommodate user -specific energy and voltage requirements and are equipped with multiple layers of safety mechanisms.

Kokam by SolarEdge - KCE
(Kokam Containerized ESS)
40ft

SPECIFICATIONS SPECIFICTION VALUE(S)
Energy Storage 2MWh
System Configuration 2 Bank
Technology
Bank Configuration 13 Racks (2C5R)
Installed Energy Natural Air Cooling Forced Air Cooling Nominal Voltage 3,942kWh 3,942kWh
Operating Voltage Range 736Vdc 736Vdc
Max. Charge Power 670 ~ 826Vdc 670 ~ 826Vdc
Peak Discharge Power 3,942kW (1P) 3,942kW (1P)
Max. Discharge Power 7,884kW (2P) 11,826kW (3P)
Round Trip DC Efficiency 3,942kWh 5,518kW (1.4P)
Size 40 ft container
Source https://kokam.com/ess-solution

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Hitachi ABB – Battery Energy Storage System PQpluS™: PQpluS™ is available in a wide range of power and energy ratings, making it the right choice for end users, system integrators, and aggregators, as well as users with the right control system for utility scale applications. In addition to functions like peak shav ing and power quality, PQpluS™ can be mana ged by third party controller to perform site energy management, integration of renewables, and grid services.

Hitachi ABB – Battery Energy
Storage System PQpluS

SPECIFICATIONS SPECIFICTION VALUE(S)
Energy Storage 68.5 kWh per rack
Electrical Grid Connection 380 VAC-415 VAC 50/60 Hz
Electrical Rated Output 30 kW / 68.5 kWh
Inverter Rated Power (at 400 V) 30 kW per module
Technology Lithium-ion based on NMC technology
Min 30 kW power & 68.5 kWh
energy to max 360 kW &411
kWh
rated system
• 2 x PQstorI (30kW each) inverter and 1 x battery
rack: 60 kW (max) and 68.5 kWh (max)
• 9 x PQstorI (30kW each) inverter and 4 x battery
racks: 270 kW (max) and 274 kWh (max)
Power/ energy requirement
above 360 kW/ 411 kWh
• Up to 32 x PQstorI inverters: max power 960 kW
• Up to 14 x battery racks: max energy 960 kWh
Multiple modules of inverters/ batteries can
operate in parallel to build storage capacity up to

1.6 MW/ 2.2 MWh. For example, a 960 kW/ 1100
kWh rated PQpluS require the following modules:
• Inverter modules: 32 modules of 30 kWh PQstorI
• Battery modules: 2 off 8 x battery racks
Weight 562 kg
Source https://www.hitachiabb-powergrids.com/offering/product-and- system/energystorage/pqplus

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Hitachi ABB – e-mesh™ PowerStore™: Hitachi ABB Power Grids e -meshTM PowerStoreTM is a scalable microgrids and energy storage solution that is designed to ensure reliable power availability, grid stability, highest possible penetration of renewable energy together with an intelligent control system for both grid-connected and off-grid systems. e-mesh™ PowerStore™ is available in two variants, Integrated and Modular, for installations across utilities, remote communities, independent power producers, commercial, and industrial establishments.

Hitachi ABB – e-mesh™
PowerStore™:

SPECIFICATIONS SPECIFICTION VALUE(S)
Energy Storage 50kW, 250kW, up to MW scale
Variants Integrated and Modular
Source https://www.hitachiabb-powergrids.com/offering/solutions/grid-edge- solutions/our-offering/e-mesh/powerstore

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Appendix F: The Pasadena Department of Transportation Route Modelling Results

Note: For the buses that did not go to the maximum number of laps, an estimate was taken from the lap(s) that was closest to the appropriate time of day. The red cell highlight denotes the lap where the bus drops below 20 percent SOC. The worst-case scenarios were modeled, with peak summer temperatures or 120F.

Table F-1: The Pasadena Department of Transportation Route 10 Modelling Results

Lap OEM 1 (kWh/lap) OEM 2 (kWh/lap) OEM 3 (kWh/lap)
1 14.75 22.71 15.88
2 15.97 23.57 17.1
3 17.9 23.57 19.03
4 19.5 24.21 20.63
5 20.92 24.21 22.05
6 22.05 25.12 23.18
7 22.91 25.76 24.04
8 23.55 25.76 24.68
9 23.55 25.76 24.68
10 24.46 25.35 25.59
11 25.1 25.35 26.23
12 25.1 24.07 26.23
13 24.69 22.69 25.82
14 23.41 22.69 24.54
15 22.04 20.63 23.16
16 19.97 20.63 21.1
17 18.75 19.41 19.88
Total 364.62 401.49 383.82
Route 10

Appendix F
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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

Lap OEM 1 (kWh/lap) OEM 2 (kWh/lap) OEM 3 (kWh/lap)
1 18.63 19.45 20.34
2 20.57 21.39 22.27
3 22.17 22.99 23.87
4 23.58 24.4 25.28
5 24.71 25.53 26.42
6 25.57 26.39 27.28
7 27.12 27.94 28.83
8 27.76 28.58 29.47
9 27.76 28.58 29.47
10 27.36 28.17 29.06
11 26.07 26.89 27.78
12 24.7 25.52 26.4
13 22.63 23.45 24.34
Total 318.63 329.28 340.81
Route 20
Lap OEM 1 (kWh/lap) OEM 2 (kWh/lap) OEM 3 (kWh/lap)
1 26.91 23.11 24.35
2 28.04 25.05 26.29
3 28.9 26.65 27.89
4 29.55 29.19 30.43
5 30.45 30.05 31.29
6 31.09 30.7 31.94
7 31.09 31.6 32.84
8 30.69 32.24 33.48
9 29.4 31.84 33.07
10 28.03 30.55 31.79
11 25.96 29.18 30.42
12 24.74 27.11 28.35
Total 344.85 347.27 362.14
Route 31/32
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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

Lap OEM 1 (kWh/lap) OEM 2 (kWh/lap) OEM 3 (kWh/lap)
1 20.13 21.1 21.93
2 22.06 23.04 23.87
3 23.67 24.64 25.47
4 25.08 26.05 26.88
5 26.21 27.18 28.02
6 27.07 28.04 28.87
7 28.62 29.59 30.42
8 29.26 30.23 31.06
9 29.26 30.23 31.06
10 28.85 29.83 30.66
11 27.57 28.54 29.37
12 26.2 27.17 28
13 24.13 25.1 25.93
Total 338.11 350.74 361.54
Route 40
Lap OEM 1 (kWh/lap) OEM 2 (kWh/lap) OEM 3 (kWh/lap)
1 23.34 24.6 27.21
2 25.28 26.53 29.14
3 26.88 28.13 30.74
4 28.29 29.55 32.16
5 29.42 30.68 33.29
6 30.28 31.54 34.15
7 31.83 33.09 35.7
8 32.47 33.73 36.34
9 32.47 33.73 36.34
10 32.06 33.32 35.93
11 30.78 32.04 34.65
12 29.41 30.66 33.28
13 27.34 28.6 31.21
Total 379.85 396.2 430.14
Route 51/52
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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

