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Section 9. Ordinance Transmitted to State. Pursuant to RCW 36.70A.106, a copy of this ordinance shall be transmitted to the Washington State Department of Commerce. INTRODUCED: MAY 0 5 2025 PASSED: MAY 0 5 2025 APPROVED: MAY 0 5 2025 NANCY BA YOR ATTEST: APPR• . ' PASTO • 'M: 2S4cP-•-%-- -----GX.Ird‘v44301/4 fr 4 4rti Shawn Campbell, MMC, City Clerk Jason Whalen, City Attorney Published: M(Jl 202'5, in The, ' 1 • / T\ S Ordinance No. 6978 April 14, 2025 Page 10 of 10 AUBURN VALUES S E R V I C E ENVIRONMENT E C O N O M Y C H A R A C T E R SUSTAINABILITY W E L L N E S S C E L E B R AT I O N COUNCIL STUDY SESSION ENERGY STORAGE SYSTEM MORATORIUM ORDINANCE NO. 6978 PRESENTED BY GABRIEL CLARK, PLANNER II APRIL 28, 2025 Department of Community Development Planning Building Development Engineering Permit Center Economic Development Code Enforcement Energy Storage Systems (ESS) vary widely in their uses and installation types; their primary function is to store electrical energy during periods of low demand and discharge at periods of high demand. Battery Energy Storage Systems (BESS) are a type of ESS which uses battery technology to provide storage and improve the overall stability of the electrical grid. Other functions include: Load Shedding Load Sharing Smoothing and dispatching from renewable energy sources Emergency power storage The moratorium covers all ESS, BESS is the primary concern for Staff. WHAT ARE ENERGY STORAGE SYSTEMS? SERVICE ENVIRONMENT ECONOMY CHARACTER SUSTAINABILITY WELLNESS CELEBRATION Lithium-ion batteries are a very common method of storing electrical energy for usage and may be charged and discharged reliably. Examples: Phone batteries Laptop computers Electric Vehicles WHY A LITHIUM-ION BATTERY? WHAT ARE THE DIFFERENT TYPES? SERVICE ENVIRONMENT ECONOMY CHARACTER SUSTAINABILITY WELLNESS CELEBRATION Residential Commercial Grid Moratorium PRIMARY FUNCTIONS VISUALIZED FLOW MAP OF TIER II AND III SYSTEMS CROSS SECTION OF A BESS CABINET Primary Impact: Thermal Runaway WHAT ARE THE IMPACTS OF BESS SYSTEMS? SERVICE ENVIRONMENT ECONOMY CHARACTER SUSTAINABILITY WELLNESS CELEBRATION Thermal Runaway: “A primary risk related to Lithium-ion batteries. It is a phenomenon in which the Lithium-ion cell enters an uncontrollable, self-heating state.” – UL Research Institutes To reduce the likelihood of thermal runaway, the batteries need to be isolated, cooled, and monitored. WHAT IS THE CAUSE OF THESE FIRES? PSE Hired Power Systems Consultants to report the most viable sites in the service area. Christopher Substitution cited as “low risk” Puget Sound Energy announcing two BESS projects in the State. Appaloosa Solar Project (Garfield County) Greenwater BESS Project (Sumner) WHAT IS THE DEMAND? Tier I (residential) BESS installations have limited negative impacts and will not be considered under this moratorium. Tier II and Tier III facilities may pose impacts to the safety, well-being and health to the residents and business in Auburn. The moratorium will provide needed time for the City to research these impacts and develop regulatory standards. Community Development and Public Works need to develop effective siting, construction, and operation regulations. WHAT IS THE REASON FOR THE MORATORIUM? SERVICE ENVIRONMENT ECONOMY CHARACTER SUSTAINABILITY WELLNESS CELEBRATION Meetings with Valley Regional Fire Authority (VRFA) concluded the main method of extinguishing fires at BESS facilities is to continually douse the compromised rack with cool water. VRFA would be required to post several units at the site, for a multi shift response (12+ hours) and treated as a hazardous materials response. A fire would require a significant response. VRFA, Auburn Police, Department of Ecology, Puget Sound Clean Air Agency and other agencies. Community Development Staff are developing a new chapter in Title 18 to facilitate the siting, construction, and operation of BESS projects. WHAT IS THE JURISDICTIONAL RESPONSE? Existing International Fire Code (IFC) and National Fire Protection Association (NFPA) Chapter 12 of the Washington State IFC (Est. March 2024) 2023 edition of the NFPA 855 Standard Installation of Stationary Energy Storage Systems International Building Code (IBC) siting and construction standards. Absent Comprehensive guidance on siting, construction, and operation of ESS facilities. Title 18 Zoning for siting and operation. Engineering Design Standards (EDS) WHAT STANDARDS? PROPOSED TIMELINE May •Adopt Moratorium Jun •Research and program development Jul •Prepare zoning text amendment Aug •Present proposed text amendment to planning commission Sep •Present proposed text amendment to City Council Oct •Adopt amended code and moratorium expires AUBURN VALUES S E R V I C E ENVIRONMENT E C O N O M Y C H A R A C T E R SUSTAINABILITY W E L L N E S S C E L E B R AT I O N Department of Community Development Planning Building Development Engineering Permit Center Economic Development Code Enforcement www.greeningthegrid.org | www.nrel.gov/usaid-partnership GRID INTEGRATION TOOLKIT Grid-Scale Battery Storage Frequently Asked Questions 1. For information on battery chemistries and their relative advantages, see Akhil et al. (2013) and Kim et al. (2018). 2. For example, Lew et al. (2013) found that the United States portion of the Western Interconnection could achieve a 33% penetration of wind and solar without additional storage resources. Palchak et al. (2017) found that India could incorporate 160 GW of wind and solar (reaching an annual renewable penetration of 22% of system load) without additional storage resources. What is grid-scale battery storage? Battery storage is a technology that enables power system operators and utilities to store energy for later use. A battery energy storage system (BESS) is an electrochemical device that charges (or collects energy) from the grid or a power plant and then discharges that energy at a later time to provide electricity or other grid services when needed. Several battery chemistries are available or under investigation for grid-scale applications, including lithium-ion, lead-acid, redox flow, and molten salt (including sodium-based chemistries).1 Battery chemistries differ in key technical characteristics (see What are key characteristics of battery storage systems?), and each battery has unique advantages and disadvantages. The current market for grid-scale battery storage in the United States and globally is dominated by lithium-ion chemistries (Figure 1). Due to tech- nological innovations and improved manufacturing capacity, lithium-ion chemistries have