Guidebook for Deploying Zero-Emission Transit Buses (2021)

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67 PHASE 4 FUELING INFRASTRUCTURE STRATEGY AND COST 4.1 Overview Establishing a fueling strategy and estimating fuel costs is an important step to ensure that you are maximizing the utilization of your buses and infrastructure in order to minimize costs. Both BEB and FCEB deployments will require electricity for bus charging or hydrogen fueling. Understanding consumption patterns and electric utility rate structures will help identify opportunities for load management and cost savings. For BEBs, electricity costs can vary significantly based on the type of charging utilized, the time of day the buses are charged, and the size of the deployment. Charge management strategies can help minimize costs for any size deployment and become a necessity for larger deployments. BEB deployments of any size will benefit from demand management strategies. For FCEB deployments, costs will vary based on the type of deployment (on-site production versus hydrogen delivery). For deployments utilizing hydrogen delivery, daily operation of fueling stations will be similar to CNG stations today. The greatest driver of costs for these deployments will be location, as hydrogen fuel costs vary greatly by region. FCEB deployments utilizing on-site hydrogen generation will require a significant amount of energy and may benefit from demand management strategies, depending on the generation process utilized and storage capabilities. Completion of this phase includes evaluating the available utility rate schedule to estimate electricity costs and designing a fueling strategy to minimize costs while still meeting all service needs. Coordination with your transit agency’s electric utility is vital throughout this phase. Your utility can help you understand your rate schedule, evaluate your service needs and how to satisfy them, and identify opportunities for reducing costs. Best practices for evaluating fueling infrastructure strategy and cost include: • Conducting electricity rate model analysis to understand how bus operation impacts costs. • Determining total fueling costs and opportunities for demand management. • Identifying charge management strategies for BEB operation that will meet all service needs.

68 Guidebook for Deploying Zero-Emission Transit Buses 4.2 Key Stakeholder Considerations External Stakeholders • Electric utility providers should be engaged throughout the ZEB deployment process to discuss service and infrastructure needs, changes to your electricity rate schedule, and methods to lower electricity costs through demand management. The utility may be able to offer pilot rates or programs to support the ZEB deployment or infrastructure operation. • Hydrogen production facilities and delivery companies, when applicable, should be engaged to discuss hydrogen costs, estimated demand, and delivery schedules. • Labor unions may need to be engaged if staff are assigned new job responsibilities to operate a hydrogen fueling station or plug-in depot charged buses. • Third-party vendors provide software solutions to support data monitoring and smart charging capabilities. Project Managers • Maintain a strong relationship with your electric utility throughout the ZEB deployment process to discuss service and infrastructure needs, changes to your electricity rate schedule after ZEB deployment, and methods to lower electricity costs through demand management. • Develop an electricity rate model to estimate electricity costs based on BEB charging procedures, considering the duty cycle, schedule, battery capacity, and usable charger power. • Work with the utility and operations staff to identify ways to optimize the charging approach to limit demand charges, weighing service and operational constraints. Operations, Maintenance, and Facilities • Meet with your electric utility early on in the planning process to discuss infrastructure needs for the fueling infrastructure deployments. • Ensure that roles, responsibilities, and timing for bus fueling are clear, either at the hydrogen fueling stations for FCEBs or at the charging stations for BEBs. • Identify service and operational constraints that would impact charge management optimization (e.g., %SOC needed for morning pullout, timing and flexibility of bus assignment, limiting demand charges, minimizing overall costs). Procurement • Coordinate with transit agency staff to understand estimated monthly fuel costs. • Work with your electric utility provider to review and identify the most favorable rate schedules for your deployment strategy. • For hydrogen delivery deployments, research production facilities and delivery options to determine the combination that best satisfies service demand.

