Examination of Transit Agency Coordination with Electric Utilities (2024)

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CHAPTER 4 Case Examples This set of case examples highlights examples of agency-utility collaborations that can be used as an example for both transit agencies in the process of establishing a relationship with their utility and for electric utilities looking for policies and programs that are most helpful to transit agency electrification efforts. These selected case examples reflect a range of conditions and contexts: • Small, medium, and large agencies • Agencies in an early or pilot stage and those in a more advanced deployment stage • Agencies in varying climates • Agencies in rural and urban areas • Utilities with different governance structures (including a commercial subsidiary of a utility) • A variety of levels and types of collaborations The case examples reflect the varied ways that utilities can provide services and solutions to support transit agency battery electric bus programs within their different regulatory structures. Each utility will have a different approach to supporting fleet electrification: different types of policies and different This case example captures several levels of commitment to engage with transit agencies on their battery bus types of agency-utility engagement deployment. in support of BEB deployment: The case examples highlight these different approaches, the opportunities • “Green Energy Partnership” and challenges that agencies and utilities face in BEB program collabora- memorandum of understanding tions, the drivers behind these collaborations, and practical considerations (MOU) between the utility and for how to work effectively together. Each case example concludes with some the Metropolitan Council key takeaways. • EV Supply Infrastructure program under which the utility installed Metro Transit, Minneapolis-St. Paul and paid for infrastructure “beyond the meter” for a BEB Introduction fleet • Collaboration on developing Metro Transit in Minneapolis-St Paul is collaborating with the regulated Metro Transit’s ZEB Transition utility that covers its service territory, Xcel Energy, as it implements its zero- Plan emission bus transition. Theirs is one of the most well-integrated and wide- • Effort to create a bus rebate ranging agency-utility collaborations found through this synthesis research. program that did not come to This case example will cover three major initiatives: a 2019 program to install fruition infrastructure at a Metro Transit bus facility; the development of Metro Transit’s • Ongoing collaboration between Zero Emission Bus Transition Plan; and a failed effort to establish a bus rebate leads at the agency and the utility program. It will also examine the two entities’ overall relationship, how it is maintained, and the benefits it provides. 29 

30   Examination of Transit Agency Coordination with Electric Utilities Transit Agency BEB Program Metro Transit operates in the Twin Cities area of Minnesota, providing transportation services in 90 cities and over seven counties. The agency is an operating division of the Metropolitan Council (Met Council). Met Council is the regional policy-making body, planning agency, and provider of essential services, including transit, in the Twin Cities metro area. Metro Transit’s transportation services include light rail, bus rapid transit (BRT), fixed-route bus service, and a commuter rail line. In its 2022 Metro Transit Facts publication, Metro Transit reported operating a fleet of over 700 buses, including 40-ft. and 60-ft. buses, and diesel, hybrid-electric, and battery electric pro- pulsion systems. The agency operates in a primarily urban environment. Metro Transit’s service territory experiences a wide temperature range. These include the low temperatures associated with Minnesota; the agency experiences many days below zero and, significantly, multiple feet of snow each winter. The service territory also has highs over 90°F during the summer months. This temperature range and the snowy conditions affect BEB operations in terms of range reduc- tions due to cold weather and the need to heat the buses, but also the need for cooling during hot months. While Metro Transit is not subject to regulatory requirements to transition to zero-emission buses under a particular timeline, under state statute Met Council is responsible for developing a ZEB transition plan and conducting five-year reviews of the plan. Metro Transit also has a history of adopting new clean technology buses, including hybrid-electric buses. The first hybrid buses were introduced into the fleet in 2002, and the agency ultimately deployed around 136 hybrid buses through 2015. The agency’s BEB program is in the pilot stage (see Figure 4). The program launched in June 2019 and currently has eight battery electric buses in service on the METRO C Line BRT service. Figure 4.   Metro Transit battery electric bus (courtesy Metro Transit). 

Case Examples   31 Infrastructure includes both DC chargers for depot charging and two overhead conductive on-route chargers. Xcel Energy supported the infrastructure deployment for the pilot buses. After launching its BEB pilot, Metro Transit developed and released a ZEB Transition Plan in February 2022, in accordance with Minnesota statute, and put in place a schedule to review and revise the plan every five years. The Transition Plan identifies opportunities, risks, and implementation strategies for transi- tioning the agency’s bus fleet to zero-emission technology in three time horizons: short-term (2022–2027), medium-term (2028–2032), and long-term (beyond 2033). The February 2022 plan sets out the following ZEB adoption goals: • Short term, between 2022 and 2027: the plan sets a target for at least 20% of Metro Transit 40-ft. bus replacement purchases to be electric. • Medium term, between 2028 and 2032: the plan states the percentage of Metro Transit bus procurements that are zero emission is to be driven by key performance indicators and avail- able budgetary resources. Metro Transit included Xcel Energy throughout the development of the plan to provide input on locations and timing of the BEB rollout and infrastructure deployment. The two entities con- tinue to work closely together to execute the BEB rollout outlined in the Plan and continue to look for other opportunities to collaborate. Utility Overview Xcel Energy is a regulated electric and natural gas delivery company that serves customers in the Midwestern and Western regions of the United States. Xcel Energy is a holding company that operates through four utility subsidiaries: the Northern States Power Company–Wisconsin, serving Michigan and Wisconsin; Public Service Company of Colorado, serving Colorado; Southwestern Public Service Company, serving New Mexico and Texas; and the Northern States Power Company–Minnesota, which serves Minnesota, North Dakota, South Dakota. Metro Transit is a customer of the Northern States Power Company–Minnesota, but this case example will simply refer to “Xcel Energy” or “Xcel.” Xcel Energy has made a corporate commitment to clean, renewable energy and transportation electrification. In Minnesota specifically, Xcel offers a wide range of programs to support renew- able energy and transportation electrification for residential, commercial, and public sector cus- tomers. This larger corporate commitment is reflected in Xcel Energy’s ongoing collaboration with Metro Transit’s BEB transition program. From the utility’s perspective, transit bus electrifi- cation supports the grid while promoting conservation efforts and helps the utility contribute to carbon reduction by reducing the number of combustion engines. Details of Agency-Utility Collaboration The partnership between Metro Transit and Xcel Energy has its origins in a 2018 MOU between Xcel Energy and Met Council. In June 2018, these two parties announced the “Green Energy Partnership” under which Met Coun- As a top 10 customer of Xcel cil and Xcel Energy would work together on renewable electricity purchases Energy, Met Council was able to and transportation electrification. Specifically, the partnership set a goal of secure active and engaged support getting Met Council to 100% renewable energy use by 2040. At the time of for bus electrification from the the announcement in June 2018, Met Council typically purchased around utility. 245,000 megawatt-hours (MWh) of electricity annually, making it one of 

32   Examination of Transit Agency Coordination with Electric Utilities Xcel Energy’s Top 10 customers. Interviews with Xcel and Metro Transit made clear that Met Council’s status as a major Xcel customer is an important element in enabling this relationship. The Green Energy Partnership MOU also established a formal partnership between Xcel Energy and the council for “creating electric bus pilot programs, pursuing funding, and sharing data with the goal of further advancing electric bus technology” (Metropolitan Council 2018). Of note, the partnerships announcement stated that “the partnership should be advantageous to the Council and Xcel, and that it should not in any way disadvantage other Xcel ratepayers.” This statement reflects the regulatory framework under which investor-owned utilities work: they are governed by a Public Utilities Commission and are obligated not to favor any particular ratepayers over others. EV Supply Infrastructure Program and Metro Transit The first collaboration specifically on Metro Transit’s BEB program involved the pilot fleet’s infrastructure deployment. Currently in Minnesota, Xcel offers three Fleet EV Solutions: Opti- mize Your Charge; Fleet Electrification Advisory Services; and EV Supply Infrastructure. The EV Supply Infrastructure (EVSI) program is available only to public sector organizations, and Metro Transit was a “pilot” customer of the program. Indeed, Xcel Energy provided the services now offered through the established program before it was officially approved by the Minnesota PUC. The EVSI program enabled Xcel to provide support “beyond the meter” for Metro Transit’s pilot BEB program. Figure 5 depicts the flow of electricity from the transformer through the meter, wiring, and charging stations to the bus. Typically, a utility will only provide the infra- structure needed up to the meter—in other words, in this depiction, only to the transformer that provides service to the meter. Under the EVSI program, Xcel Energy not only provided the infra- structure up to the transformer but also ran conduit from the transformer to the meter through Figure 5.   EV Supply infrastructure partnership: role of agency and utility (courtesy Metro Transit). 