experienced a steep price decline of over 70% from 2010-2016, and prices are projected to decline further (Curry 2017). Increasing needs for system flexibility, combined with rapid decreases in the costs of battery technology, have enabled BESS to play an increasing role in the power system in recent years. As prices for BESS continue to decline and the need for system flexibility increases with wind and solar deployment, more policymakers, regulators, and utili- ties are seeking to develop policies to jump-start BESS deployment. Is grid-scale battery storage needed for renewable energy integration? Battery storage is one of several technology options that can enhance power system flexibility and enable high levels of renewable energy integration. Studies and real-world experience have demonstrated that interconnected power systems can safely and reliably integrate high levels of renewable energy from variable renewable energy (VRE) sources without new energy storage resources.2 There is no rule-of- thumb for how much battery storage is needed to integrate high levels of renewable energy. Instead, the appropriate amount of grid-scale battery storage depends on system-specific characteristics, including: •The current and planned mix of generation technologies •Flexibility in existing generation sources •Interconnections with neighboring power systems •The hourly, daily, and seasonal profile of electricity demand, and •The hourly, daily, and seasonal profile of current and planned VRE. In many systems, battery storage may not be the most economic resource to help integrate renewable energy, and other sources of system flexibility can be explored. Additional sources of system flexibility include, among others, building additional pumped-hydro storage or transmission, increasing conventional generation flexibility, and changing operating procedures (Cochran et al. 2014).Figure 1: U.S. utility-scale battery storage capacity by chemistry (2008-2017). Data source: U.S. Energy Information Administration, Form EIA-860, Annual Electric Generator ReportAnnual Installed CapacityChemistry Energy (MWh) Power (MW) Year Installed 0 50 100 150 200 250 '17'16'15'14'13'12'11'10'09'08 '17'16'15'14'13'12'11'10'09'08 Lithium-Ion Other Redox FlowLead-acid Sodium-based EXHIBIT B 2Grid-Scale Battery Storage: Frequently Asked Questions What are the key characteristics of battery storage systems? • Rated power capacity is the total possible instantaneous discharge capability (in kilowatts [kW] or megawatts [MW]) of the BESS, or the maximum rate of discharge that the BESS can achieve, starting from a fully charged state. • Energy capacity is the maximum amount of stored energy (in kilowatt-hours [kWh] or megawatt-hours [MWh]) • Storage duration is the amount of time storage can discharge at its power capacity before depleting its energy capacity. For example, a battery with 1 MW of power capacity and 4 MWh of usable energy capacity will have a storage duration of four hours. • Cycle life/lifetime is the amount of time or cycles a battery storage system can provide regular charging and discharging before failure or significant degradation. • Self-discharge occurs when the stored charge (or energy) of the battery is reduced through internal chemical reactions, or without being discharged to perform work for the grid or a customer. Self-discharge, expressed as a percentage of charge lost over a certain period, reduces the amount of energy available for discharge and is an important parameter to consider in batteries intended for longer-dura- tion applications. • State of charge, expressed as a percentage, represents the battery’s present level of charge and ranges from completely discharged to fully charged. The state of charge influences a battery’s ability to provide energy or ancillary services to the grid at any given time. • Round-trip efficiency, measured as a percentage, is a ratio of the energy charged to the battery to the energy discharged from the battery. It can represent the total DC-DC or AC-AC efficiency of the battery system, including losses from self-discharge and other electrical losses. Although battery manufacturers often refer to the DC-DC efficiency, AC-AC efficiency is typically more important to utilities, as they only see the battery’s charging and discharging from the point of interconnection to the power system, which uses AC (Denholm 2019). What services can batteries provide? Arbitrage: Arbitrage involves charging the battery when energy prices are low and discharging during more expensive peak hours. For the BESS operator, this practice can provide a source of income by taking advantage of electricity prices that may vary throughout the day. One extension of the energy arbitrage service is reducing renewable energy curtailment. System operators and project developers have an interest in using as much low-cost, emissions-free renewable energy generation as possible; however, in systems with a growing share of VRE, limited flexibility of conventional generators and temporal mismatches between renewable energy supply and electricity demand (e.g., excess wind 3. See Mills and Wiser (2012) for a general treatment on the concept of capacity credit. generation in the middle of the night) may require renewable generators to curtail their output. By charging the battery with low-cost energy during periods of excess renewable generation and discharging during periods of high demand, BESS can both reduce renewable energy curtailment and maximize the value of the energy developers can sell to the market. Another extension of arbitrage in power systems without electricity markets is load-leveling. With load-levelling, system opera- tors charge batteries during periods of excess generation and discharge batteries during periods of excess demand to more efficiently coordinate the dispatch of generating resources. Firm Capacity or Peaking Capacity: System operators must ensure they have an adequate supply of generation capacity to reliably meet demand during the highest-demand periods in a given year, or the peak demand. This peak demand is typically met with higher-cost generators, such as gas plants; however, depending on the shape of the load curve, BESS can also be used to ensure adequate peaking generation capacity. While VRE resources can also be used to meet this requirement, these resources do not typically fully count toward firm capacity, as their generation relies on the availability of fluctuating resources and may not always coincide with peak demand. But system operators can improve VRE’s ability to contribute to firm capacity requirements through pairing