Lap OEM 1 (kWh/lap) OEM 2 (kWh/lap) OEM 3 (kWh/lap)
1 15.39 16.21 17.1
2 16.84 17.66 18.55
3 18.04 18.86 19.75
4 19.95 20.77 21.66
5 20.6 21.41 22.3
6 21.08 21.89 22.79
7 21.76 22.57 23.46
8 22.24 23.05 23.94
9 21.93 22.75 23.64
10 20.97 21.79 22.68
11 19.94 20.76 21.65
12 18.39 19.21 20.1
Total 237.13 246.93 257.62
Route 60
Lap OEM 1 (kWh/lap) OEM 2 (kWh/lap) OEM 3 (kWh/lap)
1 33.15 34.84 40.8
2 36.17 37.86 43.82
3 39.13 40.82 46.78
4 41.17 42.86 48.82
5 42.83 44.52 50.48
6 43.55 45.24 51.2
7 43.2 44.88 50.84
8 40.62 42.31 48.27
Total 319.82 333.33 381.01
Route 177
Lap OEM 1 (kWh/lap) OEM 2 (kWh/lap) OEM 3 (kWh/lap)
1 59.15 61.91 70.99
2 63.59 66.35 75.43
3 66.65 69.41 78.49
4 69.14 71.9 80.99
5 70.22 72.98 82.07
6 69.69 72.45 81.53
7 65.83 68.59 77.67
Total 464.27 483.59 547.17
Route 256
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Table F-9: The Pasadena Department of Transportation Route 88 Modelling Results

Table F-10: The Pasadena Department of Transportation Route H Modelling Results

Lap OEM 1 (kWh/lap) OEM 2 (kWh/lap) OEM 3 (kWh/lap)
1 20.95 21.99 24.44
2 22.15 23.19 25.64
3 23.21 24.25 26.7
4 24.06 25.1 27.55
5 25.18 26.22 28.68
6 25.86 26.9 29.36
7 26.34 27.38 29.84
8 26.34 27.38 29.84
9 26.04 27.08 29.53
10 25.07 26.12 28.57
Total 245.2 255.61 280.15
Route 88
Lap OEM 1 (kWh/lap) OEM 2 (kWh/lap) OEM 3 (kWh/lap)
1 16.1 16.73 18.48
2 16.67 17.3 19.06
3 17.12 17.75 19.51
4 17.12 17.75 19.51
5 17.48 18.11 19.86
6 17.96 18.58 20.34
7 17.96 18.58 20.34
8 18.32 18.94 20.7
9 18.32 18.94 20.7
10 18.14 18.76 20.52
11 18.14 18.76 20.52
12 17.51 18.14 19.89
13 16.85 17.48 19.23
Total 227.69 235.82 258.66
Route H
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Table F-11: The Pasadena Department of Transportation Route 51/52S Modelling Results

Lap OEM 1 (kWh/lap) OEM 2 (kWh/lap) OEM 3 (kWh/lap)
1 23.34 24.6 27.21
2 26.88 28.13 30.74
3 28.29 29.55 32.16
4 30.28 31.54 34.15
5 30.93 32.18 34.79
6 32.47 33.73 36.34
7 32.47 33.73 36.34
8 32.06 33.32 35.93
9 29.41 30.66 33.28
10 27.34 28.6 31.21
Total 293.47 306.04 332.15
Route 51/52S
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Appendix G: Pasadena Department of Transportation Service Changes

Route 20 is an example of a route where the number of buses that need to be deployed can be red uced by redistributing some of the laps in a more equitable manner . If this is done, the BEBs can serve as a drop -in replacement for all OEMs . Table G-1 below provides an energy analysis if the laps are more equitably distributed between the buses.

Table G-1: Route 20 Energy Analysis with Redistributed Laps Route Bus # of Laps OEM 1 OEM 2 OEM 3
20CW 1 9 222.99 241.07 249.03
2 9 222.99 241.07 249.03
3 10 233.35 253.43 262.28
4 9 210.32 228.39 233.22
5 5 101.16 116.8 121.25
20CC 1 11 258.23 280.32 290.05
2 8 180.61 196.67 203.75
3 9 222.99 241.07 249.03
4 8 185.44 201.5 208.58
5 5 101.17 127.03 131.44

Route 31/32 is a route where the number of laps each bus performs is distributed inequitably . Some of the buses on this route are not able to serve as a drop -in replacement and the modelling indicates that two of the buses will return to the depot with less than 10 percent SOC. Redistributing the laps would beneficial as it would reduce the energy requirements for some buse s.

Due to scheduling issues, the ability to redistribute laps between buses is very limited . However, if redistribution occurs, it reduces the amount of laps that the most active bus must perform. This redistribution is not enough to make both of these buses drop-in replacements. However, it does reduce the laps that one of the buses will have to perform, which opens up the possibility of the route becoming a drop-in replacement in the future with advances in technology. See Table G-2 below for this analysis.

Appendix G
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Table G-2: Route 31/32 Energy Analysis with Redistributed Laps Route Bus # of Laps OEM 1 OEM 2 OEM 3
31/32 1 11 320.13 324.17 337.79
2 10 294.17 290.99 303.37
3 11 317.97 339.23 357.84
4 2 54.95 48.16 50.64

Route 51/52 is another route where the number of buses required can be reduced by redistributing some of the laps in a more equitable manner. If this is done, the BEBs can serve as a drop-in replacement for all OEMs. Table G-3 below provides an energy analysis if the laps are more equitably distributed between the buses.

Table G-3: Route 51/52 Energy Analysis with Redistributed Laps Route Bus # of Laps OEM 1 OEM 2 OEM 3
51/52 1 7 216.37 225.16 243.44
2 6 165.55 175.75 191.42
3 7 191.31 204.11 222.39
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Appendix H: City of Glendale Route Modelling Results
Note: For the buses that did not go to the maximum number of laps, an estimate was taken from the lap(s) that was closest to the appropriate time of day . The red cell highlight denotes the lap where the bus drops below 20 percent SOC. The worst-case scenarios were modeled, with peak summer temperatures or 120F.

Scenario 1
Table H-1: Glendale Beeline Scenario 1 Route 1 Modelling Results

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Table H-2: Glendale Beeline Scenario 1 Route 3 Modelling Results

Table H-3: Glendale Beeline Scenario 1 Route 4 Modelling Results

Lap OEM 1 (kWh/lap) OEM 2 (kWh/lap) OEM 3 (kWh/lap)
1 37.91 39.73 41.35
2 45.16 46.99 48.6
3 50.53 52.36 53.97
4 53.81 55.64 57.25
5 57.07 58.89 60.5
6 57.07 58.89 60.5
7 53.56 55.39 57
8 46.6 48.43 50.04
Total 401.71 416.32 429.21
Route 3
Lap OEM 1 (kWh/lap) OEM 2 (kWh/lap) OEM 3 (kWh/lap)
1 14.08 14.56 14.69
2 16.29 16.76 16.89
3 18.11 18.59 18.72
4 21.03 21.51 21.63
5 22 22.47 22.6
6 22.7 23.18 23.3
7 23.67 24.14 24.27
8 24.32 24.8 24.92
9 23.81 24.29 24.41
10 22.33 22.81 22.93
11 20.75 21.23 21.36
Total 229.09 234.34 235.72
Route 4
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Table H-4: Glendale Beeline Scenario 1 Route 5 Modelling Results