Case Examples   33 the connection cabinet to the charging hub in the customer facility. (Metro Transit provided the actual design of the panel to the charger, but Xcel was responsible for, and paid for, building out the infrastructure to the charger.) As part of this, Xcel also put in a separate transformer to feed electricity to the facility. Typi- cally, for additional load demand, a utility will use an existing transformer but since data col- lection is a key element of the EVSI program, Xcel put in a separate transformer and installed advanced metering. The meter collects 15-minute interval data which the agency and Xcel use to better understand the energy demands from a BEB fleet and how to manage it. As noted, Xcel submitted its filing with the MN Public Utilities Commission to engage in this “behind the meter” activity after the work had begun. Xcel felt confident that the Minnesota Public Utilities Commission (MPUC) would approve the program, as the commission recog- nized the need for electrification support in the public sector. It also proved advantageous that the program provided the same support to the State’s Capital Complex. The utility was able to include letters of support from Metro Transit and the State of Minnesota for the docket which did indeed receive approval in 2019. Metro Transit and Xcel described this work as laying the foundation for the closely inter- twined relationship that continues as Metro Transit plans for and deploys its larger BEB fleet. Collaboration on Metro Transit ZEB Transition Plan Metro Transit included Xcel Energy as a partner in the technical analysis that underpins the Transition Plan goals and timelines. Rather than develop- Metro Transit: “The transition ing a plan and then presenting it to the utility, Metro Transit identified facilities planning needs to be a collaboration for its BEB fleet deployment and consulted Xcel regarding power availability. as ultimately it needs to be in both This input was then used to develop the timeline based on the availability of entities’ capital plans.” power and the ability of the utility to provide upgrades as needed to meet the timeline. The facility upgrade timeline can also then be incorporated by Xcel Energy into its own capital planning, as shown in Figure 6. Bus Rebates One collaboration that did not come to fruition was an electric bus rebate program. Xcel put together a proposal to the Minnesota PUC for a bus rebate that would help offset the higher capital costs of battery electric buses. Metro Transit supported this proposal, but it was ultimately Figure 6.   Joint Metro Transit/Xcel Energy facility upgrade timeline (courtesy Metro Transit Transition Plan, February 2022). 

34   Examination of Transit Agency Coordination with Electric Utilities rejected by the PUC. Of note, however, the two entities found that this effort still helped them strengthen and deepen their partnership and led to productive discussions around what they are able to do together to move the needle forward on bus electrification. Future Collaborations Going forward, as Metro Transit’s BEB fleet moves beyond the pilot phase, both parties aim to enhance their understanding of energy management, explore what tools are available, and evaluate how charge management might influence future rate design at Xcel. The objective is to optimize the bus charging, minimizing the creation of new peaks and avoiding excessive demand charges. Xcel specifically hopes to enhance its understanding of energy management for trans- portation electrification overall. Xcel Energy also has an active docket for a time-of-use rate design pilot for all commercial and industrial customers. The proposal would create a three-tiered time-of-use rate. Although it is not specific to transit, Metro Transit is engaged as a fleet customer and has been active in supporting this docket at the commission. Lessons Learned Some highlights and lessons learned from this case example are: • Having a primary contact for the project at the utility and agency acting as an advocate for the BEB program helps drive progress forward. The collaboration expedites the project and expands each organization’s capabilities by sharing their respective technical expertise. • They can support one another in navigating the other organization, basically by each being an initial point of contact to locate the right departments or personnel as needed for any aspects of the project. • Creativity plays a pivotal role in their process. They constantly seek innovative ways to col- laborate. Even efforts that are unsuccessful, like the electric bus rebate concept, help foster a robust partnership and generate ideas for future endeavors. • They collaborate to convey their narrative to key stakeholders including MPUC, external industry groups, advocacy organizations, and the general public. • From a practical standpoint, they have a standing monthly meeting to discuss ongoing projects that they recommend as a best practice. • Having an executive-level commitment to transit bus electrification at each organization will be a huge help to ensuring that the project moves forward. • Playing the long game with your engagement is important. Think beyond just the immediate program demands and look at the potential future program plans. Overall, Metro Transit and Xcel encourage transit agencies to forge part- nerships with their utilities, not limited to transit bus electrification, but over This case example illustrates a type a range of shared sustainability and efficiency goals. of agency-utility engagement that offsets or alleviates both capital and operating expenses of BEB Roaring Fork Transportation deployment: Authority (RFTA) • Special time-of-use rate for off- Introduction peak charging The Roaring Fork Transportation Authority (RFTA) in Aspen, Colorado, • Financial support for infrastructure is collaborating with Holy Cross Energy, a rural electric co-op, on the depot upgrade costs charging for its eight-bus pilot BEB program. As a member-governed rural co-op, Holy Cross Energy (HCE) has been able to implement policies that have 

Case Examples   35 been beneficial to the BEB program: a time-of-use rate that incentivizes off-peak charging with low rates and offsetting some of the infrastructure upgrade costs related to RFTA’s depot charging. Transit Agency Program Roaring Fork Transportation Authority was created in November 2000 by voters in seven jurisdictions within the Roaring Fork Valley. RFTA serves an 80-mile rural-resort region in Colorado, covering Aspen to Glenwood Springs, and Glenwood Springs to Rifle. RFTA is the second-largest transit system in Colorado and the largest rural transit system in the United States. The agency operates a fleet of 100 buses in revenue service, with a spare ratio of 20 buses (see Figure 7). The agency’s service territory experiences a wide temperature range, with high temperatures that can hit over 90°F, cold temperatures below freezing, and elevation ranges from 8,000 ft. in Aspen to 5,400 ft. in Rifle. The system currently operates a fleet of eight BEBs, placed in service in 2019. This pilot BEB program was catalyzed when RFTA was awarded an FTA Low-No Grant. Additional funding to support the full fleet came from the city of Aspen and RFTA’s own capital funding. There are four DC fast chargers at the agency’s Aspen Maintenance Facility to serve the eight-bus fleet. The agency is also planning on-route charging, which will enable the BEBs to be used on longer routes. The driver for this program was the desire to be at the forefront of innovation and sustain- ability, driven both by the agency’s board and internal staff. As of the writing of this report, the agency is in the process of developing a ZEB transition plan. RFTA is also planning a multi-party microgrid project under which RFTA will install a 1-MW storage battery at the Aspen Maintenance Facility where the BEB fleet is based. The project is not directly related to the BEB fleet, but it will provide benefits in terms of providing backup emergency power and the ability to store energy at night at low overnight off-peak rates that can then be used during peak hours. RFTA’s service territory is serviced by four separate utilities: Holy Cross Energy, a rural co-op; Xcel Energy, an IOU; the city of Glenwood Springs, CO, municipal utility; and the city of Aspen, CO, municipal utility. Holy Cross Energy serves the territory where the current BEB depot is located. The on-route chargers that RFTA is preparing to install are located within Aspen munic- ipal utility’s service territory so RFTA will be working with them for that deployment. However, since only the depot chargers are in service at present, this case example focuses only on the collaboration with Holy Cross Energy. Figure 7.   RFTA BEB facility (courtesy RFTA). 