with BESS. Pairing VRE resources with BESS can enable these resources to shift their generation to be coincident with peak demand, improving their capacity value (see text box below) and system reliability.3 Operating Reserves and Ancillary Services: To maintain reliable power system operations, generation must exactly match electricity demand at all times. There are various categories of operating reserves and ancillary services that function on different timescales, from subsec- onds to several hours, all of which are needed to ensure grid reliability. BESS can rapidly charge or discharge in a fraction of a second, faster Firm Capacity, Capacity Credit, and Capacity Value are important concepts for understanding the potential contribution of utility-scale energy storage for meeting peak demand. Firm Capacity (kW, MW): The amount of installed capacity that can be relied upon to meet demand during peak periods or other high-risk periods. The share of firm capacity to the total installed capacity of a generator is known as its capacity credit (%).3 Capacity Value ($): The monetary value of the contribution of a generator (conventional, renewable, or storage) to balancing supply and demand when generation is scarce. 3Grid-Scale Battery Storage: Frequently Asked Questions than conventional thermal plants, making them a suitable resource for short-term reliability services, such as Primary Frequency Response (PFR) and Regulation. Appropriately sized BESS can also provide longer-duration services, such as load-following and ramping services, to ensure supply meets demand. Transmission and Distribution Upgrade Deferrals: The electricity grid’s transmission and distribution infrastructure must be sized to meet peak demand, which may only occur over a few hours of the year. When anticipated growth in peak electricity demand exceeds the existing grid’s capacity, costly investments are needed to upgrade equipment and develop new infrastructure. Deploying BESS can help defer or circum- vent the need for new grid investments by meeting peak demand with energy stored from lower-demand periods, thereby reducing congestion and improving overall transmission and distribution asset utilization. Also, unlike traditional transmission or distribution investments, mobile BESS installations can be relocated to new areas when no longer needed in the original location, increasing their overall value to the grid. Black Start: When starting up, large generators need an external source of electricity to perform key functions before they can begin generating electricity for the grid. During normal system conditions, this external electricity can be provided by the grid. After a system failure, however, the grid can no longer provide this power, and generators must be started through an on-site source of electricity, such as a diesel generator, a process known as black start. An on-site BESS can also provide this service, avoiding fuel costs and emissions from conventional black-start generators. As system-wide outages are rare, an on-site BESS can provide additional services when not performing black starts. Table 1 below summarizes the potential applications for BESS in the electricity system, as well as whether the application is currently valued in U.S. electricity markets (Denholm 2018). Figure 2 shows the cumulative installed capacity (MW) for utility-scale storage systems in the United States in 2017 by the service the systems provide. Where should batteries be located? Utility-scale BESS can be deployed in several locations, including: 1) in the transmission network; 2) in the distribution network near load centers; or 3) co-located with VRE generators. The siting of the BESS has important implications for the services the system can best provide, and the most appropriate location for the BESS will depend on its intended-use case. In many cases, a BESS will be technically capable of providing a broad range of services in any of the locations described in the next section. Therefore, when siting storage, it is important to analyze the costs and benefits of multiple locations to determine the optimal siting to meet system needs. Considering all combinations of services the BESS can provide at each potential site will provide a better understanding of the expected revenue streams (see What is value-stacking?) and impact on the grid. In the Transmission Network BESS interconnected to the transmission system can provide a broad range of ancillary and transmission-related services. These systems can be deployed to replace or defer investments of peaking capacity, provide operating reserves to help respond to changes in generation and demand, or they can be used to defer transmission system upgrades in regions experiencing congestion from load or generation growth. Figure 3 below shows the configuration of a utility-scale storage system interconnected at the transmission substation level. In the Distribution Network Near Load Centers Storage systems located in the distribution network can provide all of the services as transmission-sited storage, in addition to several services related to congestion and power quality issues. In many areas, it may be difficult to site a conventional generator near load in order to provide peaking capacity, due to concerns about emissions or land use. Due to their lack of local emissions and their scalable nature, BESS systems can be co-located near load with fewer siting challenges than conventional generation. Placing storage near load can reduce transmission and distribution losses and relieve congestion, helping defer transmission and distribution upgrades. Distribution-level BESS systems can also provide local power quality services and support improved resilience during extreme weather events. Most storage systems in the United States provide operating reserves and ancillary services. Despite this current focus, the total U.S. market for these services is limited, and utility-scale storage may begin providing more firm and peak capacity in the near future. Nameplate Capacity 0 100 200 300 400 500 600 Operating Reserves and Ancillary Services Arbitrage, RE Curtailment Reduction and Load-levelling Firm Capacity or Peaking Capacity Transmission and Distribution Upgrade Deferrals Black Start Figure 2: U.S. Utility-scale battery storage capacity by service. Data source: U.S. Energy Information Administration, Form EIA-860, Annual Electric Generator Report 4Grid-Scale Battery Storage: Frequently Asked Questions Co-Located with VRE Generators Renewable resources that are located far from load centers may require transmission investments to deliver