Table H-5: Glendale Beeline Scenario 1 Route 6 Modelling Results

Lap OEM 1 (kWh/lap) OEM 2 (kWh/lap) OEM 3 (kWh/lap)
1 8.75 9.13 9.23
2 9.57 9.95 10.04
3 10.88 11.26 11.35
4 11.97 12.35 12.44
5 11.97 12.35 12.44
6 12.94 13.32 13.41
7 13.71 14.1 14.19
8 14.3 14.69 14.78
9 14.73 15.12 15.21
10 14.73 15.12 15.21
11 15.32 15.71 15.8
12 15.73 16.11 16.2
13 15.73 16.11 16.2
14 15.43 15.82 15.91
15 15.43 15.82 15.91
16 14.55 14.93 15.02
17 13.61 14 14.09
18 12.22 12.61 12.7
Total 241.57 248.5 250.13
Route 5
Lap OEM 1 (kWh/lap)OEM 2 (kWh/lap)OEM 3 (kWh/lap)
1 9.45 15.08 10
2 10.33 15.08 10.89
3 11.76 14.37 12.32
4 12.94 13.65 13.5
5 13.99 12.94 14.55
6 13.99 12.23 14.55
7 14.83 12.23 15.39
8 15.47 11.51 16.02
9 15.93 10.8 16.49
10 16.57 10.09 17.13
11 17 9.37 17.56
12 17 9.32 17.56
13 17 9.32 17.56
14 16.68 9.32 17.24
15 15.72 9.76 16.28
16 14.7 10.31 15.26
17 13.2 10.31 13.75
Total 246.56 195.69 256.05
Route 6
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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

Lap OEM 1 (kWh/lap) OEM 2 (kWh/lap) OEM 3 (kWh/lap)
1 24.19 25.25 25.44
2 30 31.07 31.25
3 34.26 35.33 35.51
4 36.81 37.87 38.06
5 38.28 39.34 39.53
6 39.31 40.37 40.56
7 38.61 39.68 39.86
8 34.21 35.27 35.46
Total 275.67 284.18 285.67
Route 7
Lap OEM 1 (kWh/lap) OEM 2 (kWh/lap) OEM 3 (kWh/lap)
1 15.18 15.86 16.63
2 17.09 17.77 18.54
3 18.68 19.36 20.13
4 20.1 20.78 21.55
5 21.25 21.93 22.7
6 22.13 22.8 23.57
7 22.78 23.46 24.23
8 23.66 24.34 25.11
9 24.28 24.96 25.73
10 24.28 24.96 25.73
11 23.87 24.54 25.31
12 22.58 23.25 24.03
13 21.21 21.89 22.66
Total 277.09 285.9 295.92
Route 8
Lap OEM 1 (kWh/lap) OEM 2 (kWh/lap) OEM 3 (kWh/lap)
1 18.31 18.88 18.98
2 22.23 22.8 22.9
3 24.87 25.44 25.53
4 26.87 27.44 27.53
5 27.67 28.24 28.34
6 27.13 27.7 27.79
Total 147.08 150.5 151.07
Route 12
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Scenario 2:

Table H-10: Glendale Beeline Scenario 2 Route 1 Modelling Results

Table H-11: Glendale Beeline Scenario 2 Route 3 Modelling Results

Lap OEM 1 (kWh/lap) OEM 2 (kWh/lap) OEM 3 (kWh/lap)
1 9.78 10.21 10.3
2 10.74 11.17 11.26
3 12.27 12.71 12.8
4 13.55 13.98 14.07
5 14.68 15.11 15.21
6 15.59 16.02 16.11
7 16.27 16.7 16.79
8 16.27 16.7 16.79
9 16.77 17.2 17.29
10 17.45 17.88 17.97
11 17.91 18.35 18.44
12 17.91 18.35 18.44
13 17.56 18 18.09
14 16.53 16.96 17.06
15 15.43 15.86 15.96
16 15.43 15.86 15.96
17 13.8 14.24 14.33
18 12.83 13.26 13.36
19 12.38 12.81 12.9
20 11.92 12.36 12.45
21 11.47 11.9 12
Total 306.54 315.63 317.58
Route 1
Lap OEM 1 (kWh/lap) OEM 2 (kWh/lap) OEM 3 (kWh/lap)
1 35.49 37.31 38.93
2 41.86 43.68 45.3
3 48.12 49.95 51.56
4 52.4 54.22 55.83
5 55.71 57.53 59.14
6 57.07 58.89 60.5
7 56.23 58.05 59.66
8 50.74 52.56 54.18
9 44.05 45.87 47.49
10 41.51 43.33 44.94
Total 483.18 501.39 517.53
Route 3
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Table H-12: Glendale Beeline Scenario 2 Route 4 Modelling Results

Lap OEM 1 (kWh/lap) OEM 2 (kWh/lap) OEM 3 (kWh/lap)
1 14.08 14.56 14.69
2 16.29 16.76 16.89
3 18.11 18.59 18.72
4 19.73 20.21 20.34
5 21.03 21.51 21.63
6 22 22.47 22.6
7 22.7 23.18 23.3
8 24.32 24.8 24.92
9 24.32 24.8 24.92
10 23.81 24.29 24.41
11 22.33 22.81 22.93
12 20.75 21.23 21.36
13 18.41 18.89 19.02
14 17.02 17.5 17.63
15 16.38 16.86 16.98
16 15.74 16.21 16.34
Total 317.02 324.67 326.68
Route 4
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Table H-13: Glendale Beeline Scenario 2 Route 5 Modelling Results

Lap OEM 1 (kWh/lap) OEM 2 (kWh/lap) OEM 3 (kWh/lap)
1 8.75 9.13 9.23
2 9.57 9.95 10.04
3 10.88 11.26 11.35
4 11.97 12.35 12.44
5 11.97 12.35 12.44
6 12.94 13.32 13.41
7 13.71 14.1 14.19
8 14.3 14.69 14.78
9 14.3 14.69 14.78
10 14.73 15.12 15.21
11 15.32 15.71 15.8
12 15.73 16.11 16.2
13 15.73 16.11 16.2
14 15.73 16.11 16.2
15 15.43 15.82 15.91
16 14.55 14.93 15.02
17 13.61 14 14.09
18 13.61 14 14.09
19 12.22 12.61 12.7
20 11.39 11.78 11.87
21 11 11.38 11.47
22 11 11.38 11.47
23 10.61 10.99 11.08
24 10.21 10.6 10.69
Total 309.26 318.49 320.66
Route 5
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Table H-14: Glendale Beeline Scenario 2 Route 6 Modelling Results

Table H-15: Glendale Beeline Scenario 2 Route 7 Modelling Results

Lap OEM 1 (kWh/lap) OEM 2 (kWh/lap) OEM 3 (kWh/lap)
1 9.45 9.87 10
2 10.33 10.76 10.89
3 11.76 12.19 12.32
4 12.94 13.37 13.5
5 12.94 13.37 13.5
6 13.99 14.42 14.55
7 14.83 15.26 15.39
8 15.47 15.9 16.02
9 15.47 15.9 16.02
10 15.93 16.36 16.49
11 16.57 17 17.13
12 17 17.43 17.56
13 17 17.43 17.56
14 17 17.43 17.56
15 16.68 17.11 17.24
16 15.72 16.15 16.28
17 14.7 15.13 15.26
18 14.7 15.13 15.26
19 13.2 13.62 13.75
20 12.29 12.72 12.85
21 11.87 12.3 12.43
22 11.87 12.3 12.43
23 11.45 11.88 12
24 11.02 11.45 11.58
Total 334.18 344.48 347.57
Route 6
Lap OEM 1 (kWh/lap) OEM 2 (kWh/lap) OEM 3 (kWh/lap)
1 24.19 25.25 25.44
2 30 31.07 31.25
3 34.26 35.33 35.51
4 36.81 37.87 38.06
5 39.31 40.37 40.56
6 39.31 40.37 40.56
7 38.61 39.68 39.86
8 34.21 35.27 35.46
9 28.83 29.9 30.08
10 26.87 27.94 28.12
Total 332.4 343.05 344.9
Route 7
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Table H-16: Glendale Beeline Scenario 2 Route 8 Modelling Results