36   Examination of Transit Agency Coordination with Electric Utilities Utility Overview Holy Cross Energy is a not-for-profit, member-owned electric cooperative serving 45,000 cus- tomers in the central mountain region of Colorado. Their customers include resorts like Vail and Aspen, the primary economic drivers of this region. The region has been an early adopter of renewable energy and clean energy solutions. As a member-driven organization, HCE reflects the interests and priorities of this region. With its governance structure, it is readily able to enact programs and policies that support these interests. The utility has set aggressive targets for decarbonization: HCE’s goal is to reach 100% carbon-free electricity by 2030. The utility has moved aggressively to achieve this goal: as of 2022, HCE was already at over 50% renewable electricity. HCE also offers a special renewable electricity subscription rate through its PuRE program. Under this program, subscribers can select a 100% renewable electricity source for a surcharge. Since HCE is already 50% renewably sourced, the customer is only responsible for the cost to offset the remaining 50% of their elec- tricity use with renewables. In 2018, the utility identified transportation electrification as a key area of focus for expanding the benefits of renewable, carbon-free electricity. The utility also views the transition to electric vehicles as an opportunity in terms of potential new load, but one that needs to be managed to ensure that the new load is optimized with the grid and grid resources, especially as the utility moves to 100% renewable electricity. HCE has enacted policies that support the dual interests of supporting electrification and encouraging new load to occur at off-peak times or when the utility has excess load from renewables. The utility supports electrification across a wide range of end uses, including personal vehicles and fleets. In its 2021 EV progress report (HCE 2021, p. 15), HCE specifically identified transit as “one of the best opportunities for environmental impact reduction by EVs.” This interest helped drive the effort to find ways to support RFTA’s BEB deployments, with both financial and plan- ning support. The utility also sees a long-term opportunity in bidirectional charging that allows the utility to buy back the electricity stored in electric vehicle batteries for grid stabilization or provide power at periods of peak demand. The utility does not see this “vehicle-to-grid” model as having poten- tial with transit fleets, but it is an overall driver of the utility’s programs to support transportation electrification which includes supporting RFTA’s BEB program. Details of Agency-Utility Collaboration The two main components of the collaboration between HCE and RFTA that have helped sup- port RFTA’s BEB fleet are a favorable time-of-use rate for off-peak charging and financial support for infrastructure upgrade costs. HCE created a time-of-use rate for off-peak depot charging that has enabled RFTA to realize significant savings over regular commercial rates. Under this rate, the utility charges 24 cents per kWh for on-peak charging, defined as occurring between 4:00–9:00 pm, but for off-peak times, the utility charges just 6 cents per kWh. This off-peak charging rate is available to other electric fleet customers of HCE, not only Holy Cross Energy has implemented transit customers. an EV charging TOU rate of The depot chargers are on a separate meter, so RFTA is able to track their 6 cents/kWh for charging at off- electricity use. RFTA reports that its mechanics have been instructed on peak times, compared to 24 cents/ when to plug in the buses for recharging, and the agency has been able to kWh for peak hours. stay within this off-peak time to secure significant savings over what would be the cost at the peak charging rate. 

Case Examples   37 HCE also absorbed some of the costs of installing a new transformer, and some trenching needed when RFTA installed its depot chargers at its Aspen Maintenance Facility. As part of its commitment to low-carbon sustainable operations, RFTA takes advantage of the renewable electricity sourcing offered by HCE through its PuRE program. As noted, subscribers to this program can select a 100% renewable electricity source for a small surcharge from HCE. This program is one that is available to all customers, so is not specific to the collaboration around the BEB program. Lessons Learned Some highlights and lessons learned from this case example are • For this particular partnership, the progressive nature of the region has been a factor in driving the policies supporting the BEB pilot program at both the transit agency and the utility. • As a cooperative utility, HCE has a greater ability to explore new policies that will incentivize transit bus electrification since it is not governed by a PUC. If transit bus electrification is deemed a priority by the co-op’s members, that enables the utility to identify and enact these policies much more quickly than a regulated utility would be able to. • The relationship between the two primary contacts at the agency and the utility has been a key factor in a smooth, functioning relationship. San Diego Metropolitan Transit System (MTS) Introduction The San Diego Metropolitan Transit System (MTS) is making the transition to an all zero-emission bus fleet. In accordance with the California Air Resources This case example captures three Board’s mandate, MTS developed a plan to have a fully zero-emission fleet by primary, and interrelated, types 2040, with escalating percentages of annual new bus purchases to be zero emis- of agency-utility engagement in sion between 2023 and 2029. In this first phase of the transition, MTS is par- support of BEB deployment: ticipating in several programs offered by its electric utility, San Diego Gas & Electric (SDG&E), which is also under mandate in California to support the • MTS’s participation in SDG&E’s state’s carbon reduction goals. Power Your Drive for Fleets program MTS participates in SDG&E’s Power Your Drive for Fleets program, which • MTS’s participation in the utility’s provides financial and programmatic support for facility infrastructure build- special high-power EV charging out and takes advantage of a special EV charging rate offered by the utility subscription rate that replaces demand charges with a subscription fee based on the customer’s • Close collaboration between a electricity usage (measured in increments of 25 kW). The two entities also primary point of contact at each have a primary point of contact within each organization that helps drive and organization to facilitate regular facilitate planning and communication. meetings and communication Transit Agency Program MTS provides transit for San Diego and surrounding cities, with a 3,240-square-mile service territory. MTS describes its service environment as primarily urban, but the agency also serves rural areas within the county. MTS offers bus, light rail, paratransit, and taxicab services. Its fixed- route bus service comprises close to 100 routes, served by 630 fixed-route buses. The service territory has a mild, temperate climate without extreme heat or cold, so temperatures are not a significant factor in the expected real-world range of BEBs. 

38   Examination of Transit Agency Coordination with Electric Utilities MTS is subject to the California Air Resources Board’s Innovative Clean Transit (ICT) regula- tion adopted in December 2018 (California Air Resources Board 2019). Under this regulation, California transit agencies must submit plans showing how they will transition to a fully zero- emission bus fleet by 2040. MTS is subject to the specific requirements for large agencies under the ICT. Large agencies were required to submit a transition plan by July 1, 2020, and to have 25% of new bus purchases be zero emission starting in calendar year 2023. The percentage ramps up, with new ZEBS required to be 25% of new bus purchases from 2023 to 2025; 50% from 2026 to 2028 = 50%; and, from 2029 on, 100% of total bus purchases must be ZEBs with a goal of a 100% ZEB fleet as of 2040. (Small agencies are also required to be fully zero emission by 2040 but the initial purchase requirement starts later, in 2026.) The agency was ahead of the ICT regulation in deploying ZEBs; having launched its pilot ZEB program in October 2017, before the regulation went into effect. MTS deployed eight 40-ft. BEBs: six New Flyer BEBs equipped with 466 kW batteries and two Gillig BEBs with 444 kW bat- teries. It also installed 12 plug-in DC fast chargers from ChargePoint. The agency subsequently placed five more 40-ft. BEBs in service for a total fleet of 13 as of 2023. MTS’s latest BEB project involves a fleet of 12 60-ft. articulated BEBs to be placed on a new BRT line, the Iris Rapid. The Iris Rapid will be the first MTS service with a fully dedicated BEB fleet. These buses are on order with expected delivery in September 2023. They will operate out of the agency’s South Bay Division, where MTS will utilize a charging strategy of depot-based charging using primarily overhead chargers with two DC plug-in chargers from the BEB pilot. MTS plans to deploy a modular overhead charging design that can be scaled up as the BEB fleet grows. Under its ZEB transition plan as submitted under the ICT, MTS is slated to purchase between 10 and 13 new BEBs annually through 2025, then increase annual purchases to over 25 and more ZEBs annually from 2026 on. For the first phase of infrastructure deployment at the South Bay Division, MTS will construct an overhead gantry system capable of charging 24 battery electric buses at a time. MTS will also have eight DC charging power cabinets as part of this first phase (three buses will charge on one power cabinet). MTS has worked closely with their electric utility on the planning and execution of this project. MTS is working within a program offered by SDG&E for medium and heavy-duty fleets called Power Your Drive for Fleets, which supports the charging infrastructure buildout needed at the South Bay Division. The agency is also taking advantage of a special commercial EV rate offered by SDG&E. Finally, MTS is engaging the utility in planning the next phase of its BEB rollout plans. Utility Overview San Diego Gas & Electric is a regulated public utility that serves San Diego and southern Orange counties in California. It distributes energy service—both electric and natural gas—to 3.7 million customers in a 4,100 square mile service territory. SDG&E is a subsidiary of Sempra, a utility hold- ing company headquartered in San Diego. SDG&E is actively engaged in supporting transportation electrification through a variety of programs and rate mechanisms. These programs are designed to help California meet its ambi- tious goals for greenhouse gas reductions that have been established by a number of legislative and executive actions, including the 2015 Senate Bill (SB) 350 that set clean energy, clean air, and greenhouse gas reduction goals for California for 2030 and beyond, and SB 100, passed in 2018, which requires 100% zero-carbon energy by 2045. As an investor-owned utility, SDG&E is under the regulatory oversight of the California Public Utilities Commission (CPUC). The CPUC has been specifically directed under California law to 