power to where it is needed. Given the variable nature of VRE resources, the transmission capacity used to deliver the power may be underutilized for large portions of the year. A BESS can reduce the transmission capacity needed to integrate these resources and increase the utilization of the remaining capacity by using storage to charge excess generation during periods of high resource availability and discharge during periods of low resource availability. The same BESS can be used to reduce the curtailment of VRE gen- eration, either due to transmission congestion or a lack of adequate demand, as well as provide a broad range of ancillary services. What is value-stacking? What are some examples of value-stacking opportunities and challenges? BESS can maximize their value to the grid and project developers by providing multiple system services. As some services are rarely called for (i.e., black start) or used infrequently in a given hour (i.e., spinning reserves), designing a BESS to provide multiple services enables a higher overall battery utilization. This multi-use approach to BESS is known as value-stacking. For example, a BESS project can help defer the need for new transmission by meeting a portion of the peak demand with stored energy during a select few hours in the year. When not meeting peak demand, the BESS can earn revenue by providing operating reserve services for the transmission system operator. Table 1: Applications of Utility-Scale Energy Storage Application Description Duration of Service Provision Typically Valued in U.S. Electricity Markets? Arbitrage Purchasing low-cost off-peak energy and selling it during periods of high prices. Hours Yes Firm Capacity Provide reliable capacity to meet peak system demand. 4+ hours Yes, via scarcity pricing and capacity markets, or through resource adequacy payments. Operating Reserves • Primary Frequency Response Very fast response to unpredictable variations in demand and generation. Seconds Yes, but only in a limited number of markets. • Regulation Fast response to random, unpredictable variations in demand and generation. 15 minutes to 1 hour Yes • Contingency Spinning Fast response to a contingency such as a generator failure. 30 minutes to 2 hours Yes • Replacement/ Supplemental Units brought online to replace spinning units. Hours Yes, but values are very low. • Ramping/Load Following Follow longer-term (hourly) changes in electricity demand. 30 minutes to hours Yes, but only in a limited number of markets. Transmission and Distribution Replacement and Deferral Reduce loading on T&D system during peak times. Hours Only partially, via congestion prices. Black-Start Units brought online to start system after a system-wide failure (blackout). Hours No, typically compensated through cost-of-service mechanisms. 5Grid-Scale Battery Storage: Frequently Asked Questions Some system services may be mutually exclusive depending on the BESS design (e.g., a short duration storage device used to supply regulating reserves would have limited value for deferring transmission or distribution upgrades). Even if a BESS is technically capable of pro- viding multiple services, the additional cycling of the battery (charging and discharging) may degrade the battery and shorten its lifetime and economic viability. Finally, a BESS can only provide a limited duration of any set of services before it runs out of charge, which means batteries must prioritize the services they provide.4 Regulators have a variety of options to enable BESS to maximize its economic potential through val ue-stacking. For example, the California Public Utilities Commission (CPUC) developed categories of services BESS can provide based on their importance for reliability and location on the grid, as well as 12 rules for utilities when procuring services from BESS (CPUC 2018). The CPUC rules: • Dictate that BESS projects can only provide services at the voltage level to which they are interconnected or higher, but not lower5; • Prioritize reliability services over non-reliability services and ensure storage cannot contract for additional services that would interfere with any obligation to provide reliability services; • Require that a BESS project comply with all performance and avail- ability requirements for services it provides and that noncompliance penalties be communicated in advance; • Require that a BESS project inform the utility of any services it currently provides or intends to provide; and • Take measures to prevent double compensation to BESS projects for services provided. 4. ANSI C84.1: Electric Power Systems and Equipment–Voltage Ratings (60 Hz) defines a low-voltage system as having a nominal voltage less than 1 kV and medium voltage as having a nominal voltage between 1 kV and 100 kV. 5. BESS interconnected at the distribution level can provide distribution or transmission level services, but BESS interconnected at the transmission level can only provide transmission-level services. These CPUC rules are just one example of how regulators can help ensure BESS projects can select the most cost-effective combinations of services to provide without negatively impacting the reliability of the grid. How are BESS operators compensated? BESS operators can be compensated in several different ways, including in the wholesale energy market, through bilateral contracts, or directly by the utility through a cost-of-service mechanism. In a wholesale energy market, the BESS operator submits a bid for a specific service, such as operating reserves, to the market operator, who then arranges the valid bids in a least-cost fashion and selects as many bids as necessary to meet the system’s demands. If the BESS operator’s bid is selected and the BESS provides the service, the operator will receive compensation equal to the market price. This process ensures transparent prices and technology-agnostic consideration; however, many services are currently not available in the market, such as black start or transmission and distribution upgrade deferrals. Alternatively, BESS operators can enter into bilateral contracts for services directly with energy consumers, or entities which procure energy for end-con- sumers. This process does not ensure transparency and contracts can differ widely in both prices and terms. Finally, some BESS are owned directly by the utilities to whom they provide services, such as upgrade deferrals. In these cost-of-service cases, the utility pays the BESS operator at the predetermined price and recovers the payments through retail electricity rates. In some jurisdictions, however, BESS may be prevented from extracting