Fueling Infrastructure Strategy and Cost 69 4.3 Battery Electric Buses and Utility Rate Analysis Deploying BEBs may result in a significant increase in your electricity usage compared to the historical usage of your facilities. A transit agency with a full BEB fleet may be one of the largest electricity users in the utility’s service area. Have a strong understanding of the factors that will impact your electricity costs prior to BEB deployment (e.g., time of electricity usage, number of buses charging simultaneously). The impact of these factors will be influenced by the electric utility rate schedules available to you. Discuss your short- and long-term BEB goals early on in the planning process with your electric utility so they can help you understand the infrastructure needs to support your planned deployments as well as options for your electricity rate schedule. For customers with BEBs, your utility may be able to propose charging strategies that will allow you to achieve your service needs at the lowest cost. The sections below describe common components of electricity rates. Your rate schedule may contain a combination of the components listed. 4.3.1 Understanding Your ElectricityBill Since generation and demand must precisely match at all times, power companies tend to favor steady, predictable consumption of energy. To help manage demand, utilities impose different rates throughout the day and often surcharge the price of electricity during peak usage hours. Therefore, your cost for the same electricity usage may vary based on when it is consumed. Electric bills consist of many different charges, which will vary between power providers. Some charges are billed by kW, a measure of power, while others by kWh, a measure of energy. Your electric bill may include an additional power factor (PF) charge (sometimes called a PF adjustment) since a low PF can overload generating, distribution, and networks. However, the majority of your utility bill will be based on kW and kWh consumption. See below for further explanation of the PF. Early coordination with your electric utility is vital to understand how your rate schedule may change and to explore options for reducing costs.

70 Guidebook for Deploying Zero-Emission Transit Buses 4.3.2 Electric Bill Charges Electric bill charges are commonly broken down into the following categories, described in more detail below: Power Factor Working power, measured in kW, is the actual power electrical equipment requires when performing its function. For a bus charger, the working power would be approximately equivalent to the power rating of the charger (e.g., a 50 kW depot charger would have 50 kW working power). However, many types of equipment require reactive power to generate and sustain a magnetic field in order to operate. Working power and reactive power make up apparent power, which is measured in kilovolt-amperes (kVA). Comparing apparent power to working power gives the PF, which determines how much of an incoming current is doing useful work. A high PF benefits both the customer and the utility, while a low PF indicates poor utilization of electrical power (Laurens Electric Cooperative, Inc., n.d.). PF is expressed as: PF = Working Power (kW) / Apparent Power (kVA) Power vs. Energy Power, measured in kW, is the rate that energy is consumed or moved. Energy, measured in kWh, is a quantity of work. For example, using a 50 kW bus charger for 2 hours consumes 100 kWh: 50 kW × 2 hours = 100 kWh Using a 300 kW bus charger for 20 minutes also consumes 100 kWh: 300 kW × 0.33 hours = 100 kWh This relationship can also help determine the minimum time required for recharging buses. For instance, restoring 150 kWh utilizing a 50 kW charger would require at least 3 hours. Note that actual charge times may be longer due to charger limitations. An engineering analysis is needed to calculate accurate charge times. Compare the above examples to filling up a diesel tank. A diesel pump may be able to fill a bus at 10 gallons per minute. That flow rate is analogous to the power of a bus charger. Using the pump for 15 minutes will dispense 150 gallons of diesel. That total amount of fuel received is analogous to the kWh of energy that a battery would receive during a charging session.