Case Examples   39 direct its regulated utilities to undertake transportation electrification activities. Any proposed programs must also be reviewed and approved by the CPUC before they can go into effect. In January 2016, SDG&E received approval for a program to support EV infrastructure roll- out, called the Power Your Drive (PYD) program. The program has multiple tranches that support different types of end users and charging locations. Initially, the program focused on passenger car EVs and locations where these drivers are likely to need charging such as the workplace and at home. In late 2019, SDG&E received approval to expand the program to fleets, including transit fleets, and the Power Your Drive for Fleets program was subsequently launched in 2020. Also in 2020, SDG&E received authorization for a new commercial rate for separately metered EV charging loads of 20 kW or higher. Both programs have been utilized by MTS in its BEB fleet program. SDG&E has continued to commit itself to supporting California’s carbon reduction goals. In 2022, SDG&E published its Path to Net Zero report (SDG&E et al. 2022) which provides a road- map for how the utility will seek to achieve California’s 2045 net zero energy goal. The report identifies transportation electrification as key to achieving net zero energy, with infrastructure costs highlighted as a top barrier to widespread transportation electrification. Details of Agency-Utility Collaboration MTS is a participant in SDG&E’s Power Your Drive for Fleets program, subscribes to the utility’s special high-power EV charging rate, and maintains a regular cadence of meetings and communications between the two organizations to plan future BEB infrastructure deployments planned by the agency. MTS and Power Your Drive for Fleets MTS was one of the first customers to participate in SDG&E’s Power Your Drive for Fleets program, launched in 2020 and set to conclude in 2025. Medium- and heavy-duty fleets and fleet vehicles of all types—trucks, buses, vans, and off-road vehicles are all eligible—can apply to the program, which provides financial support for charging infrastructure deployments. Sig- nificantly, SDG&E is allowed to pay for, or reimburse the costs of, infrastructure “behind the meter”—i.e., on the customer side of the meter, which is normally prohibited for investor-owned utilities. Fleets also receive programmatic support, from early planning through design, con- struction, and ongoing site maintenance. Fleet customers may choose from two different options under the program. Under Option 1: SDG&E-Owned, SDG&E pays for, constructs, owns, and maintains all infrastructure up to the charging station. As illustrated in Figure 8, SDG&E pays for the transformer, meter, and switchgear—all infrastructure that occurs behind the meter on the customer side. The charging station is paid for, owned, and maintained by the customer, but SDG&E provides rebates for a portion of the costs for certain approved equipment. MTS participates in the program under Option 2: Customer-Owned. In this option, the utility only pays for, and is responsible for, infrastructure upgrades up to the meter. The customer is responsible for everything from the meter to the charger (as indicated in Figure 9) but receives a rebate for up to 80% of the design and construction costs and up to 50% for the charging equip- ment costs for school bus sites, transit bus sites, and sites located in a Statewide Disadvantaged Community (as determined through an official California state screening tool). MTS utilized Option 2 because the agency’s choices of primary metering and future installa- tion of associated distributed generation resources are not eligible for the SDG&E-owned option. MTS reports that, since the overhead charging was not fully eligible for rebates, a significant 

Figure 8.   SDG&E Power Your Drive for Fleets, Option 1 (courtesy SDG&E). 

Figure 9.   SDG&E Power Your Drive for Fleets, Option 2 (courtesy SDG&E). 

42   Examination of Transit Agency Coordination with Electric Utilities portion of the costs related to the overhead installation such as the gantry steel structure was not able to be paid for by the utility. MTS estimated that only about 23% of the customer-side design and construction costs were reimbursed through the program, and 43% of charging equipment costs will be reimbursed. In both options, SDG&E provides support to the customer in design, engi- SDG&E created a timeline for neering, power capacity, and load assessment. SDG&E gives program par- the completion of transit facility ticipants a high-level step-by-step timeline to completion, highlighting each charging infrastructure to help phase and the support that SDG&E provides to the agency through the infra- fleets in their own planning structure development process, as highlighted in Figure 10. process. On its website, SDG&E lays out the time needed to complete each of these steps and estimates a total timeline of 11–16 months from start to completion if local power substations have capacity. MTS noted that the timeline may be extended to 24 months or more if SDG&E’s substations do not have the capac- ity needed and require upgrades. This schedule can help agencies in creating their internal BEB program road map. Customers in the Power Your Drive for Fleets program are required to Participants must provide SDG&E install a separate meter for the charging in order to take advantage of the Elec- with at least five years of charger tric Vehicle-High Power rate and provide SDG&E with charger usage data for at least five years. This requirement is typical of many of the utility pro- usage data under the Power Your grams examined in this synthesis; it seems to be a central driver for the utility Drive for Fleets program. sector in providing financial support for transit bus electrification efforts: to understand the total new demand and the demand cycles from high-power battery bus charging so that the utility can prepare for and manage new load from large-scale transit bus electrification. The separate meter also provides a benefit to the agency so that the agency itself can understand the fleet’s energy usage and create an energy management strategy. MTS reports that it uses the data from each charger to secure credits under the Low Carbon Fuel Standards in California. Electric Vehicle-High Power (EV-HP) Charging Pricing Plan In 2020, SDG&E received authorization from the CPUC for a new commercial rate for sepa- rately metered EV charging. The Electric Vehicle-High Power (EV-HP) pricing plan is offered to medium, heavy-duty, and off-road fleets that use greater than 20 kW demand. The central feature of this rate plan is that customers using this rate do not incur demand charges. Demand charges are regularly cited by transit agencies as a key risk factor in converting to a battery electric bus fleet, as they add significantly to BEB fleets’ energy costs and because of their unpredictability from the customer’s point of view. To address this concern, SDG&E crafted this subscription rate option. Customers who opt into the EV-HP program select the amount of power they will need and pay for this electricity through a set monthly fee. SDG&E works with the customer to estimate likely monthly usage. If the customer exceeds this amount in any given month, they are not charged a penalty or overage fee; however, if they exceed this amount for three consecutive months, they are automatically enrolled in a higher-level subscription plan. The plan also uses time-of-use rates to encourage customers to charge at off-peak hours. These TOU rates are somewhat lower than the regular commercial TOU rates, except for the on-peak kW rate. MTS began subscribing to this EV-HP rate in July 2021 and reports that it has helped the agency manage its electricity bills in comparison to the standard Commercial TOU rate. MTS and SDG&E Relationship The relationship and communication cadence between key personnel at MTS and SDG&E is an important engagement tool that supports MTS’s BEB program. As one of SDG&E’s largest customers—due to its overall electricity usage, not specifically the BEB program—MTS is 

Figure 10.   SDG&E Power Your Drive for Fleets Electrification timeline (courtesy SDG&E). 