revenues through both wholesale markets and cost-of-service agreements (Bhatnagar et al. 2013). - + batteries =~~~ inverter/charger set-up transformer tie-line status info BMS* *Battery Management System systemoperator set points DC LV AC MV AC Figure 3: Key components of BESS interconnected at the transmission substation level. LV AC represents a low-voltage AC connection, while MV AC represents a medium-voltage AC connection.4 Source: Denholm (2019) 6Grid-Scale Battery Storage: Frequently Asked Questions How does the value of batteries change with renewable energy deployment and increased VRE penetration? The amount of renewable energy on the grid can influence the value and types of the services provided by a BESS. Increased levels of renewable energy may increase the need for frequency control services to manage increased variability and uncertainty in the power system. Increased levels of VRE penetration can also change the shape of the net load, or the load minus the VRE generation, influencing BESS projects that provide load following, arbitrage, peaking capacity, or similar services. Models of the California system have shown a strong relationship between solar PV deployment and BESS’ ability to replace conventional peaking capacity, also known as the BESS capacity credit (Denholm and Margolis 2018). As the shape of the load curve affects the ability of storage to provide peaking capacity, resources such as PV that cause load peaks to be shorter will enable shorter duration batteries, which are less expensive, to displace conventional peaking capacity. Initially, low levels of PV penetration may flatten the load curve, reducing BESS’ ability to cost-effectively offset the need for conventional peaking plants.6 At higher levels of solar PV penetration, however, the net load curve becomes peakier, increasing the ability and value of BESS to reduce peak demand. Figure 4 illustrates how increasing levels of PV generation change the shape of the net load, causing it to become peakier. The shaded areas above and under the net load curves indicate BESS charging and discharging, while the text boxes show the amount of net load peak reduction (MW) and the total amount of energy met by BESS during the net load peak (MWh). 6. This is demonstrated by Denholm and Margolis (2018) for the California system. What are the key barriers to BESS deployment? Barriers to energy storage deployment can be broadly grouped into three different categories: regulatory barriers, market barriers, and data and analysis capabilities. 1. Regulatory Barriers • Lack of rules and regulations to clarify the role of BESS. Although storage may be technically able to provide essential grid services, if no regulations or guidelines explicitly state that storage can provide these services, utilities and market operators may be unwilling to procure services from BESS. Furthermore, without a guarantee that services provided by a BESS project will be compensated, storage developers and financing institutions may be unwilling to make the necessary capital investments. Federal Energy Regulatory Commission (FERC) Order 841 addressed this issue in U.S. wholesale markets and directed market operators to develop rules governing storage’s participation in energy, capacity, and ancillary service markets. Among other requirements, the rules must ensure open and equal access to the market for storage systems, taking into consideration their unique operating and technical characteristics (FERC 2018). • Restrictions or lack of clarity around if and how storage can be used across generation, transmission, and distribution roles. The variety of different services storage can provide often cuts across multiple markets and compensation sources. For instance, frequency regulation may be compensated in a wholesale market, but transmission or distribution investment deferrals may be compensated as a cost of service by the utility or system operator. In some jurisdictions, providing services across different compensation sources is restricted by regulation. Limiting the services batteries can provide based on where the service is provided or how it is compensated can influence how often they are utilized and whether they remain an economic investment (Bhatnagar 2013). 2. Market Barriers • Lack of markets for system services. A lack of markets for services that batteries are uniquely suited to provide can make it difficult for developers to include them as potential sources of income when making a business case, deterring investment. For example, in most U.S. Independent System Operator (ISO) markets, generators are currently expected to provide inertial and governor response during frequency excursions without market compensation. Although BESS can provide the same services, currently there is no way for BESS to seek market compensation for doing so. Furthermore, the price formation for a service may have evolved for conventional generators, meaning the presence 0 6 12 18 24 60,000 50,000 Net Demand (MW)Hour of Day 40,000 30,000 20,000 10,000 0 PV Penetration 0% PV 20% PV 10,385 MWh, 4296 MW 4,841 MWh, 2019 MW Figure 4: Change in California net load shape due to PV. Adapted from Denholm and Margolis (2018) 7Grid-Scale Battery Storage: Frequently Asked Questions of batteries in the market could distort prices, affecting storage systems and conventional generators alike (Bhatnagar 2013). • Lack of discernment in quality and quantity of services procured. For some services, such as frequency regulation, the speed and accuracy of the response is correlated to its overall value to the system. Battery systems can provide certain services much faster and more accurately than conventional resources, which may not be reflected in compensation for the service. Markets can provide fair compensation to BESS by aligning compensation schemes with the quality of service provided, as is mandated by FERC Order 755, which requires compensation for frequency regulation that reflects “the inherently greater amount of frequency regulation service being provided by faster-ramping resources” (FERC 2011). Similarly, BESS can be uniquely suited to provide up- or down-regulation, given their larger operating range over which to provide regulating reserves (due to their lack of a minimum stable level and ability to provide up- and down-regulation in excess of their nameplate capacity, based on whether they are charging or discharging) (Denholm 2019). These unique features of BESS are not necessarily reflected in the procurement requirements and compensation of such services, diminishing BESS’ economic viability. 