Fueling Infrastructure Strategy and Cost 71 • Fixed Costs, • Energy Charges, • Demand Charges, and • Other Charges. These charges will be applied to each electric meter installed at your facility. Your approach to demand management may differ if your chargers or hydrogen fueling equipment are on the same meter as the rest of your facility. 4.3.3 Fixed Costs The utility may charge a monthly service fee, which usually covers the price of being connected to the grid. Fixed costs generally account for less than 1% of your total monthly bill. 4.3.4 EnergyCharges = Total energy used (kWh) × Rate ($/kWh) The utility will charge for the total energy consumption, which accrues throughout each month and is typically measured in kWh. Some utilities have seasonal rates, tiered rates for the amount of energy used, or higher energy charges for peak periods. There may be many line items on a bill that are all billed based on the kWh consumed. 4.3.5 Demand Charges = Highest average power (kW) over a specified period of time × Rate ($/kW) The electric utility must always be able to meet the power demand for all of their customers at the instant that it is required. Demand charges are put in place to cover the cost of electrical infrastructure needed to meet the highest electricity demand at any time. Most commercial utility rates will include demand charges. Demand charges are typically calculated each billing cycle and are based on the highest demand used over a window of time, typically 15- or 30- minutes. However, some utilities utilize a ratchet charge on demand, utilizing an annual peak demand (instead of resetting it each month), based on your highest monthly demand from the previous year. Depending on the rate structure, demand rates may also vary by the amount of power used and the time of day it is used. The relationship between energy and demand is demonstrated in Figure 4-1. The blue line shows the demand (kW) throughout the day, and the gray area shows the total energy consumed (kWh).

72 Guidebook for Deploying Zero-Emission Transit Buses The following examples illustrate how peak demand is calculated based on different usage scenarios, assuming a 15-minute demand window. Note that the calculations below do not take into account efficiency losses that may result in higher demand charges. Example 1: Five 50 kW depot chargers are installed on the same meter that services your transit facility for overnight bus charging. Your facility utilizes an average of 175 kW during the day and 75 kW overnight. Under these conditions, your previous peak demand was during the day. Without any charge management strategies, your new peak demand would now occur overnight, from simultaneously charging five buses on the 50 kW chargers. Assuming the buses require more than 15 minutes to charge, the chargers alone would create the following power demand: 5 chargers × 50 kW × (15 minutes of charging / 15 minute demand window) = 250 kW When you add that to your existing average overnight facility demand (75 kW), your new peak demand now occurs overnight: 75 kW (existing overnight demand) + 250 kW (overnight charging demand) = 325 kW In this example, the chargers created 250 kW of additional demand. However, the previous peak demand, occurring during the day, was 175 kW. The new overnight peak demand was only 325 kW, an increase of 150 kW instead of the entire 250 kW the chargers created. Because the charging occurred during previously off -peak hours, a portion of the charger demand was offset by the daytime facility usage. Figure 4-1. Example electricity demand throughout a day. (Source: We Energies)

Fueling Infrastructure Strategy and Cost 73 Example 2: A separately metered 450 kW fast charger is installed. Your highest demand possible for that charger would be approximately 450 kW, which would occur if your bus took 15 minutes to charge: 1 charger × 450 kW × (15 minutes of charging / 15 minute demand window) = 450 kW However, many buses fully charge in less than 15 minutes. If your buses take 10 minutes to charge, your peak demand would be approximately: 1 charger × 450 kW × (10 minutes of charging / 15 minute demand window) = 300 kW For separately metered fast chargers, your peak demand will occur during your longest charge event for each month. In most rate schedules, demand costs are a significant contributor to operational costs. As such, increased usage of the buses will reduce the overall cost per mile, since the demand charges can be spread out over more miles of operation. If your chargers will be on the same meter as your facility, evaluate your current electricity consumption for your facilities to determine what time of day your current demand peak occurs. Charging buses at the same time as your current facility peak will add to the overall peak demand. However, charging buses at a different time of day will allow you to offset the demand from your facilities. 4.3.6 Other Charges Surcharges, taxes, and other fees will also be included with the utility bill. These can be related to how the energy was produced, who produced or sold the energy, energy efficiency, renewable energy production, the decommissioning of old power plants, city taxes, or rate adjustments during a rate case (approval process for customer rate approval). The magnitude of these rates can be hard to predict but can account for as much as 30% of the total monthly bill. Demand charges can have significant implications for BEB operation since faster chargers or using many depot chargers concurrently will result in higher demand costs. Transit agencies can overcome these challenges by developing charge management strategies, such as a charging schedule and control schemes that minimize the rate of electricity consumption. Even with charge management strategies, if you ever need to charge more buses simultaneously than planned to meet service, you could be charged for that peak demand, even if that only occurs once in a billing cycle.