44   Examination of Transit Agency Coordination with Electric Utilities assigned an account executive and a public relations manager and is “on the radar” of the execu- tive leadership at SDG&E as a key customer. In addition to this overall account management, SDG&E has a customer solutions advisor work- ing with MTS for the clean transportation programs specifically. This role serves as a single point of contact and can act as the liaison for MTS with any other contacts needed within the utility. SDG&E and MTS hold monthly status update meetings for not only the clean transportation programs but also any other facility projects underway; these help both organizations coordinate ongoing and planned projects and stay abreast of any issues that arise. SDG&E reported that regular communication between the two entities is a critical factor in ensuring the infrastructure projects run smoothly. MTS also noted that a benefit of the Power Your Drive for Fleets program is that it brought various elements of the infrastructure “under one roof,” making it much easier for MTS to navigate the organization and find the right contacts in a timely fashion. MTS reported that it is exploring installing a compressed natural gas backup generator, solar and energy storage system (microgrid solution) for electric charger redundancy/peak shav- ing strategy. This is managed through separate utility department(s) and requires additional coordination. Lessons Learned Some highlights and lessons learned from this case example are • Both the agency and the utility are under a variety of state mandates and regulations for greenhouse gas emission reductions and zero-emission targets. These act as drivers for both entities to prioritize working together as they need the other partner in order to achieve their own goals. • The ability of SDG&E to offer a special charging rate and to pay for infrastructure on the cus- tomer side of the meter is the result of state regulations. • The close engagement of the utility with MTS is also driven to some degree by MTS’s status as a key customer. • The close partnership between key personnel and regular meetings to discuss the BEB project (and other projects) are cited as an important practice by these two entities. • In its program to offset infrastructure costs, the utility requires the installation of a separate meter and data collection. The utility requires a coordination study and third-party inspection of customer-owned power distribution equipment before installing a meter and energization. • The utility provides a clear timeline through the Power Your Drive for Fleets program of 11–16 months from initiation of interest to completion of an electrification project. If the utility does not have capacity at local substations near the project site, the timeline may be 24 months or more. • MTS’s decision to take the primary metering and future planned installation of distributed resources for this first phase had important implications for the kind of support MTS could receive under the Power Your Drive program. Pinellas Suncoast Transit Authority (PSTA) Introduction Pinellas Suncoast Transit Authority (PSTA) is collaborating with Duke Energy, the investor- owned utility that provides service for PSTA’s service territory, and with Duke Energy Sustainable Solutions (DESS), a wholly owned subsidiary of Duke Energy that operates as an unregulated entity. PSTA has been able to partner with both entities in ways that support the agency’s aggres- sive BEB adoption timeline and the significant infrastructure upgrades needed to support the 

Case Examples   45 coming BEB fleet. This case example covers the utility solutions and services provided by Duke Energy—which includes its Park and Plug Program and This case example captures transit its EV Complete Charger Rebate Program—as well as PSTA’s agreement with agency collaboration with both DESS for the design, construction, operations, and maintenance of electrical regulated utility and the affiliate infrastructure. company of the utility: • Utility support in developing a Transit Agency Program plan to manage projected load PSTA operates in Pinellas County, Florida. The agency has 220 fixed-route from BEB charging buses operating on 41 bus routes. It operates in a densely populated service • Utility rebates for charging territory with a primarily urban service environment. The operating environ- equipment ment experiences fairly consistent moderate temperatures, with some high • Agreement with affiliate temperatures during the summer months. The agency is in a hurricane-prone company to install, operate, and region, however, so hurricane-preparedness is a key part of agency planning. maintain charging equipment for 10 years PSTA has many years of experience operating a hybrid-electric bus fleet and, in 2018, launched its first battery electric buses into service. As of the writing of this report, the agency is operating six BEBs with six depot chargers. The agency has 62 BEBs on order. This means the agency is preparing to go from managing a small pilot fleet to one of the largest active fleets in the United States. The order is coming in stages, with the first tranche of 12 BEBs arriving in early 2024. To serve these, PSTA is installing a set of 200-kW DC fast chargers in its depot, a significantly higher power demand than the 80-kW AC chargers and 62 kW DC chargers currently in place. PSTA also operates a 250-kW inductive charger for wireless charging. This program is part of the Sustainable Strategic Plan that PSTA’s board adopted in March 2021. The plan includes a broad range of environmental sustainability projects, including solar panel installation and energy efficiency installations. The plan also commits PSTA to transition its full bus fleet to zero emission by FY2050. Utility Overview Duke Energy is one of the United States’ largest energy-holding companies. Its electric utilities serve customers in North Carolina, South Carolina, Florida, Indiana, Ohio, and Kentucky. The Duke Energy subsidiary providing utility services for this project is Duke Energy Florida. Through- out this case example, it will be referred to as “Duke Energy” for simplicity. Duke Energy has a clean energy strategy with goals of at least a 50% carbon reduction by 2030 and net zero-carbon emissions by 2050. This case example also covers the PSTA agreement with Duke Energy’s subsidiary, Duke Energy Sustainable Solutions. This entity operates as an affiliate company and is not subject to utility regulations. (DESS is also referenced in the Charlotte Area Transit System case example.) Details of Agency-Utility Collaboration The collaboration between Duke Energy and PSTA involves several components: services provided by Duke Energy to help PSTA understand how to manage the load of its coming 62-bus fleet, rebates for chargers with separate metering to understand energy use, and utility-side infra- structure upgrades that will be needed to serve the much bigger BEB fleet (see Figure 11). PSTA participated in a pilot program launched in 2018 by Duke Energy to install charging stations in Florida. Under the “Park and Plug” program, Duke Energy pays for chargers to be 

46   Examination of Transit Agency Coordination with Electric Utilities Figure 11.   PSTA BEB infrastructure (courtesy PSTA). installed for light-duty and fleet vehicles in public locations, workplaces, multiunit dwellings, and at fleet locations like transit. In 2018, PSTA was reimbursed by Duke Energy under this new program for two chargers that it had installed at its depot. Duke Energy then paid for the next four chargers installed to serve the six-bus battery electric fleet. Under this program, PSTA owns the chargers and selects the charger equipment to be installed. The chargers have been placed on a separate meter, so Duke Energy is able to collect data from the charging stations that the utility uses to better understand the impact of this new load from bus charging on their system. Following this program, Duke Energy implemented the EV Complete Charger Rebate Pro- gram, which offers participants a rebate for the purchase of a charging station. The program serves a wide range of customers. For a transit customer, Duke provides up to $24,423 per charger with a dedicated capacity of at least 20 kW. As with the Park & Plug program, customers must install the chargers behind a separate meter so that Duke Energy is able to collect data and track the demand on the grid from the bus fleet. To be eligible for the rebate, customers must also be on a specified non-demand (i.e., off-peak) time-of-use rate. This was a key element of Duke Energy’s filing with the PUC to receive approval to offer this solution: that it would encourage customers to charge during off-peak hours. As part of its partnership with PSTA, Duke Energy ran a set of four charging scenarios for a 60-bus fleet to assess the potential impacts and determine how to manage the energy demand. This is a service offering that provides benefits both to PSTA and Duke Energy. By conducting this analysis, Duke Energy also determined that it would be useful to modify its Complete Charger Rebate Program. The scenario analysis showed that the use of a demand TOU rate provided as much of a benefit as the non-demand off-peak rate, so Duke Energy is in the process of trying to modify the program to allow rebate program customers to utilize the peak rates. Since this program is a regulated offering, it is part of the official rate structure overseen by the PUC. Duke Energy is in the process of filing with the PUC to allow this change. 

Case Examples   47 The overall driver for Duke Energy’s engagement with PSTA is the utility’s desire to under- stand and plan for the coming new load due to transportation electrification (see Figure 12). The opportunity to gather data from PSTA’s charging operations—and from all the rebate customers—can be used by Duke Energy to understand the potential impacts on its system. Duke Energy has hired someone to take on the role of understanding the potential for fleet electrification in Florida, looking at potential loads, and assessing needs in terms of upgrades of infrastructure and any other implications on Duke Energy’s grid infrastructure. Since Pinellas County includes densely populated areas, there can be challenges to building out new infrastruc- ture; therefore, the utility is looking ahead at how to facilitate and manage that process. Finally, as noted, PSTA has a 10-year agreement with Duke Energy’s for-profit arm, Duke Energy Sustainable Solutions (DESS). This agreement is for the design, construction, operation, and maintenance of electrical infrastructure needed for 12 DC fast chargers. Under this agree- ment, DESS will operate the equipment for 10 years for the first 12 DC fast chargers. This project opened in September 2023. Figure 12.   Power needs (diagram courtesy PSTA). 