3. Data and Analysis Capabilities Battery storage systems are an emerging technology that exhibit more risk for investors than conventional generator investments. These risks include the technical aspects of battery storage systems, which may be less understood by stakeholders and are changing faster than for other technologies, as well as potential policy changes that may impact incentives for battery deployment. Given the relatively recent and limited deployment of BESS, many stakeholders may also be unaware of the full capabilities of storage, including the ability of a BESS to provide multiple services at both the distribution and transmission level. At the same time, traditional analysis tools used by utilities may be inadequate to fully capture the value of BESS. For example, production cost models typically operate at an hourly resolution, which does not capture the value of BESS’ fast-ramping capa- bilities. The gaps in data and analysis capabilities and lack of adequate tools can deter investments and prevent battery storage from being considered for services that can be provided by better understood conventional generators (Bhatnagar et al. 2013). What are some real-world examples of batteries providing services and value- stacking? There are several deployments of BESS for large-scale grid applications. One example is the Hornsdale Power Reserve, a 100 MW/129 MWh lithium-ion battery installation, the largest lithium-ion BESS in the world, which has been in operation in South Australia since December 2017. The Hornsdale Power Reserve provides two distinct services: 1) energy arbitrage; and 2) contingency spinning reserve. The BESS can bid 30 MW and 119 MWh of its capacity directly into the market for energy arbitrage, while the rest is withheld for maintaining grid frequency during unexpected outages until other, slower generators can be brought online (AEMO 2018). In 2017, after a large coal plant tripped offline unexpectedly, the Hornsdale Power reserve was able to inject several megawatts of power into the grid within milliseconds, arresting the fall in grid frequency until a gas generator could respond. By arresting the fall in frequency, the BESS was able to prevent a likely cascading blackout. Another example of value-stacking with grid-scale BESS is the Green Mountain Power project in Vermont. This 4 MW lithium-ion project began operation in September 2015 and is paired with a 2 MW solar installation. The installation provides two primary functions: 1) backup power and micro-grid capabilities; and 2) demand charge reductions. The solar-plus-storage system enables the utility to create a micro-grid, which provides power to a critical facility even when the rest of the grid is down. The utility operating the BESS also uses it to reduce two demand charges: an annual charge for the regional capacity market and a monthly charge for the use of transmission lines. Sandia National Laboratories estimated that reducing the annual demand charge for a single year saved the utility over $200,000 (Schoenung 2017). References AEMO (Australian Energy Market Operator). Hornsdale Wind Farm 2 FCAS Trial. Knowledge Sharing Paper. Melbourne, Australia: AEMO. https://www.aemo.com.au/-/media/Files/Electricity/NEM/Strategic- Partnerships/2018/HWF2-FCAS-trial-paper.pdf. Akhil, Abbas, Georgianne Huff, Aileen Currier, Benjamin Kaun, Dan Rastler, Stella Bingquing Chen, Andrew Cotter, et al. Electricity Storage Handbook. SAND2013-5131. DOE, EPRI, NRECA. July 2013. https:// www.sandia.gov/ess-ssl/lab_pubs/doeepri-electricity-storage-handbook/. Bhatnagar, Dhruv, Aileen Currier, Jacquelynne Hernandez, Ookie Ma, and Kirby Brendan. Market and Policy Barriers to Energy Storage Deployment. SAND2013-7606. Albuquerque, NM: Sandia National Laboratories. September 2013. https://www.sandia.gov/ess-ssl/publica- tions/SAND2013-7606.pdf. Cochran, Jaquelin, Mackay Miller, Owen Zinaman, Michael Milligan, Doug Arent, Bryan Palmintier, Mark O’Malley, et al. “Flexibility in 21st Century Power Systems.” NREL/TP-6A20-61721. 21st Century Power Partnership. Golden, CO: NREL. May 2014. https://www.nrel.gov/docs/ fy14osti/61721.pdf. CPUC (California Public Utilities Commission). Decision on Multiple-Use Application Issues. Rulemaking 15-03-011. January 17, 2018. http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M206/ K462/206462341.PDF. Curry, Claire. “Lithium-Ion Battery Costs and Market.” Market Report. Bloomberg New Energy Finance. July 5, 2017. https://data.bloomberglp. com/bnef/sites/14/2017/07/BNEF-Lithium-ion-battery-costs-and- market.pdf. 8Grid-Scale Battery Storage: Frequently Asked Questions Jennifer E. Leisch, Ph.D. USAID-NREL Partnership Manager U.S. Agency for International Development Tel: +1-303-913-0103 | Email: jleisch@usaid.gov Ilya Chernyakhovskiy Energy Analyst National Renewable Energy Laboratory Tel: +1-303-275-4306 Email: ilya.chernyakhovskiy@nrel.gov The Grid Integration Toolkit provides state-of-the-art resources to assist developing countries in integrating variable renewable energy into their power grids. Greening the Grid is supported by the U.S. Agency for International Development. The USAID-NREL Partnership addresses critical challenges to scaling up advanced energy systems through global tools and technical assistance, including the Renewable Energy Data Explorer, Greening the Grid, the International Jobs and Economic Development Impacts tool, and the Resilient Energy Platform. More information can be found at: www.nrel.gov/usaid-partnership. www.greeningthegrid.org | www.nrel.gov/usaid-partnership This work was authored, in part, by the National Renewable Energy Laboratory (NREL), operated by Alliance for Sustainable Energy, LLC, for the U.S. Department of Energy (DOE) under Contract No. DE-AC36-08GO28308. Funding provided by the United States Agency for International Development (USAID) under Contract No. IAG-17-2050. The views expressed in this report do not necessarily represent the views of the DOE or the U.S. Government, or any agency thereof, including USAID. Denholm, Paul. “Greening the Grid: Utility-Scale Battery Storage.” Webinar. Clean Energy Solutions Center. February 28, 2019. https://cleanenergysolutions.org/training/ greening-grid-utility-scale-battery-storage. Denholm, Paul. “Batteries and Storage: Truly a Game Changer?” presented at the JISEA 2018 Annual Meeting in Golden, CO. April 4, 2018. https://www.jisea.org/assets/pdfs/denholm-jisea-2018.pdf. Denholm, Paul, and Robert Margolis. The Potential for Energy Storage to Provide Peaking Capacity in California under Increased Penetration of Solar Photovoltaics. NREL/TP-6A20-70905. Golden, CO: NREL. March 2018. https://www.nrel.gov/docs/fy18osti/70905.pdf. FERC. Electric Storage Participation in Markets Operated by Regional Transmission Organizations and Independent System Operators. Order No. 841. Issued February 15, 2018. https://www.ferc.gov/whats-new/ comm-meet/2018/021518/E-1.pdf. FERC. Frequency Regulation Compensation in the Organized Wholesale Power Markets. Order No. 755. Issued October 20, 2011. https://www. ferc.gov/whats-new/comm-meet/2011/102011/E-28.pdf. Kim, Dae Kyeong, Susumu Yoneoka, Ali Zain Banatwala, and Yu-Tack Kim. Handbook on Battery Energy Storage System. Manila, Philippines: Asian Development Bank. December 2018. https://www.adb.org/ publications/battery-energy-storage-system-handbook. Lew, D., G. Brinkman, E. Ibanez, A. Florita, M. Heaney, B.