74 Guidebook for Deploying Zero-Emission Transit Buses 4.4 Typical Rate Structures Building and maintaining a strong relationship with your electric utility is vital throughout the deployment process. Some utilities have implemented rate structures and pilot programs that promote the deployment of zero-emission vehicles. If your utility is able to offer a pilot rate or program to benefit your BEB deployments, ensure that you plan for a change in costs or electricity rates if the pilot program expires before the end of the service life of your buses. Examples of rate structures or pilot programs being offered around the country include: • Limiting demand charges, • Energy and demand discounts for off -peak usage, • Owning and operating charging infrastructure and batteries , • End of life battery purchasing for energy storage projects, and • General contracting services for any required electrical or construction work to install charging infrastructure for a BEB fleet expansion. 4.4.1 Tiered (or Step) Rate A common rate structure used by utilities is a tiered rate structure. With a tiered structure, the cost per kWh can change at different thresholds of consumption. For example: 7.15¢ each for the first 2,000 kWh 6.00¢ each for all kWh above 2,000 4.4.2 Time of Use Rate = Total energy used at peak times (kWh) × Peak Rate ($/kWh) + Total energy used at off-peak times (kWh) × Off-peak Rate ($/kWh) Time of Use (TOU) rates are designed to curb usage during peak windows of power consumption. Utilities charge a lower rate for electricity consumed during off -peak hours, usually in the evening or at night, and a higher rate for electricity consumed during peak hours, typically during periods when most businesses are operating. Utilities set peak and off -peak times based on many factors, such as overall customer demand, or the availability of electricity (e.g., if your utility relies on solar energy, electricity may be less Utilities across the country have varying regulations and policies that determine how they establish rate structures and what types of programs they can offer. Just because a program or pilot rate is beneficial for one transit agency does not mean that it will be beneficial, or even possible, for another.

Fueling Infrastructure Strategy and Cost 75 expensive in the afternoon). Example costs per kWh for a TOU rate are shown in Figure 4-2. Note that the times when the highest energy charges are incurred may shift as more renewable energy sources are brought online to the grid. For example, the highest energy costs for a utility that relies heavily on solar may be in the evening. It is important to understand your utility’s current and future mix of electricity generation and the impact it may have on your TOU rates. Some utilities add seasonality to their TOU tariffs as well, varying their TOU rates and peak windows to account for seasonal effects on energy consumption. 4.4.3 Critical PeakPricing Some utilities will implement critical peak pricing (CPP), where a substantially higher rate is charged for energy used during a period of time when the electric utility requires more power than usual, such as extremely hot days, or during emergency situations. Some utilities allow customers to enroll in a demand response program that offers a discount on regular electricity rates in exchange for reducing consumption during critical peak events. This approach can be challenging for transit agencies, if you require charging during critical periods to meet required service, especially with on-route charging during daytime peaks. 4.5 Hydrogen Fuel Costs There are two major cost components for fueling FCEBs: (1) electricity costs and (2) hydrogen costs. Figure 4-2. Example costs per kWh for a TOU rate.