Table H-17: Glendale Beeline Scenario 2 Route 12 Modelling Results

Lap OEM 1 (kWh/lap) OEM 2 (kWh/lap) OEM 3 (kWh/lap)
1 15.18 15.86 16.63
2 17.09 17.77 18.54
3 18.68 19.36 20.13
4 20.1 20.78 21.55
5 21.25 21.93 22.7
6 22.13 22.8 23.57
7 22.78 23.46 24.23
8 23.66 24.34 25.11
9 24.28 24.96 25.73
10 24.28 24.96 25.73
11 23.87 24.54 25.31
12 22.58 23.25 24.03
13 21.21 21.89 22.66
14 19.2 19.88 20.65
15 17.98 18.66 19.43
16 17.39 18.06 18.84
17 16.8 17.47 18.24
Total 348.46 359.97 373.08
Route 8
Lap OEM 1 (kWh/lap) OEM 2 (kWh/lap) OEM 3 (kWh/lap)
1 18.31 18.88 18.98
2 22.23 22.8 22.9
3 24.87 25.44 25.53
4 26.87 27.44 27.53
5 27.67 28.24 28.34
6 27.13 27.7 27.79
Total 147.08 150.5 151.07
Route 12
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Appendix I: BurbankBus Route Modelling Results
Note: For the buses that did not go to the maximum number of laps, an estimate was taken from the lap(s) that was closest to the appropriate time of day. The red cell highlight denotes the lap where the bus drops below 20 percent SOC. The worst-case scenarios were modeled, with peak summer temperatures or 120F.

Table I-1: BurbankBus Green Route Modeling Results

Lap OEM 1 (kWh/lap) OEM 2 (kWh/lap)OEM 3 (kWh/lap)
1 9.53 10.66 11.51
2 9.92 11.05 11.9
3 10.51 11.64 12.49
4 10.74 11.87 12.72
5 11.05 12.18 13.03
6 11.24 12.37 13.22
7 11.38 12.51 13.36
8 11.38 12.51 13.36
9 11.05 12.18 13.03
10 10.78 11.91 12.76
Total 107.58 118.88 127.38
Green Route

Appendix I
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Table I-2: BurbankBus Orange Route Modeling Results

Table I-3: BurbankBus Pink Route Modeling Results

Lap OEM 1 (kWh/lap) OEM 2 (kWh/lap) OEM 3 (kWh/lap)
1 13.76 14.85 15.39
2 15.95 17.04 17.58
3 16.82 17.91 18.45
4 18.07 19.16 19.7
5 19.05 20.14 20.68
6 19.46 20.55 21.09
7 19.46 20.55 21.09
8 18.43 19.52 20.06
9 17.58 18.67 19.21
10 15.56 16.65 17.19
Total 174.14 185.04 190.44
Orange Route
Lap OEM 1 (kWh/lap) OEM 2 (kWh/lap) OEM 3 (kWh/lap)
1 21.17 22.99 25.84
2 24.04 25.86 28.72
3 25.2 27.03 29.88
4 26.91 28.74 31.59
5 28.3 30.12 32.97
6 28.9 30.72 33.58
7 28.9 30.72 33.58
8 27.56 29.39 32.24
9 26.46 28.28 31.13
10 23.8 25.63 28.48
Total 261.24 279.48 308.01
Pink Route
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Appendix J: Resiliency Methodology

To analyze resiliency solutions, CALSTART used the MDT . MDT allows users to input relevant site-specific characteristics like energy consumption (including time of use), power demand load schedules, frequency of outages and grid failures, and solar energy production potential. Users also select what types of DERs can be included in the energy po rtfolio and input equipment characteristics like estimated capital expenditures and fuel utilization rates . Once this data is input into the model, the user can specify performance objectives that the resiliency measures are intended to achieve . MDT then provides quantitative analysis to determine feasible designs that can meet all of the performance objectives . MDT assumes that there are tradeoffs between the different design objectives. For example, increasing the reliability and time that the microgrid can operate involves installing additional generation and storage assets, which increases the cost. To balance these tradeoffs, MDT’s algorithms create a Pareto frontier to optimize performance of the design parameters . It then recommends designs on the Pareto frontier that are able to meet all of the design parameters.

CALSTART's MDT model optimized for several criteria. The first criteria was capital expenditures and aimed to design a microgrid at the lowest cost possible. The second criteria was energy availability, or the percentage of the load’s needs that can be provided by the resiliency assets. For BurbankBus, the resiliency measures were designed to serve bus charging only. The energy portfolio was designed to attain a minimum energy availability of 95 percent. MDT was also programmed to maximize the use of solar energy. Only designs that can meet all of these parameters are considered viable.

MDT was also programmed to consider a variety of microgrid components . MDT was programmed to consider solar panels and battery storage as power sources. The software was also programmed to consider natural gas turbines.

The assumptions programmed into MDT are shown in Tables J-1 and J-2:

Appendix J
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Table J-1: MDT Assumptions for Renewable Energy Sources Renewables Costs
Carport Solar Cost $1.72 per W dc (Feldman, 2021)
Battery Cost (installed, including balance of system) $469/kWh (Feldman, 2021) Battery Maintenance Cost 2.5% of battery cost over life of the battery (W. Cole, 2020)

Table J-2: MDT Assumptions for Generators
Generators Costs (Ericson, 2019)
Diesel Generator (CAPEX, installed) $800/kW
Diesel Generator Maintenance Costs $35/kW/year
Diesel Fuel Costs $4/gallon
Diesel Generator Startup Success Rate 94.7%
Natural Gas Generator (CAPEX, installed) $1000/kW
Natural Gas O&M Costs $35/kW/year
Natural Gas Fuel Costs $0.70/therm
Natural Gas Generator Reliability 97.3%
Natural Gas Storage Tank $100,000 (U.S. DOE, 2014)

CALSTART also provided analysis about resiliency systems that provide resiliency using 100 percent renewable energy . This option would entail using on-site solar and storage. NREL’s REopt Lite tool was used to provide this analysis . NREL’s REopt Lite tool allows users to input site -specific information, which can be included in the analysis . REopt Lite was used to calculate the required specifications of a solar and storage system that can provide 100 percent resiliency to the fleet during a seven -day outage. REopt Lite then provided the required size of the PV system and required the power capacity and energy storage capacity of the battery that would be required to provide full resiliency.

Once these outputs were provided, the required physical footprint of the solar PV system was calculated . NREL’s PVWatts tool uses the following formula to calculate the required solar PV array area that is required:

𝑆𝑖𝑧𝑒 (𝑘𝑊) = 𝐴𝑟𝑟𝑎𝑦 𝐴𝑟𝑒𝑎 (𝑚2) 𝑥 1 𝑘𝑊
𝑚2 𝑥 𝑀𝑜𝑑𝑢𝑙𝑒 𝐸𝑓𝑓𝑖𝑐𝑖𝑒𝑛𝑐𝑦 (%)

This analysis assumed that solar PV modules have an efficiency of 19 percent.

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Appendix K: The Pasadena Department of Transportation
Conceptual Framework and Supporting Documents
Figure K-1: Pasadena Department of Transportation Single-Line Diagram

Appendix K
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Figure K-2: The Pasadena Department of Transportation Design Memo

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Appendix L: City of Glendale Conceptual Design and Supporting Documents
Figure L-1: Glendale Beeline Conceptual Design and Single-Line Diagram

Appendix L
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Figure L-2: Glendale Beeline Design Memo

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Appendix M: BurbankBus Conceptual Design and Supporting Documents
Figure M-1: BurbankBus Site 1 Conceptual Design and Single-Line Diagram

Appendix M
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Figure M-2: BurbankBus Site 2: Conceptual Design and Single-Line Diagram

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Appendix N: Cost Estimates Methodology
When developing the cost estimates in this report, CALSTART considered several factors. CALSTART’s projections modeled the costs that will be incurred between 2021 and 2040. The projections divided costs into two categories: capital expenditures and operational expenditures. Capital expenditures consist of one-time expenses that are required to obtain buses and equipment .