-M. Hodge, M. Hummon, et al. The Western Wind and Solar Integration Study Phase 2. NREL/TP-5500-55588. Golden, CO: NREL. September 2013. https:// www.nrel.gov/docs/fy13osti/55588.pdf. Mills, Andrew, and Ryan Wiser. Changes in the Economic Value of Variable Generation at High Penetration Levels: A Pilot Case Study of California. LBNL-5445E. Berkeley, CA: Lawrence Berkeley National Laboratory. June 2012. https://emp.lbl.gov/sites/all/files/lbnl-5445e.pdf. Palchak, David, Jaquelin Cochran, Ali Ehlen, Brendan McBennett, Michael Milligan, Ilya Chernyakhovskiy, Ranjit Deshmukh, et al. Pathways to Integrate 175 Gigawatts of Renewable Energy into India’s Electric Grid, Vol. I—National Study. Golden, CO: NREL. June 2017. https://www.nrel.gov/docs/fy17osti/68530.pdf. Schoenung, Susan, Raymond H. Byrne, Todd Olinsky-Paul, and Daniel R. Borneo. Green Mountain Power (GMP): Significant Revenues from Energy Storage. Albuquerque, NM: Sandia National Laboratories. May 2017. https://www.sandia.gov/ess-ssl/publications/SAND2017-6164.pdf. Written by Thomas Bowen, Ilya Chernyakhovskiy, Paul Denholm, National Renewable Energy Laboratory NREL/TP-6A20-74426 | September 2019 NREL prints on paper that contains recycled content. Valley Regional Fire Authority Selfless Service. Integrity. Grit. VRFA Headquarters, 1101 D Street NE, Auburn, WA 98002 (253) 288-5800 · vrfa.org · askthevrfa@vrfa.org Published: 10/23/2024 The increasing use of commercial-scale Battery Energy Storage Systems (BESS) introduces new safety and emergency response challenges. As the Valley Regional Fire Authority (VRFA) adapts to these emerging technologies, it is essential to focus on site design, hazardous material management, proper personnel training, and having a well-structured emergency response plan. These elements are critical for ensuring a safe and effective response to any BESS incident. To manage these risks, VRFA relies on the International Fire Code (IFC) and the National Fire Protection Association (NFPA) standards while evaluating all proposed development that falls within our purview. The proposed project will follow the 2023 edition of NFPA 855, Standard for the Installation of Stationary Energy Storage Systems, and the amended Chapter 12 of the Washington State IFC, which took effect on March 15, 2024, through an emergency ruling by the State Building Council to ensure the most current safety measures can be applied towards BESS development. Additionally, the project will adhere to the City of Auburn (COA) Engineering and Design Standards (EDS), interpreting all other IFC codes from the appropriate code cycle for the project. To allow Valley Regional Fire Authority to follow the best practices for emergency response outlined in Tesla’s Industrial Lithium-Ion Battery Emergency Response Guide for the Megapack, onsite hydrants meeting section 7.06.01 of COA EDS will be required. Each Tesla Megapack must follow the commercial hydrant spacing requirements for commercial development. With the probability of water being applied during an emergency fire event at the property, onsite water containment should be considered to help prevent contaminated runoff into the nearby protected wetlands. VRFA is an all-hazards fire agency and will respond to all fire, medical, and other emergencies within the cities of Algona, Auburn, Pacific, and Fire District 31. This would include any emergency incidents at BESS facilities. However, any response to a BESS site, especially a fire or discharge event, would likely require both local and regional assets due to the unique features and risks associated with these sites. A fire or discharge incident at a BESS facility would be treated as a hazardous materials incident. All VRFA emergency response personnel are trained to an Operations level for hazardous materials EXHIBIT C Valley Regional Fire Authority 2 response as defined in WAC 296-824-30005, Safety Standards for Emergency Response, while three are trained to the higher Technician level. This distribution is similar in other local fire departments. Because of these training levels and the high-risk, low frequency nature of hazardous materials incidents, the VRFA and our regional partners rely on automatic and mutual aid agreements to respond to and mitigate hazardous materials incidents. Response modeling determines the type, number, and order of emergency response assets to incidents based on established risk management criteria. Currently, an initial hazardous emergency response to a BESS site in Auburn would include VRFA, Puget Sound Regional Fire Authority, South King Fire and Rescue, and Renton Regional Fire Authority, at minimum. Combined with a fire response, there may be a significant impact on the area and the availability of fire-based resources. Furthermore, a review of previous incidents has shown that these emergencies span multiple operational periods – i.e., 12 or more hours – as the prescribed method for remediation of thermal events is to let the systems burn. This may necessitate extended evacuations and/or road closures due to smoke, water runoff from exposure protection, and the large presence of emergency vehicles. Finally, a prolonged response to a BESS would require coordinated public safety response and ongoing messaging to the community from VRFA, the City of Auburn, and other partners. Incident Review— Melba Battery Fire Presentation to Canyon County October 18, 2023 EXHIBIT D Topics to Cover Melba Incident Review Air Quality Testing Results Fire Response & Investigation Inspection & Remediation Other Lessons Learned Current & Future Battery Storage Needs Introductions •Megan Ronk,Economic Development & Innovations Director •Eric Hackett,Projects & Design Senior Manager •Bill Norris,Environmental Compliance Manager •Angelique Rood, Regional Manager Melba Incident Review •The fire was reported to Idaho Power at 