76 Guidebook for Deploying Zero-Emission Transit Buses 4.5.1 Electricity Costs Hydrogen fueling infrastructure operates similarly to diesel and CNG fueling stations. At a minimum, hydrogen fueling requires compressors, cooling, and a dispenser, which can consume a considerable amount of energy. Energy consumption becomes more complex if you are producing hydrogen on site. Strategies to limit electricity demand charges or concentrate usage to off-peak times will depend on the type of system you install. For delivered hydrogen that is stored and dispensed on site, your system would operate much like a CNG station, with automatic loads that cannot be easily controlled. Compression energy can be as much as 2.5 kWh/kg of fuel dispensed, whereas liquid pumping requires about 0.4 kWh/kg or less. Pre-cooling may be required, depending on several variables, including high flow rates and vehicle storage capacity. Energy to cool hydrogen gas as it is dispensed into the vehicle should not require more than 0.5 kWh/kg, but will depend on the size of the system and the energy required to maintain safe temperature levels during the fueling process. On-site hydrogen generation would significantly increase energy consumption, compared to conventional diesel fueling stations, requiring between 55 kWh/kg and 65 kWh/kg. For stations that produce hydrogen on site, your ability to mitigate electricity demand will depend on the type of production system used. The latest electrolyzer technology allows for instant on/off cycles with little efficiency loss. Oversizing the electrolyzer and controlling on/off cycles to take advantage of off -peak electricity rates and the availability of on-site renewable power can help avoid demand charges. If utilizing natural gas generation, your primary fuel for generation is natural gas, eliminating any significant benefit of scheduling generation during non-peak times. It is important to understand the power requirements of the needed infrastructure prior to installation and deployment (See Section 2.3: Bus Performance Evaluation). Once the power requirements for the fueling infrastructure are known, estimated usage patterns can be combined with existing utility rate options to calculate the anticipated costs and inform your fueling strategy. While pipeline hydrogen delivery is the cheapest and most efficient delivery method, there is little infrastructure available for this to be a viable option today, although continued market adoption may incentivize additional infrastructure in the future. For most deployments, hydrogen must either be pressurized and delivered as a compressed gas or stored as a liquid on site then converted to pressurized gas (requiring additional equipment for compression and dispensing). Transporting compressed hydrogen gas by truck or high-pressure tube trailers is expensive and used primarily for distances of 200 miles or less. Liquefied hydrogen tankers can transport over greater distances but liquefaction is expensive and, once delivered, some liquefied hydrogen can be lost to evaporation if not utilized quickly. (US Department of Energy, n.d.)

Fueling Infrastructure Strategy and Cost 77 4.5.2 HydrogenCosts Transit agencies can either purchase hydrogen from a supplier or produce it on-site. If you are purchasing hydrogen from a supplier, the supplier and dispensing company will dictate product costs. As of early 2020, hydrogen costs between $4 and $9 per kg depending on location and access to large-scale hydrogen production facilities. This significant variance in price is largely due to limited hydrogen distribution infrastructure. Since distribution is a significant component of hydrogen costs, transit agencies located further from production sources will have higher prices. However, if demand for hydrogen in fuel cell applications grows, the prices should decrease. Some major energy suppliers in California are predicting pricing between $5 to $6 per kg in the next few years when demand increases, but as of the writing of this report, none have made firm commitments to this pricing level. Prices as low as $2.50 per kg are possible with hydrogen delivered by pipeline. If you are generating hydrogen on site at your facility through electrolysis or natural gas reformation, you must consider the costs of the raw materials (i.e., power, water, or natural gas), equipment, maintenance, and energy to operate the equipment. Even without equipment to generate hydrogen on site, total fuel costs should account for energy consumption to operate the station. One study found that a public hydrogen fueling station had a net energy consumption of 5 kWh per kg of hydrogen dispensed (Brown et al., 2012). Argonne National Laboratory’s Heavy-Duty Refueling Station Analysis Model estimates the energy usage of a hydrogen fueling station for a fleet of heavy -duty vehicles. The model takes into account the many hydrogen fueling infrastructure options (delivery vs. on-site production) and the cost of energy from the U.S. Energy Information Administration (EIA) to calculate the overall fueling cost and station cost. 4.6 Electricity Rate Modeling After gaining a strong understanding of the components of your electricity bill, model your electricity consumption based on your planned service requirements to estimate your operational costs. This section is focused on BEB operation, but transit agencies operating FCEBs and producing hydrogen on site would also benefit from modeling electricity consumption based on hydrogen consumption. An electrolysis system that produces hydrogen required for 12 buses may use as much as 1 MW.