The capital expenditures that were considered in the cost estimates include the cost of transit and shuttle buses, driver and maintenance training, charging/fueling infrastructure, utility infrastructure (for BEB cost estimates only), and resiliency assets (for BEB cost estimates only). Operational expenditures represent ongoing costs associated with running the fleet. This includes bus maintenance costs, infrastructu re maintenance, and utility/fueling costs. Operational expenditures also include major midlife repairs to the buses. For CNG buses, this would include the cost of replacing the engine. This is assumed to occur in year six of bus operations. For BEBs and FC EBs, this would include the cost of replacing the battery or fuel cell midway through the life of the bus. BEB and FCEB manufacturers offer an extended warranty that covers the battery or fuel cell system for the entire lifetime of the bus (12 years/500,00 0 miles). The cost of the extended warranty was used as the midlife replacement cost for ZEBs. CALSTART provided cost comparisons for scenarios where each transit agency deploys a fully CNG, BEB, and FCEB fleet.

CNG fleet cost estimate assumptions are described in Table N-1.

Table N-1: CNG Fleet Cost Estimates Assumptions:

Expense Assumptions
Transit Buses (including equipment like farebox,
security cameras, etc.)
$650,000
Shuttle Buses (including equipment like farebox,
security cameras, etc.)
$180,000
Driver and Maintenance Training $0 (Not required for CNG buses) CNG Fueling Infrastructure $0 (Assuming that each transit agency uses existing CNG fueling stations and infrastructure)
Bus Maintenance $0.23/mile
CNG/RNG Fuel Costs Based on historical CNG/RNG bills for each transit fleet Transit Bus Mid-life Engine Replacement $47,000 (CARB, 2018) Shuttle Bus Mid-life Engine Replacement $21,000 (CARB, 2018a)

The assumptions for the cost estimates for a BEB fleet are based on plug-in charging. According to these scenarios, the buses will be charged overnight and will not use any on-route charging. The cost estimates also assume that the buses will be deployed according to the fleet replacement plan. Table N-2 explains the assumptions that were used for each of these expenses:

Appendix N
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Table N-2: BEB Fleet Cost Estimates Assumptions:

Expense Assumptions
Transit Buses Averaged cost of the transit bus OEMs (according to the statewide contracts) + $30,000 for cost of auxiliary equipment (farebox, security cameras, etc.)
Shuttle Buses Averaged cost of the shuttle bus OEMs + $30,000 for cost of auxiliary equipment (farebox, security cameras, etc.)
Driver and Maintenance Training Costs according to the statewide contracts Charging Infrastructure See Charging Infrastructure Cost Estimates section on page 245.

Utility Infrastructure Estimates based on interviews with municipal utilities Resiliency Assets See assumptions in Appendix J: Resiliency Methodology
Bus Maintenance $0.48/mile
Infrastructure Maintenance $1,500 per charging cabinet (Johnson, 2020) Utility Costs Based on utility cost estimates provided for each transit agency. Utility costs were assumed to scale
linearly as buses are deployed.

Mid-life Battery Replacement Average cost of the extended warranty for the battery (12 years/500,000 mile warranty)

The assumptions for the cost estimates for a n FCEB fleet are based on the cheapest method of hydrogen production for each agency. The cost estimates also assume that the buses will be deployed according to the fleet replacement plan . Table N-3 explains the assumptions that were used for each of these expenses.

Table N-3: FCEB Fleet Cost Estimates Assumptions:

Expense Assumptions
Transit Buses Averaged cost of the transit bus OEMs (according to the statewide contracts) + $30,000 for cost of auxiliary equipment (farebox, security cameras, etc.)
Shuttle Buses Averaged cost of the shuttle bus OEMs + $30,000 for cost of auxiliary equipment (farebox, security cameras, etc.)
Driver and Maintenance Training Costs according to the statewide contracts Hydrogen Fueling Infrastructure See Hydrogen Fueling Infrastructure Cost Estimates section on page 246.

Bus Maintenance $0.56
Infrastructure Maintenance The HDRSAM Model estimates the operation and maintenance cost for the hydrogen station.

Hydrogen Costs See Table N-11
Mid-life repairs Average cost of the extended warranty for the fuel cell system (12 years/500,000 mile warranty)

Charging Infrastructure Cost Estimates
CALSTART calculated the costs associated with deploying bus chargers. To deploy charging infrastructure, upgrades must be made to the depot. This can include the installation of electrical components like transformers and electrical panels. It als o includes trenching and the installation of conduit and wires . It can also include the installation of safety equ ipment like wheel Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-259
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stops and bollards. Table N-4 outlines the cost assumptions associated with each type of upgrade.

Table N-4: Charging Infrastructure Equipment Cost Assumptions Equipment Unit Cost Source
1500 kVA Utility Transformer $92,000 NREL Distribution System Upgrade Cost Database (Horowitz, 2019)
Main Disconnect $12,500 NREL Distribution System Upgrade Cost Database
Meter $6,000 Southern California Edison (SCE,
2021)
Automatic Transfer Switch $43,000 Average of prices from automatic transfer switch distributors
Panel Board $3,000 Average of prices from panel board
distributors
225 kVA Transformer $53,000 NREL Distribution System Upgrade Cost Database
Transit Bus Chargers (per bus) $35,000-$45,000 Average of prices from transit bus charger manufacturers
Shuttle Bus Chargers (per bus) $3,000 Average of prices from shuttle bus charger manufacturers
Bollards $800 DOE Costs Associated With Non-
Residential EVSE (U.S. DOE, 2015)
Wheel Stops $100 DOE Costs Associated With Non-
Residential EVSE
Trenching (per foot) $150 DOE Costs Associated With Non- Residential EVSE

The conceptual designs were used to identify the equipment that is required to install charging infrastructure on each site . This information was used to estimate the cost of equipment. According to the DOE, equipment costs are typically 35 percent of the total installed cost (U.S. DOE, 2015). The equipment costs were adjusted by this factor to determine total installed cost. These figures do not include resiliency. The assumptions for determining the cost of resiliency are outlined in Appendix I.

Table N-5: Charging Infrastructure Cost Estimates
Transit Agency Estimated Charging Infrastructure Cost
The Pasadena Department of Transportation $6,600,000
City of Glendale $6,000,000
BurbankBus $3,000,000

Please note that these cost estimates in Table N-5 are for budgetary purposes only and are based on high -level conceptual designs. The actual cost of charging infrastructure will depend on market conditions at the time of construction. Full engineering documents and cost estimates should be developed before issuing a n RFP for this project.

Hydrogen Fueling Infrastructure Cost Estimates
CALSTART calculated the costs associated with deploying hydroge n fueling infrastructure . The capital expenditures associated with deploying hydrogen infrastructure consists of the cost of a hydrogen fueling station and the cost of hydrogen production equipment. CALSTART used Argonne National Laboratory’s HDRSAM to cal culate the cost of a fueling station . HDRSAM allows users to input parameters for a hydrogen station. CALSTART produced fuel station cost estimates for several scenarios including on-site hydrogen production via SMR, on-site hydrogen production via electro lysis, delivered gaseous hydrogen, and delivered liquid hydrogen. CALSTART customized the parameters based on the needs of each individual fleet . Tables N-6 to N-8 outline Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-260
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the parameters used for each of these scenarios.