48   Examination of Transit Agency Coordination with Electric Utilities PSTA noted that the agency did face a few challenges in getting this agree- PSTA has an agreement with ment in place. For example, the lack of dedicated funding sources for opera- the utility’s for-profit arm, DESS, tional expenses for PSTA was a challenge in creating a long-term agreement under which DESS will operate the with DESS. There were also challenges in determining how to leverage federal electrical infrastructure for a small funds in the agreement since the federal funding is subject to Buy America fleet of buses for 10 years. requirements. The two sides were able to work out these issues, the agreement was put into place, and construction is underway for the facility. However, this example highlights issues to be aware of in signing agreements between a transit agency and a commercial subsidiary like DESS. This infrastructure project requires all three parties to be engaged and working together. Duke Energy helped facilitate the initial outreach between PSTA and DESS, and Duke Energy is putting the infrastructure in place on the utility side to accommodate this new bus fleet. This involves substantial investments from the regulated utility side, including updating the trans- former and substation and installing a new feeder. Duke Energy and DESS are careful in their work together to keep a clear separation between what the regulated and unregulated entities have responsibility for. PSTA and Duke Energy are continuing to explore other sustainability initiatives together. They are currently considering a plan to install solar panels and energy storage at PSTA, to enable PSTA to become more energy self-sufficient. Overall, the partnership between PSTA and Duke Energy has been instrumental in PSTA’s electric bus program. The ongoing collaboration between the two organizations helps each execute its commitments to electrified fleets, decarbonization, and broader clean energy initiatives. Lessons Learned Some highlights and lessons learned from this case example are • This case example again highlights the importance of engaging the utility early before embark- ing on an ambitious program of electrification. It’s important for all parties to understand what a large-scale BEB deployment will take and what the time frame and time restrictions are from both the utility and agency sides. • A top driver for the utility in this partnership is the ability to separately meter the bus chargers and collect data to understand the potential impacts of BEB charging on its infrastructure. • Having a single point of contact at the agency and the utility is tremendously helpful. It helps each party navigate its partner organization more effectively and enables each partner to find the right people for various aspects of the project. • Communication is also critical. Duke Energy and PSTA have frequent calls that include all the relevant parties from their respective organizations. • Establishing a relationship with the utility and regular cadence for communication can generate ideas for future collaborations. Duke Energy and PSTA began their conversations around PSTA’s interest in installing solar panels, and this led to conversations on Duke’s EV rebate program, backup power, and more. Charlotte Area Transit System (CATS) Introduction The Charlotte Area Transit System (CATS) formed a public-private partnership with eTransEnergy, a wholly owned subsidiary of Duke Energy, to implement a battery electric bus pilot program, set to conclude in October 2023. eTransEnergy served as an engineering, procurement, and 

Case Examples   49 construction (EPC) service provider to CATS for the deployment of charging infrastructure, the only case example in this report to capture this type of This case example captures a transit relationship. In its role, eTransEnergy worked with CATS to plan, implement, agency collaboration with an and manage the pilot program of 18 buses and 10 DC fast chargers. Because affiliate company of a regulated eTransEnergy is an affiliate company, it was able to provide services that are utility: different from what a regulated utility can. Duke Energy played a typical utility role of evaluating and upgrading service to provide the power requirements • Providing engineering, for the facilities out of which the BEBs operate. procurement, and construction services to help the agency launch a pilot BEB program Transit Agency Program The Charlotte Area Transit System (CATS) is a department of the city of Charlotte and provides bus, light rail, streetcar, vanpool, and paratransit services. The agency’s service area encompasses 675 square miles with a population of over 1.3 million. CATS’s vehicle fleet includes around 300 buses, 83 paratransit vehicles, and 87 van- pool vehicles, in addition to its fleet of light rail and streetcar vehicles. The agency operates in a primarily urban environment and experiences both high temperatures that can rise to over 90°F in summer and winter temperatures below freezing. CATS’s electric bus pilot program was originally designed to test whether battery electric buses could operate to meet the agency’s service needs in its service area climate and topography, with a plan to procure six BEBs and six DC fast chargers to test them in CATS’s operating environment. Over time, the aim of the pilot program evolved to become a comparative test of different manufacturers’ buses and chargers. As part of this evolution, the agency expanded its pilot from six to 18 buses and secured a partnership with eTransEnergy. The BEB pilot is a first step in the agency’s commitment to transition its fleet to zero emissions. This commitment is aligned with and in support of the city of Charlotte’s Strategic Energy Action Plan, passed in December 2018. The city’s plan sets an overall goal for Charlotte to become a low-carbon city by 2050 and specifically for the city fleet and facilities to be fueled by 100% zero- carbon sources by 2030. In 2022, CATS officially launched the pilot program into service, operating a mixed fleet of 18 BEBs from two different manufacturers and charging infrastructure comprising 10 dual-port DC fast chargers, also from two different manufacturers. The buses operate out of two CATS maintenance facilities. The CATS BEB pilot project received funding from a FY2020 FTA Low-No award of $3.7 million to support the purchase of six buses. It also received technical support through the Bloomberg Philanthropies American Cities Climate Challenge, a program designed to help 25 large U.S. cities meet carbon emission reduction goals. The remainder of the funding for the bus procurement comes from CATS’s Capital Investment Program. Utility Overview For this case example, the primary focus is on CATS’s relationship with eTransEnergy, which operates under the Duke Energy Sustainable Solutions (DESS) brand. As described in the PSTA case example, the Duke Energy Sustainable Solutions brands are subsidiaries of Duke Energy, one of the United States’ largest energy-holding companies. Its electric utilities serve customers in North Carolina, South Carolina, Florida, Indiana, Ohio, and Kentucky. The Duke Energy subsidiary pro- viding utility services in North Carolina and for this project is Duke Energy Carolinas (DEC). Duke Energy has a clean energy strategy with goals of at least a 50% carbon reduction by 2030 and net zero-carbon emissions by 2050. The creation of a commercial brand providing direct 

50   Examination of Transit Agency Coordination with Electric Utilities services to customers around clean energy aligns with Duke Energy’s carbon goals. However, these DESS brands operate as affiliate companies, which means they aren’t subject to utility regulations. They are therefore able to offer solutions and services directly to customers that the Duke Energy parent company may not offer as a regulated utility. Launched in early 2021, eTransEnergy specifically focuses on fleet electrification solutions. In this role, eTransEnergy works with transit agencies, school districts, and others to assist with all aspects of electrifying their vehicle fleets, from financing and charging infrastructure to strategy, operations, and maintenance. DEC retained its traditional role as the provider of energy needed at CATS’s battery electric bus facilities (see Figure 13) for the pilot fleet. eTransEnergy’s business model does not take the place of a utility role as a provider of energy but rather allows it to offer services that support customer needs for project management, infrastructure planning and installation, and energy management as they relate to fleet electrification. Details of Agency-Utility Collaboration In 2020, as CATS was developing plans for its BEB pilot, the agency received an unsolicited proposal from eTransEnergy on a range of services that the company could provide in support of the BEB pilot. These include project management and engineering and design support. Fol- lowing this, CATS developed an open request for proposal process, and an independent panel selected eTransEnergy out of this procurement process. When CATS submitted its 2020 Low-No Grant proposal, both eTransEnergy and Duke Energy were listed as partners in the proposal. Having an entity other than a bus OEM as the project partner is somewhat unusual in the Low-No process. CATS noted that it chose this route because, by the time the agency was working on the 2020 grant proposal, it had shifted its vision for the pilot. CATS wanted to use The eTransEnergy partnership in the pilot to help the agency understand different manufacturer offerings as it the pilot project has spurred a prepared for the long-term BEB transition. Having eTransEnergy as a partner transformation in how CATS will enabled it to use the grant funding to test various offerings rather than locking approach future sustainability CATS into a partnership with one manufacturer. projects in the next phase of the eTransEnergy became a key project management partner in the pilot project. agency’s BEB transition. Its role included helping with procurement, facilities planning, charging infra- structure installation, and monitoring. Duke Energy Carolina’s distribution Figure 13.   CATS electric buses (courtesy Duke Energy). 