78 Guidebook for Deploying Zero-Emission Transit Buses A rate model will provide an upper bound of costs and operational parameters for your BEB deployment. It will also help identify what factors have the greatest impact on costs, which may be managed with charging strategies. Any charge management strategy to limit demand or time usage to off -peak hours must be balanced with your service requirements and the cost for this management service. Understanding your utility rate structure and how different charging scenarios impact your cost of deployment will be essential for maximizing the utilization and cost effectiveness of your BEBs. At a minimum, your rate model should: 1) Utilize the proposed bus usage (e.g., in-service time and mileage) and estimated energy efficiency identified through your modeling efforts (See Section 2.3: Bus Performance Evaluation), incorporating any seasonal variations. 2) Establish operational requirements (e.g., when a bus is available to charge, when a bus must be available for service, what SOC is required to be put into service, time required for cleaning, and any other standard vehicle operation and maintenance use). 3) Reflect charger power ratings to establish how long it will take to recharge your buses (See Section 2.3: Bus Performance Evaluation). Note that the estimated time to charge should incorporate efficiency losses and other parasitic loads during charging and assume that the charging rate will slow down as the batteries get close to full. Ensure that you incorporate a margin of error within your charging requirements to accommodate unanticipated issues with charging or bus scheduling. 4) Estimate your maximum electricity load profile with the overall kW demand and kWh consumption from charging your buses. 5) Apply your utility rate schedule to estimate the costs of charging based on time of day and duration of charging. 6) Incorporate flexible parameters that allow you to evaluate the costs or benefits of various scenarios (e.g., limiting the number of buses charged simultaneously, limiting charging to off -peak hours, changing the time in service). Compare the cost per mile for each scenario to determine which scenario will provide you the greatest costs savings, while still allowing you to meet your service needs. Limiting your peak demand may allow you to save money on or delay electrical infrastructure upgrades for smaller ZEB deployments, if the existing depot facility is not utilizing its full rated kW capacity. However, for larger installations or for overhead fast - chargers, a thorough analysis of power and consumption needs will be required. While adding some initial complexity and cost, larger installations can provide fleet owners greater flexibility in creating charging patterns that minimize spikes in demand (Chandler et al., 2016).

Fueling Infrastructure Strategy and Cost 79 4.6.1 BEB Charging Strategy Utilizing the results of your route and rate modeling efforts, schedule data, the available battery capacity of your buses, and the power delivered from your chargers, develop a charging strategy that meets service needs while minimizing costs. On-route charging strategies can be either charge depleting or charge sustaining (as shown in the illustrative on-route charging sessions in one service day in Figure 4-3). Charge depleting scenarios occur when a bus cannot “catch up” or fully recharge to the %SOC at the beginning of the previous charging session. With this approach, buses will require additional charging to get a bus to sufficient %SOC to begin service the next day. Charge sustaining scenarios occur when a bus can “catch up” to the %SOC at the beginning of the previous charging session. Under this scenario, buses will not need plug-in charging, and can operate in service indefinitely. With some charging scenarios, on-route charging can result in lower peak demand than simultaneous plug-in charging, due to the number of buses and duration of charge required. In addition, if charging isn’t required each time the bus passes the on-route station, charging can be strategically timed to occur outside of peak-demand windows. Recognizing the need for balancing recharging and demand costs, OEMs are starting to offer technology solutions as well. At least one overhead charging station on the market includes a stationary battery for storage to limit the peak demand (Heliox, n.d.). As the ZEB industry matures, there may be opportunities for utilizing batteries that have reached the end of their useful life in a transit bus or other application as on-site energy storage as well. For depot-charged buses, sequential charging or charging at lower power may help limit demand charges. You may have 8 hours to charge your buses overnight before morning pullout, but your buses only need 4 hours to fully charge. Operational procedures or charge management software can help manage your demand load by: Figure 4-3. Example %SOC for charge depleting and charge sustaining on-route charging strategies, showing %SOC over time for on-route charging sessions throughout the day.