Table N-6: On-site Hydrogen Production HDRSAM Assumptions Parameter The Pasadena
Department of
Transportation
The City of Glendale BurbankBus
Station Type Gaseous Hydrogen Gaseous Hydrogen Gaseous Hydrogen Hydrogen Source 20 bar H2 supply 20 bar H2 supply 20 bar H2 supply Fleet Size (buses being
fueled per day)
31 buses 36 buses 17 buses
Dispensing Options 350 bar Cascade
dispensing
350 bar Cascade
dispensing
350 bar Cascade
dispensing
Production Volume Mid Mid Mid
Assumed Start-up Year 2027 2023 2027
Construction Period 1 year 1 year 1 year
Analysis Period 20 years 20 years 20 years
Max Dispensed Hydrogen
per Vehicle
25 kg 25 kg 25 kg
Fueling Rate 3.6 kg/minute 3.6 kg/minute 3.6 kg/minute
Vehicle Lingering Time 2 minutes 2 minutes 2 minutes
Number of Dispensers 2 2 2
Maximum Number of Fills
per Hour
6 6 4

Table N-7: Delivered Gaseous Hydrogen HDRSAM Assumptions Parameter The Pasadena
Department of
Transportation
Glendale Beeline BurbankBus
Station Type Gaseous Hydrogen Gaseous Hydrogen Gaseous Hydrogen Hydrogen Source Tube-Trailer Supply Tube-Trailer Supply Tube-Trailer Supply Fleet Size (buses being
fueled per day)
31 buses 36 buses 17 buses
Dispensing Options 350 bar Cascade
dispensing
350 bar Cascade
dispensing
350 bar Cascade
dispensing
Production Volume Mid Mid Mid
Assumed Start-Up Year 2027 2023 2027
Construction Period 1 year 1 year 1 year
Analysis Period 20 years 20 years 20 years
Max Dispensed Hydrogen
per Vehicle
25 kg 25 kg 25 kg
Fueling Rate 3.6 kg/minute 3.6 kg/minute 3.6 kg/minute
Vehicle Lingering Time 2 minutes 2 minutes 2 minutes
Number of Dispensers 2 2 2
Maximum Number of Fills
per Hour
6 6 4

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Table N-8: Delivered Liquid Hydrogen HDRSAM Assumptions Parameter The Pasadena
Department of
Transportation
Glendale Beeline BurbankBus
Station Type Gaseous Hydrogen Gaseous Hydrogen Gaseous Hydrogen Dispensing Option 350 bar via vaporization
and compression
350 bar via vaporization
and compression
350 bar via vaporization
and compression
Fleet Size (buses being
fueled per day)
31 buses 36 buses 17 buses
Dispensing Options 350 bar Cascade
dispensing
350 bar Cascade
dispensing
350 bar Cascade
dispensing
Production Volume Mid Mid Mid
Assumed Start-up Year 2027 2023 2027
Construction Period 1 year 1 year 1 year
Analysis Period 20 years 20 years 20 years
Max Dispensed Hydrogen
per Vehicle
25 kg 25 kg 25 kg
Fueling Rate 3.6 kg/minute 3.6 kg/minute 3.6 kg/minute
Vehicle Lingering Time 2 minutes 2 minutes 2 minutes
Number of Dispensers 2 2 2
Maximum Number of Fills
per Hour
6 6 4

All other parameters in the model that were not listed in Table N-6 to N-8 were set to the default values.

Table N-9: Fueling Station Costs
Hydrogen Pathway The Pasadena
Department of
Transportation
Glendale Beeline BurbankBus
On-site SMR $3,411,019 $3,575,972 $2,510,361
On-site Electrolysis $3,411,019 $3,575,972 $2,510,361
Delivered Gaseous
Hydrogen
$2,208,627 $2,205,540 $1,825,150
Delivered Liquid
Hydrogen
$2,370,162 $2,467,776 $1,980,876

It is important to note that the cost of a fueling station (see Table N-9) is dependent on the hydrogen pathway pursued . The difference in cost is due to the fact that each pathway requires different infrastructure.

The other component of fueling infrastructure capital expenditures is the cost of production equipment . It is important to note that delivered hydrogen pathways do not require any production equipment because the hydrogen is not produced on-site.

However, on-site SMR and on-site electrolysis production pathways require the installation of production equipment . On-site SMR equipment was assumed to incur a capital cost of $1,238,987 . This figure is the default capital expenditure for SMR equipment from NREL’s H2A Model. On-site electrolyzer equipment is assumed to have a capital cost of $3 million (J. Cole, 2020).

The operational costs of the hydrogen fleet were also calculated . The operational costs are recurring costs that occur on an annual basis. CA LSTART investigated hydrogen infrastructure maintenance costs and the cost of hydrogen. Hydrogen Attachment 1 - BurbankBus Bus Electrification Feasibility Study FINAL ATTACHMENT 2-262
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infrastructure maintenance costs were estimated using the HDRSAM Model . Based on the results of the HDRSAM Model, the annual maintenance costs were calculated and recorded in Table N-10.

Table N-10: Annual Maintenance Costs
Hydrogen Pathway The Pasadena
Department of
Transportation
Glendale Beeline BurbankBus
On-site SMR $179,506 $190,564 $137,892
On-site Electrolysis $179,506 $190,564 $137,892
Delivered Gaseous
Hydrogen
$153,781 $160,492 $130,111
Delivered Liquid
Hydrogen
$209,175 $211,357 $185,011

CALSTART also explored the cost of hydrogen. The cost of hydrogen was explored on a levelized per kg basis. Based on interviews with the hydrogen industry, CALSTART assumed that hydrogen produced via on-site SMR could be obtained for $6 per kg. The cost of on-site electrolysis production was calculated using the utility rates to which each transit agency is subject. The cost of delivered gaseous and liquid hydrogen was assumed to be $8 per kg . However, there is a cost to dispense hydrogen , as the dispensing process uses fuel and energy. HDRSAM produced estimates for the cost of dispensing. This amount was added to the cost of the hydrogen, as seen below in Table N-11.

Table N-11: Cost of Hydrogen
Hydrogen Pathway The Pasadena
Department of
Transportation
Glendale Beeline BurbankBus
On-site SMR $6.57 $6.56 $6.59
On-site Electrolysis $10.37 $8.82 $9.01
Delivered Gaseous
Hydrogen
$8.10 $8.10 $8.10
Delivered Liquid
Hydrogen
$8.37 $8.37 $8.37

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Appendix O: LCFS Calculation Methodology
The number of LCFS credits that an agency can earn is calculated according to the following formula:

# 𝑜𝑓 𝐿𝐶𝐹𝑆 𝐶𝑟𝑒𝑑𝑖𝑡𝑠 = 𝐶𝐼 𝑆𝑡𝑎𝑛𝑑𝑎𝑟𝑑 − (𝐶𝐼 𝐸𝑙𝑒𝑐𝑡𝑟𝑖𝑐𝑖𝑡𝑦
𝐸𝐸𝑅 ) 𝑥 𝐸𝑛𝑒𝑟𝑔𝑦 𝐷𝑒𝑛𝑠𝑖𝑡𝑦 𝑥 𝐸𝐸𝑅 𝑥 𝑘𝑊ℎ 𝑥 10−6

The Carbon Intensity (CI) Standard variable represents the standard baseline value for carbon intensity of energy (as measured in grams of CO2 equivalent per megajoule of energy) that CARB had designated to use as a benchmark from which to calculate savings of emissions. CI Standard depends on the type of fuel that is being displaced by the zero-emission vehicles. The two fuels that were examined in this report include diesel (which is being displaced by zero emission transit buses) and gasoline (which is being displaced by zero-emission shuttle buses). CARB designates a different CI Standard value each year for each type of fuel.