Case Examples   51 planning engineers worked with CATS and eTransEnergy to establish capacity requirements at the two depots based on the project load profile for each site. As noted, Duke Energy was also a project partner. For this pilot, there was a fairly traditional customer-utility relationship with CATS contacting Duke Energy about its new load and energy needs at the two facilities. Duke Energy’s engineers worked with CATS to determine what was needed and provided the needed energy up to the meter, while eTransEnergy dealt with the infra- structure behind the meter. eTransEnergy operates entirely independently of Duke Energy, so there is no special consid- eration given to the CATS project in terms of power upgrades or other utility components due to the agency’s relationship with eTransEnergy. As this pilot project winds to a close in October 2023, CATS is looking to its next phase and is working with Duke Energy to prepare for a larger fleet of battery buses. CATS noted that not only did eTransEnergy allow the agency to successfully meet its goals with the pilot phase, but it also has kicked off a transformation in how CATS will approach future sustainability projects as it implements its vision for a clean energy transition. Other transit agencies can consider this type of partnership to help them get their pilot projects off the ground. The benefits are the expertise that an agency just starting a BEB program may not have in-house. Lessons Learned Some highlights and lessons learned from this case example are • A key lesson learned for the agency from this pilot is the importance of data in understanding the buses’ real-world energy use and how to manage energy use and cost. • The agency also found it valuable to set up the BEB facility on a separate meter. One of the two BEB facilities at CATS needed a new transformer so the facility was put on a separate meter. Having this facility on its own meter gives CATS a better view into the fleet’s energy use and the impacts of the rate schedule at this facility on overall energy costs. CATS staff members stated that they believe this is an opportunity to manage their BEB fleet’s energy usage with good data. • CATS reported that interoperability of data collection and management across the bus chargers is a significant challenge. Even with standards in place, the project team found that it’s chal- lenging to sync up and compare data from different manufacturers’ buses and chargers. It’s important to make sure they can all “speak coherently” together. King County Metro Introduction This case example captures two types of agency-utility engagement King County Metro (Metro) has one of the largest battery electric bus fleets in support of BEB deployment: in the United States, with 51 battery electric buses as well as 174 electric trol- ley buses. Metro has an ambitious plan to convert its large bus fleet to zero • A pilot EV commercial rate emission by 2035. The plan calls for the staged introduction of increasingly • An MOU between the agency larger BEB fleets in coordination with facility and infrastructure buildout. and the utility establishing a The agency’s approach allows it to test a variety of BEB and charging tech- close partnership in the site nology options as it grows its BEB operations. design and planning process for infrastructure buildout In carrying out its plans, Metro has been working closely with Seattle City Light, a municipal utility that provides electricity in the transit agency’s service 

52   Examination of Transit Agency Coordination with Electric Utilities territory. Project leads from the agency and the utility work in close collaboration in planning the infrastructure needed to operate and maintain Metro’s growing BEB fleet. Both are public agencies—Metro is governed by the county and Seattle City Light is a city-owned and run electric utility—whose constituencies prioritize environmental stewardship. Working together enables both entities to achieve their sustainability and climate goals. (Note that investor-owned utility Puget Sound Energy also provides electricity to portions of King County Metro’s service territory, but this case example focuses on the agency-utility col- laboration for the current phase of Metro’s BEB rollout. In addition, the facilities for this phase are served by Seattle City Light.) Transit Agency Program King County Metro operates in the Puget Sound region of Washington State. It is the largest public transportation agency serving this region, offering a wide diversity of services including bus and paratransit service, as well as operating the King County Water Taxi, Seattle Streetcar, Sound Transit Link light rail, and Sound Transit Express bus service. The agency operates in a primarily urban environment with a fairly temperate climate, although the region does experi- ence days with freezing temperatures or temperatures at 90°F or higher. It is one of the largest agencies in the United States with a fleet of more than 1,300 transit buses that includes 35-ft., 40-ft., and 60-ft. articulated buses. It also operates one of the few fleets of electric trolley buses in the United States and has a large number of hybrid-electric buses. Because of this experience, the agency has existing expertise in powering vehicle fleets with electricity and maintaining electric-drivetrain vehicles. Metro is a department under the King County government and is governed by the county. The county serves a constituency that strongly supports climate change goals and strategies, which in turn have driven an ambitious zero-emission transition plan by Metro. In 2015, King County released a Strategic Climate Action Plan, a five-year blueprint for County climate action, that called for the county to reduce its transit bus fleet emissions. In 2016, Metro launched its pilot fleet of 11 battery electric buses, and, in 2017, Metro made a commitment to transition to an all zero-emission fleet by 2040, dependent on the ability of technology to meet the agency’s needs. In February 2020, the all ZEB-fleet goal was advanced to 2035 by the King County Council through Ordinance 19052. Ordinance 19052 commits King County to accelerating electrification of King County is directed under its overall fleet, including the transit bus fleet. To support vehicle electrification, a county ordinance to engage the Ordinance directs the County to create an EV infrastructure analysis and with electric utilities as part of its implementation plan for King County Facilities in consultation with Seattle vehicle electrification assessment City Light and Puget Sound Energy. Thus, the ordinance effectively mandated and planning process. collaboration between the county and the electric utilities in the planning process for fleet electrification. The five-year update of the county’s Strategic Climate Action Plan, released in 2021, affirmed the 2035 target for an all-ZEB fleet. The 2020 Action Plan also calls out environmental justice and equitable access as central elements of any electrification strategy or plan. The plan identifies zero-emission transit bus transition as a central plank of an equitable greenhouse gas reduction strategy. With this set of commitments in place, Metro rolled out its ZEB Transition Plan in May 2022. The plan provided a timeline for a phased transition to an all-zero-emission fleet, with all new bus purchases to be zero emission starting in 2024. The program milestones are shown in Figure 14. 

Case Examples   53 Figure 14.   King County Metro transition plan milestones (courtesy Metro). The plan called for 40 new BEBs—split between 40-ft. and 60-ft. models—to be placed into service and for the opening of a new South Base Test Charging Facility by 2022. Both targets were reached. The South Base Test Charging Facility uses overhead pantograph down charging as the primary charging technology (Figure 15); DC plug-in chargers are also available at the facility. The agency is now focused on the next phase: electrification at the Interim Base at South Campus that can support a fleet of 120 new BEBs by 2025. In this project, as well as the work on the South Base Test Charging Facility, Seattle City Light was the electric utility serving these areas and Metro’s partner in these projects. Figure 15.   Overhead charging (photo courtesy Lisa Jerram). 

54   Examination of Transit Agency Coordination with Electric Utilities Utility Overview Seattle City Light (City Light) is a municipal utility that provides service to Seattle and eight adjacent jurisdictions, serving around 460,000 metered customers. Seattle City Light is a depart- ment of the city of Seattle and is governed by the City Council; therefore, the utility’s mission is driven by the interests of the council’s constituents, who place a high value on environmental stewardship. City Light has a longstanding commitment to renewable energy: in 2005, it became the first electric utility in the United States to achieve net zero greenhouse gas emissions; its electricity comes from a mix of hydropower, wind, nuclear, and biogas. Like King County Metro, City Light has a strong commitment to transportation electrifica- tion. Importantly, the utility also has the legal authority to establish programs that follow through on this commitment. In 2019, the Washington State Legislature passed HB 1512, a law granting municipal utilities the authority to adopt a transportation electrification plan and offer pro- grams, services, or incentives that support transportation electrification. In 2020, City Light submitted, and received approval for, its Transportation Electrification Strategic Investment Plan from the Seattle City Council. This plan is driving a range of activities and initiatives at the utility. It identifies transit electrification as a top priority to help the utility meet its aim of equitable access to improved environmental outcomes. In its outreach efforts with the community, as the utility developed the Strategic Investment Plan, transit buses arose as the transportation mode affecting a large portion of the popula- tion, especially those who are not likely to own a private electric vehicle. Deployment of battery electric buses will thus enable a broad swathe of the population to benefit from electrification and help address historical inequities in underserved communities that live along congested transportation corridors. This Strategic Investment Plan has helped to drive City Light’s collaboration with Metro to support its goals to transition to an all zero-emission fleet. The plan (Seattle City Light 2020, p. 13) specifically calls for providing “financial incentives and technical assistance with site and design requirements” for King County Metro’s BEB infrastructure. Details of Agency-Utility Collaboration Metro brought City Light into the planning process early for both the South Base Test Facility that opened in 2022 and the Interim Facility planned for 2025. City Light has been well-integrated into the transit agency’s planning process for both projects. The two entities have a memorandum of understanding (MOU) that formalizes their close collaboration; this MOU speaks to the high- level support at both the agency and the utility for collaboration around transit electrification. Seattle City Light also adopted a pilot EV commercial rate that goes into effect with the utility’s 2024 rate schedule. Partnership Between Metro and City Light In 2020, Metro and City Light signed an MOU pledging to collaborate on the “civil, structural and electrical infrastructure” needed for charging and operations at the South Base Test Facility. The MOU recognized that both City Light and Metro were committed to launching the facility in just two years’ time, and that, with its substantial electricity needs (approximately 2.5 MW), the schedule would require close collaboration throughout the planning and deployment process. The MOU (King County Metro and City of Seattle 2020) called for a “one team” approach that promotes cooperation, learning, and accountability, and indicates full leadership support. Under the one-team vision, key staff at City Light and Metro collaborate on day-to-day aspects of the project. Leadership from both organizations are responsible for reconciling any major conflicts of opinion within just five working days to ensure the timely resolution of problems. 