80 Guidebook for Deploying Zero-Emission Transit Buses • Limiting the number of buses being charged simultaneously (e.g., charge 4 buses, then charge the other 4) or • Reducing the power output of your chargers (e.g., charge eight buses over the 8 hours at 60kW instead of 125kW) Effective charge management strategies may extend the total time required for recharging your fleet but will ensure all buses are fully charged for morning pullout (as shown in Figure 4-4). Your transit agency’s service requirements may limit the types of charge management strategies that you can implement. Weigh the benefits and costs of your charging strategy and keep in mind long-term BEB goals. Any charge management software should pay for itself, regardless of the size of your ZEB deployment, by saving you money on your electricity bill. The complexities and benefits of charging a large fleet of BEBs will likely require an automated solution to manage demand. Establish priorities for charge management Prioritize the constraints of your fueling strategy to identify the optimum charging processes that will allow you to meet your service needs and minimize costs. What is the minimum SOC needed at the time of pullout? Do you require a midday charge to optimize bus usage? Do you need to ensure that your demand never exceeds a certain limit? Are you attempting to minimize overall costs? Figure 4-4. Example daily power demand with and without charge management strategies. Third-party software can provide smart charging capabilities that automate charge management strategies. Contact your bus or charger OEM for more information on options for smart charging.

Fueling Infrastructure Strategy and Cost 81 While operational procedures can be another strategy for minimizing demand, be sure to educate all relevant staff on charge management procedures to avoid accidental charging. Plugging in and charging buses at the wrong time, even once in a billing period, can immediately impact demand and negate the benefit of a charging strategy. 4.7 Utility Partnership A strong partnership between transit agencies and their electricity provider is invaluable and will help ensure a charge management strategy that balances transit needs with those of the utility. A transit agency with a fully electric fleet may become one of the largest customers in a utility’s service area, which introduces new challenges and opportunities. Work with your utility to understand where your transit agency fits within their capital plan. Early in your BEB deployment process, coordinate with your electric utility to understand infrastructure needs, existing or planned rate schedules, and to discuss opportunities to plan your charging sessions to minimize costs. Engagement with your electric utility throughout the life of your BEBs will ensure that you have a seat at the table for any discussions about proposed changes to rate schedules or the development of any beneficial programs. Your utility can help you understand how your rate schedule may change as you add ZEBs to your fleet, increasing electricity consumption. Work with your electric utility to identify ways to reduce your electricity bill, such as utilizing TOU rates, or methods to limit demand charges. Demand response programs may be available, providing financial incentives for the ability to curtail demand during peak windows. Evaluate your options Besides your electric utility, there may be options in your service area for electricity purchase or generation. Coordinate with your local government to discuss available options. Electric utilities are anticipating changes in how electricity is generated and distributed in the future, due to the increased usage of renewable energy. Consider re-evaluating your options every few years to identify new opportunities that may become available to you. Other options include: • On-site energy generation and storage, such as on-site solar or wind, • Power purchase agreements (PPAs), and • Community microgrids.