This value is scheduled to decrease over time, which mak es it more difficult to earn LCFS credits over time . The CI Standard changes according to the following schedule in Figures O-1 and O-2:

Appendix O
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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)

The CI Electricity represents the actual value of carbon intensity of electricity (as measured in grams of CO2 equivalent per megajoule of energy) that CARB has estimated in 2021 to be the actual average carbon intensity of California’s electricity grid.

This number is updated every year, and it is expected to decrease over time. In 2021, CARB set this value at 75.93 gCO2e / MJ.

The LCFS calculations provided in this report assume that the CI Electricity value remains at 75.93 through 2040.

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The EEER stands for Energy Economy Ratio. For electricity used for transportation, CARB has designated this value to be 5. This represents the higher efficiency of conversion of electrical ener gy to motion, compared to the inherent inefficiency of a combustion engine where a large portion of the energy is wasted as useless heat due to the laws of thermodynamics. For this reason, the carbon intensity of electricity used for transportation is divi ded by 5 to represent the fact that each megajoule of energy can produce 5 times the work that a megajoule of liquid hydrocarbon fuel could.

Energy Density is a simple fixed conversion factor which represents the number of megajoules in a k Wh. There are 3.6 megajoules in a kWh.

The kWh label simply represents the quantity of kWh of electrical energy that is used for transportation.

The final term is an adjustment factor of 10-6. This is used to convert the amounts of CO2 equivalent from grams to metric tons.

This is because the values for carbon intensity are measured in grams, but each low-carbon fuel standard credit represents one metric ton of CO2 equivalent.

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Appendix P: Sustainability Calculations Methodology
The calculations for the upstream pollution data were conducted using Greenhouse Gases, Regulated Emissions, and Energy use in Technologies Model (GREET), an Excel -based calculation tool which was developed by Argonne National Laboratory. GREET provides figures for emissions factors per megajoule of energy used for transportation purposes from various fuels and fuel pathways, including from California grid electricity, combustion of CNG, and multiple different pathways for producing hydrogen.

CALSTART modeled the amount of energy which ZEBs would use on an annual basis for each of the transit agencies under each service scenario. CALSTART multiplied these quantities of energy by the emissions factors for each pollutant, to quantify the amount of pollution that each agency and service pattern would produce.

These numbers measure only emissions produced by the transit service operation but do not attempt to quantify the fundamental environmental benefit to public transit, which is displacing private car travel. They also do not attempt to quantify the emissions produced by the manufacturing or disposal of buses.

In addition to the BEBs powered by the California grid, and the conventional CNG buses, five pathways for production of hydrogen for FCEBs were considered. These are SMR on the site of the fueling station to make gaseous hydrogen, SMR at a central plant to make gaseous hydrogen, electrolysis using grid energy on the site of the fueling station to make gaseous hydrogen, electrolysis using solar energy at a central plant to make gaseous hydrogen, and SMR at a central plant to make liquid hydrogen. Upstream emissions from these six zero-emissions bus options were calculated using GREET.

CALSTART estimated the fuel consumption based on mileage data. M .J. Bradley and Associates had estimated the fuel consumption of CNG buses in Southern California at 4.1 miles per diesel gallon equiv alent, which translates to 33 megajoules per mile (Lowell, 2013) . This efficiency factor was multiplied by the total annual mileage for each transit fleet under each scenario. The quantities of CNG fuel were then multiplied by the emissions factors for the different types of pollution in GREET, to calculate the upstream pollution from CNG bus operation.

Tailpipe emissions from CNG buses were estimated using CARB’s Emissions Factors Model (E MFAC). This Excel -based model contains estimates for the tailpipe emissions per mile for CNG -powered transit buses in Los Angeles County. These emissions factors were multiplied by the annual mileage for each transit fleet under each scenario and added to the upstream emissions numbers to obtain the total emissions.

Appendix P
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GREET contains estimates for the emissions of CO2, methane, and nitrous oxide, as well as a combined total GHG emissions. The figure for total GHG emissions is a measure of the total warming impact of the GHG emissions produced. This figure is necessary because some GHGs contribute more to climate change than others . The impact that a particular gas has on climate change is quantified into a figure called global warming potential . Global warming potential is a multiplicative factor that is used to compare the warming impact of a gas in relation to CO2. For example, a gas with a global warming potential of three has triple the warming impact of CO2. The conversion of emissions to global warming potential provides a metric that can be used to directly compare emissions between different fuel pathways.

The Total GHG emissions calculation is the sum of each gas multiplied by its global warming potential. EMFAC provides emission results for each GHG ( CO2, methane, and nitrous oxide) separately, but not the combined total for GHG emissions . CALSTART calculated the combined total for GHG emissions from CNG bus operation using the same global warming potential numbers from GREET, which is displayed below in Table P-1.

Table P-1: Global Warming Potential Factors
GHG Global Warming Potential
CO2 1
Methane 30
Nitrous Oxide 265

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Appendix Q: The Pasadena Department of Transportation
Stakeholder Engagement and Outreach Summary
The Transit Fleet Electrification Feasibility Study for the Arroyo Verdugo Region Transit Operators study was presented to various City of Pasadena councils and commissions. The main objective of these presentations was to solicit feedback on the study from city stakeholders. During these meetings, Pasadena Department of Transportation staff presented the results of the study.

CALSTART served as a subject -matter expert and provided answers to technical questions. The study was presented to the following City of Pasadena councils and commissions:

• Pasadena Transportation Advisory Commission
• Pasadena Municipal Services Committee
• Pasadena Environmental Advisory Commission
• Pasadena Northwest Commission

A summary of t he study was presented to the Pasadena Transportation Advisory Commission on June 24, 2021. During this meeting, Pasadena Department of Transportation presented the study, outl ining the results of the study. The Transportation Advisory Committee commented on the study. The Transportation Advisory Committee expressed concerns about the increased cost of zero emission buses, as compared to the current CNG fleet. However, despite t his concern, they also recognize that combatting climate change is important and that continuing business-as-usual is not a viable option. The Transportation Advisory Commission also stated that the transition to ZEBs is an opportunity to promote economic development and workforce development. The Transportation Advisory Commission stated that they would like to see Pasadena Department of Transportation partner with Pasadena City College or an OEM to train workers if there is a viable opportunity. Lastly, t he Transportation Advisory Commission expressed an interest in hydrogen .

A summary of t he study was presented to the Pasadena Municipal Services Committee on October 12, 2021. The Municipal Services Committee is comprised of members from Pasadena City Cou ncil. During this meeting, the study was presented to the Municipal Services Committee. The Municipal Services Committee had input on the study. The Committee noted that Pasadena Department of Transportation is obligated by the ICT Regulation to begin purc hasing ZEBs by 2026. The Committee expressed

Appendix Q
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an interest in purchasing buses ahead of the mandate outlined by the ICT Regulation. The Municipal Services Committee stated that an earlier deployment is needed due to the need to combat climate change. In addition, the Committee expressed concerns about the cost of the buses and are concerned that government incentives for ZEBs could end before 2026. As a result, the Municipal Services Committee stated that they would like Pasadena Department of Transportation to explore opportunities to deploy buses ahead of 2026. Specifically, they asked Pasadena Department of Transportation to explore opportunities to deploy pilot buses ahead of 2026 . Since it is unlikely that Pasadena Department of Transportation will have a depot before 2026, the Committee asked them to engage with PWP to explore options for charging pilot buses. The Committee also asked Pasadena Department of Transportation to look into opportunities to partner with other transit agencies to share facilities. The Committee also proposed methods for financing the construction of a new transit facility. Options that are being considered include issuing bonds and using financing from the California iBank. The League of Women Voters provided comments on the study. The League of Women Voters expressed concerns that environmental justice groups did not have the opportunity to comment on the report.