Case Examples   55 Under the MOU, City Light committed to go beyond the “normal passive role” of electricity supplier and instead provide consultant services to “aid design and construction.” The MOU does not commit City Light to paying for the design and construction as would occur in a typical “make-ready” program. The organizations noted one benefit of having City Light closely integrated into the planning process is helping to avoid long delays. When Metro requires Under the joint MOU, City Light service at a new or upgraded facility, the agency typically waits to submit a pledges to go beyond the usual service letter to the utility when it has reached 90% of the design completion. passive role of electricity supplier With the long lead times on permitting electric infrastructure upgrades, it was and provide direct services to help a top priority to bring in City Light early in the design phase since any changes Metro in planning and design. made at 90% design can significantly delay a project. Having City Light as part of the design team means that any potential issues can be flagged early and resolved. Both organizations noted a major benefit simply to building the relationship between the respective project leads. This facilitates trust between the two parties as they look to determine the potential demand of the new fleet and how to manage it. The project teams hold regular meet- ings and strive to share information readily with their counterparts. It is worth noting that even when being transparent about information, there is uncertainty inherent in the planning process. The utility’s goal is to accurately predict future power needs since adding electrical capacity is costly and takes time. However, there is significant uncer- tainty in the transit agency’s own understanding of its future BEB fleet’s likely electricity needs. The regular cadence of meetings can help the two sides work through these issues. As they look ahead, Metro and City Light anticipate a maturation of the ability to forecast future loads and demand response. City Light also noted that it is important to bring in staff from various departments at the utility that might normally not be involved in new projects; the recommendation was to include not just the planners and engineers for the grid but also staff responsible for generation, forecasting, and rates. The two entities also recommended that any processes for meetings and collaborations become operationalized and formalized for the long term, to guard against the risk when key personnel leave or take on new roles. They are also looking ahead to establishing the transit bus fleet as a critical service in the case of power outages. Pilot EV Commercial Rate In 2020 City Light adopted a Commercial EV Charging Rate Pilot; these rates go into effect in 2024. The Commercial Charging rate is a “time-of-day” rate intended to incentivize off-peak charging; of note, it does not include demand charges. As a comparison, Figure 16 shows the utility’s 2-24 “Opt-In Time-of-Day Rates” for Medium General Service. Note that the peak and off-peak rates are slightly higher for the Commercial Charging rate, but there are no demand charges. The goal of this pilot rate is to enable customers to learn how best to manage battery electric fleet charging while BEB fleets are still in an early stage of deployment. Subscribing to this rate requires the installation of a separate meter exclusively for EV charging. Lessons Learned Some highlights and lessons learned from this case example are • Both King County Metro and Seattle City Light are governed by public entities—the county and the city, respectively. This governance allows them to set aggressive transit electrifica- tion goals since the constituency in this region strongly supports sustainability and climate strategies. 

56   Examination of Transit Agency Coordination with Electric Utilities 2024 Commercial Charging Rates, Seattle City Light 2024 Opt-In Time-of-Day Rates, Seattle City Light Figure 16.   SCL 2024 commercial charging rates (courtesy SCL). 

Case Examples   57 • The MOU between the agency and utility formalizes a close collaboration and requires City Light to provide consulting services on the design and construction of the infrastructure facility. This commitment does not include offsetting the cost of the infrastructure. • It was critical to bring the electric utility into the agency’s BEB project early and keep it closely integrated through the planning process. Given the long lead times for utility permitting and providing increased electrical capacity, getting the utility involved early helps avoid delays as the utility can spot potential issues early on. • Providing full information and being transparent help each stakeholder manage the project. • It is important to formalize any collaborative processes developed to ensure that there is insti- tutional knowledge that remains even if specific staff leave the project. • This collaboration has buy-in at the highest level of each organization. • The availability of a pilot charging rate that has higher base rates than standard rates but excludes demand charges may be helpful in the early stages of BEB deployment and allow the transit agency to learn its fleet’s power needs and optimize its charging protocols. Missoula Urban Transportation District Introduction The Missoula Urban Transportation District, also called “Mountain Line,” has a small BEB fleet and is making a transition to all BEBs. The agency has This case example captures the experienced high electricity costs due to demand charges with its pilot BEB experience of an agency being fleet and has faced significant challenges in forming a relationship with the unable to effectively engage electric utility. This brief case example describes the agency’s unsuccessful with its utility to support its BEB efforts to work with the utility and the impacts on its BEB program. deployment. Transit Agency and Utility Experience Missoula Urban Transportation District, also called “Mountain Line,” serves the city of Missoula, Montana. Mountain Line operates a small fleet of 30 full-size buses as well as paratransit and support vehicles. Missoula is a university town, so this is an urban service territory, and it has a range of temperatures, from extreme cold with snow to relatively warm summers. Mountain Line was an early adopter of BEBs, launching its pilot fleet in 2019. It operates 12 battery electric buses and has 14 more BEBs on order. The transition plan calls for the follow- ing rollout plan to reach full zero emissions: • 2023 – 12 buses in operation – 40% • 2024 – 16 buses – 53% • 2025 – 17 buses – 57% • 2026 – 27 buses – 90% • 2028 – 30 buses – 100% Paratransit and support vehicles will be phased in starting in 2028, with a complete transition before 2035. Mountain Line operates the current fleet out of an existing depot using DC charging. The agency has plans to build a new facility for the full fleet of 30 buses. The agency’s service territory is serviced by two utilities: Northwestern Energy, a regulated utility, and the Missoula Electric Cooperative. However, the agency is Northwestern Energy’s customer, so this is the utility that provides service for the facilities that house the BEB fleet. Northwestern Energy is an investor-owned utility that serves Montana, South Dakota, and Nebraska. 

58   Examination of Transit Agency Coordination with Electric Utilities Mountain Line reports that it reached out to Northwestern early in its planning process, but that it has been unable to establish a productive working relationship with the utility beyond simply acting as a regular customer and user of electricity. The agency notes that when it did the initial construction in 2018 for the BEB fleet, it was required to pay for the transformer that was sized to service this new fleet. The agency is paying for this transformer upgrade over 10 years. The agency has experienced significant demand charges from operating its pilot fleet of BEBs. The staff initially pursued a special rate that would lower the demand charges, but this was unsuc- cessful due to push back from a consumer advocacy group that opposed Northwestern having to pass on its lost revenue to other ratepayers. These capital and operating costs have made the BEB transition more challenging for Moun- tain Line, although it remains committed. The agency is now in the process of trying to locate a new property to build a new facility that can accommodate the larger fleet. The agency has begun having more regular conversations with Northwestern as it plans this new facility. However, the agency is also exploring if it could become a customer of the Missoula Electric Cooperative for the new facility. In the meantime, Mountain Line is exploring charge management systems and energy storage to level off the electricity demand and reduce demand charges. Lessons Learned • The key lesson from this case example is that some agencies will struggle to form produc- tive relationships with their utility despite pursuing such a relationship early in their BEB deployment. • A second lesson is that agencies may want to consider alternatives to seeking lower rates to offset demand charges when they are working with a regulated utility. They will need to uti- lize charge management to ensure that they are optimizing their charging schedules. This is recommended generally for BEB deployments, as it benefits both the agency and the utility.