82 Guidebook for Deploying Zero-Emission Transit Buses As transit resources are often part of emergency management planning , resilience and emergency response planning are an essential element of your ZEB deployment. FCEB systems require power for fueling infrastructure to operate and depend on a hydrogen supply stored, or created, on site. BEB charging infrastructure also requires continual power to operate. Consider existing abnormal procedures for your diesel or CNG fleet when developing a resilience plan for your ZEB fleet. Your transit agency needs to understand what risks your system may face, how new vehicles will or will not factor into existing emergency response planning, and what strategies are available for fulfi lling service needs during power outages. Establishing a plan for both short- and long-term power outages is important. 4.8.1 Understanding Reliability of Your Operations The first step in creating your resilience plan is to understand what types of disruptions are likely to occur in your area. Request reliability reports from your utility to understand the duration of historical disruptions to inform what types of regular outages to plan for , as well as service restoration times during significant weather events. Areas exposed to hurricanes and ice storms may be more vulnerable to more frequent longer-term outages. 4.8.2 Providing Service During a Power Outage Once you have an idea of the type and duration of disruptions, you need to consider what minimal service your transit agency needs to provide in order to fulfill its mission. There may be different goals of operation, depending on the time of day, day of the week, type of event (e.g., power outage versus significant weather events, such as hurricanes) , and the services your transit agency provides (e.g., evacuation services) . Create a backup plan for each type of occurrence and ensure operations and maintenance personnel are trained on the necessary procedures. 4.8.3 Emergency Backup Systems After assessing the likelihood and duration of disruptions, you may find that additional infrastructure is needed to satisfy your minimum service needs. There are several options for emergency power backup systems, providing different levels of resilience, each with advantages and disadvantages (Table 4-1). Talk with your utility provider about options you are exploring since some may require grid interconnection. In addition to providing backup power during outages, some backup solutions may be utilized to offset peak-demand loads or defray grid consumption, helping reduce your overall energy costs. For example, solar panels may be utilized to help power charging stations or on-site energy storage systems could help provide power during peak-demand periods. Be sure to understand available technology solutions, utility programs, and the cost benefit of avoiding time-of-day charges as this may help reduce the cost of your solution. Consider talking with a local hospital or other establishments with emergency response and resilience plans to learn electrical distribution design and maintenance procedures. 4.8 Resilience and Emergency Response Planning

Fueling Infrastructure Strategy and Cost 83 Table 4-1. Summary of available options for backup power. SYSTEM NAME DESCRIPTION ADVANTAGES DISADVANTAGES Dual power feeds Providing two independent electricity paths to your charging infrastructure • Familiar implementation as many electricity customers require this • If one power path faults, the other continues to provide a path for power • Still requires a backup power source to ensure reliability as line faults, alone, are a small risk for deployments • Line extensions may be costly if needed • Requires additional space for equipment Backup power generator— internal combustion engine Utilizing diesel or natural gas to generate power on site • Can operate when needed as baseload, backup, or peak curtailing • Can automatically provide power when a disruption in the grid supply is detected • Mature, stable technology with several manufacturers • Efficient • Infrastructure is costly and requires significant space • Generators need to be correctly sized in order to prevent charger disruptions or failures; coordinate with equipment providers for correct sizing • Requires ongoing maintenance • Releases harmful emissions and noise • May require on-site fuel storage On-site energy generation utilizing wind or solar Utilizing wind or solar to generate power on site • No variable costs for fuel • Ongoing power generation can be used for daily service needs • Grid connections may be restored more quickly to smaller microgrids than larger grid systems • Will require an energy storage system to ensure power is available at all times

84 Guidebook for Deploying Zero-Emission Transit Buses SYSTEM NAME DESCRIPTION ADVANTAGES DISADVANTAGES Fuel Cells • Molten Carbonate Fuel Cell (MCFC) • Phosphoric Acid Fuel Cell (PAFC) • Polymer Electrolyte Membrane Fuel Cell (PEMFC) • Solid Oxide Fuel Cell (SOFC) Utilizing a local fuel cell stack to generate power • Very high fuel efficiencies • Water and heat are the only emissions from hydrogen fuel, low emissions from other fuels • Potential to operate base load with utility backup • Few commercially available devices, although industry is growing (Vine et al., 2017) • Need for fuel reformer in almost all applications • Start times vary based on technology used: Cold start is 1– 2 days for MCFC, 3 hours for PAFC, 1 hour for PEMFC, and 2 minutes for SOFC Dual-grid operation Installation of charging infrastructure across different portions of the power grid • Provides easy backup during localized outages, especially for fast-charge infrastructure installations • Difficult to incorporate for depot charge installations as most transit agencies don’t have two depot options with enough space for all vehicles 4.9 Additional Resources • Heavy-Duty Refueling Station Analysis Model, Argonne National Laboratory, U.S. Department of Energy • Preparing to Plug in Your Bus Fleet: 10 Things to Consider, Edison Electric Institute Table 4-1. (Continued).