They also expressed concerns that more CNG -powered buses will be purchased before 2026 and that after 2026, 75% of purchases will still be powered by CNG. Since these purchases will lock-in additional consumption of fossil fuels until the 2030s, the League of Women Voters , asked that Pasadena Department of Transportation accelerate the purchase of ZEBs. CALSTART worked to address the concerns raised during this meeting, especially those surrounding a pre-2026 ZEB deployment. The main barrier to a pre-2026 deployment is that Pasadena Department of Transportation will likely not have a transit facility or its own infrastructure to charge the buses. To address this concern, CALSTART facilitated a discussion between Pasadena Department of Transportation and PWP. During this meeting, PWP stated that they would be able to provide a temporary charging solution for pilot buse s if they are deployed before Pasadena Department of Transportation has finished construction on its transit facility.

A summary of t he study was presented to the Pasadena Environmental Advisory Commission on November 9, 2021. The Environmental Advisory C ommission had several questions about the plan. The Commission stated that the Public Works/Department of Sanitation fleet is planning to electrify and asked if there are opportunities to collaborate with them to share infrastructure. Pasadena Department of Transportation confirmed that this study does not assume collaboration to share a facility. The Environmental Advisory Commission also stated that they would like to see the ZEB cost figures disaggregated into individual components. The Commission also a sked about options for resiliency for the fleet. CALSTART stated that the most viable options would be to use a solar and storage system or to use natural gas backup generators. However, without the designs for a transit facility , it is not possible to determine what the exact specifications of the resiliency system will look like. The Commission also asked if there are any opportunities to collaborate with Glendale and Burbank to purchase buses. CALSTART stated that the State of California has already sign ed a state -wide procurement contract with major ZEB OEMs . Pasadena Department of Transportation would be able to use these state -wide procurement contracts to purchase buses without having to do a request for proposals. The Commission also asked about how ZEBs will affect noise pollution. CALSTART stated that CNG buses produce much more noise than both BEBs and FCEBs. Lastly, the Commission expressed concerns about the amount of power that a ZEB fleet will draw from the grid. CALSTART stated that PWP did not express any concerns about grid capacity.

A summary of t he study was presented to the Pasadena Northwest Commission on November 9, 2021. The Northwest Commission raised questions about the cost of bus charging/fueling infrastru cture. Concerns were also raised about how Pasadena Department of Transportation plans to pay for the buses and if funding had been allocated to purchase ZEBs ahead of 2026. Pasadena Department of Transit stated that their current budget plan assumes that purchases of CNG buses will continue until 2026. The Northwest Commission also asked about the life-cycle environmental impact that the batteries will have and what options there are to mitigate any negative environmental impacts. CALSTART stated that ther e are two main options for mitigating the environmental impacts of batteries. The first method is to recycle the batteries once they reach the end of their useful life. There are companies that will accept used batteries, break the batteries down into thei r raw materials, and recycle the materials. Another option would be to reuse the batteries. After an EV battery's useful life, the battery is still useable and can be reused in a stationary battery storage system.

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Appendix R: City of Glendale Stakeholder Engagement and Outreach Summary
The Transit Fleet Electrification Feasibility Study for the Arroyo Verdugo Region Transit Operators study was presented to Glendale City Council on December 7, 2021. The main objective of this presentation was to brief Glendale City Council about the plan to transition to ZEBs and solicit feedback on the study. During this meeting, CALSTART and Glendale Beeline presented the study.

Glendale City Council had several questions about the study. Glend ale City Council expressed concerns about the costs associated with transitioning to a zero emission fleet. As a result, they asked about how Glendale Beeline planned to fund th e purchase of ZEBs. Glendale Beeline stated that they plan to primarily use grant funding from state and Federal programs to pay for the buses. Glendale City Council also expressed concerns about the need for resiliency assets. Glendale City Council stated that LADOT had recently been awarded a grant to build a microgrid that was designed to provide power to the buses in the event of a grid outage and asked if this approach to resiliency had been considered in the study. CALSTART responded that thi s approach had been considered in the study but that it would be difficult to deploy battery storage assets due to space constraints at the depot. Glendale City Council expressed concerns that Glendale Beeline's depot is space constrained and asked about how other major transit agencies in the area, like LA Metro and LA Department of Transportation, have overcome these challenges.

Glendale Beeline responded that other transit agencies are facing similar problems . Transit agencies like LA Metro and LA Department of Transportation are also facing space constraints on their depots and have had to purchase additional yards to accommodate charging infrastructure. These challenges might cause delays the deployment of ZEBs at these transit agencies .

Furthermore, due to these challenges, Glendale City Council asked whether hybrid electric buses could be deployed instead of zero emission buses. CALSTART stated that hybrid electric buses do not count towards compliance with the ICT Regulation.

Glendale Beeline added that the hybrid electric buses at other transit agencies have historically had reliability problems.

Appendix R
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Appendix S: BurbankBus Stakeholder Engagement and Outreach Summary
The Transit Fleet Electrification Feasibility Study for the Arroyo Verdugo Region Transit Operators study was presented to t he Burbank Transportation Commission and Burbank City Council. The main objective of these presentations was to solicit feedback on the study from city stakeholders. During these meetings, the City of Burbank Community Development Department, which manages BurbankBus, presented the results of the study. CALSTART served as a subject-matter expert and provided answers to technical questions.

The study was presented to the Burbank Transportation Commission on December 20, 2021. The Transportation Commission had several questions about the study. The Commission expressed concerns about the costs associated with acquiring a new transit facility. As a result, the Commission asked why a city-owned depot is required. Burbank Community Development stated that a city -owned depot is required because they are currently using leased depots that are provided by the transit company they have contracted with. Since these contracts tend to be short -term, it would not be financially viable to invest millions of dollars to bui ld charging infrastructure unless they would control the property for the life of the equipment. The Community Development Department recognizes that they are a small transit agency and as a result, it will be difficult to achieve economies of scale. To start achieving economies of scale, the Community Development Department is exploring options for collaboration with other transit agencies. One possibility being explored is to work with Glendale Beeline on joint contracts with transit companies for both ci ties. The Community Development Department is aware that once charging infrastructure is installed, Glendale Beeline will likely not have enough room to accommodate BurbankBus's vehicles on their depot.

The Commission stated that over the years, there have been discussions about eliminating city -operated transit service. This topic has been raised due to concerns about decreasing ridership, the high cost of operating transit, and citizen complaints about fixed-route transit service not meeting the transportation needs of the city. The Commission expressed concerns about the unknowns about the range and reliability of ZEBs. Since the projected cost of a ZEB fleet is projected to be higher than the status quo, some of the commissioners stated that el iminating city-operated transit services might be the most viable option. They argued that bidding transit services to a contractor or switching to a demand response transportation system might be a more cost-effective option. However, other commissioners disagreed arguing that this model would leave the city at the mercy of contractors, who might charge high rates to provide these services.

Appendix S
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Some of the commissioners also proposed purchasing used/second -hand buses as a way to reduce the costs associated wi th transitioning to ZEBs. Lastly, some of the commissioners stated that FCEBs should continue to be considered as an option.

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Burbank City CouncilJuly 25, 2023

Burbank City Council
July 25, 2023