5:20 a.m., Monday Oct. 2 •Idaho Power arrived on-site at 6:02 a.m. •Neighbors were encouraged to evacuate, hotels offered •Fire responders reported on-site, no action needed •Roads were closed to maintain a 200 ft perimeter •Regular updates to fire, city, and county throughout event •Industrial Hygiene Professionals arrived to begin air quality testing at approximately 11:00 a.m. –National firm with mobile instrumentation arrived Tuesday, Oct. 3 Air Quality Testing Results •3rd party real-time air monitoring –Immediate monitoring conducted afternoon and evening of Oct. 2 –Continuous monitoring performed evening of Oct. 3–Oct. 5 (duration of fire) –Analyte selection: vendor material information and common contaminants from fires –Sampling locations based on nearby residential dwellings and prevailing winds No detected analytes above health-based action levels Fire Response & Investigation •Idaho Power and battery supplier monitored 24x7 until fire was extinguished •Advised by battery supplier to not add water or retardant, consistent with current industry practices Fire Response & Investigation •Comprehensive investigation at Melba –Battery supplier believes the root cause to be water intrusion –Short-circuit caused heat that ignited the battery cells –Fire spread between battery segments until it burned out •Supplier believes that an identified defective unit is where the fire originated due to water intrusion •Idaho Power third-party experts engaged to provide independent conclusions and recommend appropriate mitigation measures •Developing plans for removal Inspection & Remediation •Melba incident has emphasized heightened need and awareness for inspection and remediation across Idaho Power battery systems –Meet specifications, codes, and testing ratings –Ensure safe operation –Ensure emergency response clarity •Complete inspection of all battery systems with supplier and independent third-party –Water intrusion –Defects –Mitigation measures and success Inspection & Remediation •Determine appropriate mitigation strategies –Resolve water intrusion –Reduce propagation between battery segments •Consult with third-party experts to ensure ongoing safe operation •Develop additional procedures, processes, inspection protocols, and contingency plans •Complete rigorous technical and engineering diligence and specification review of future suppliers Other Lessons Learned •Improved coordination with stakeholders prior to battery installation is necessary –Training with public safety partners –Better communication with city and county officials •Idaho Power staff to be better equipped with information on battery units to aid in communication and information sharing •Previous work with Canyon County aided in cooperation during the event –Messaging was timely, coordinated, and accurate Other Lessons Learned •Operational experience –Establish subject expertise –Mitigation strategies –Contingency planning –Emergency response Current & Future Battery Storage Needs •Growth info –Capacity needs-23% customer growth in Canyon County (2018-2023) •Why Melba specifically –Steady load growth –Batteries supports local peak demand and help meet system needs –Affordable and reliable –Local resiliency benefits •Other Canyon County installations –Happy Valley Substation (Nampa) Melba Project Timeline •Need identified in spring 2021 –Transformer overload given sustained growth in Melba –2-MW four-hour battery storage system –Defer transformer upgrade by 10+ years •Supplier solicitation, review, and contract through the end of 2021 –Numerous suppliers evaluated based on specification, timeline, and cost Melba Project Timeline •Batteries were delivered/installed in summer 2023 •Testing/commissioning began in September 2023 –Control electronics, monitoring equipment, auxiliary power, fire suppression system, HVAC •Expected to be fully operational in early October Our Electric Grid How Batteries Can Help The Future of Battery Storage •Industry is advancing technology, including safe operations –Worldwide, batteries are generally proven and safe –Supplier/industry expertise –Battery experts –Community collaboration •Affordable and reliable –Anticipated in Idaho Power Integrated Resource Plan •Provide ability to store energy to meet customer needs at any time –Potential to support economic development and meet timelines –Support local needs as well as system benefits Questions EXHIBIT E /s/ Mark Orthmann, as authorized by email on May 14, 2024 FINAL BILL REPORT E2SHB 1216 C 230 L 23 Synopsis as Enacted Brief Description: Concerning clean energy siting. Sponsors: House Committee on Appropriations (originally sponsored by Representatives Fitzgibbon, Doglio, Berry, Reed, Simmons, Macri, Fosse and Pollet; by request of Office of the Governor). House Committee on Environment & Energy House Committee on Appropriations Senate Committee on Environment, Energy & Technology Senate Committee on Ways & Means Background: Energy Facility Siting. The Energy Facility Site Evaluation Council (EFSEC) was established in 1970 to provide a single siting process for major energy facilities. The EFSEC coordinates all evaluation and licensing steps for siting certain energy facilities, as well as specifies the conditions of construction and operation. After evaluating an application, the EFSEC submits a recommendation either approving or rejecting an application to the Governor, who makes the final decision on site certification. If approved by the Governor, a site certification agreement is issued in lieu of any other individual state or local agency permits. The laws that require or allow a facility to seek certification through the EFSEC process apply to the construction, reconstruction, and enlargement of energy facilities, biorefineries, and electrical transmission facilities, with many specifications. Energy facilities of any size that exclusively use alternative energy resources, such as wind or solar energy, may opt into the EFSEC review and certification process. Energy facilities that exclusively use alternative energy resources that choose not to opt in to the EFSEC review and certification process must instead receive applicable state and local agency development and environmental permits for their projects directly from each agency. This analysis was prepared by non-partisan legislative staff for the use of legislative members in their deliberations. This analysis is not part of the legislation nor does it constitute a statement of legislative intent. E2SHB 1216-1 -House Bill Report EXHIBIT F Projects of Statewide Significance. Since 1997 a process has existed to support the development of certain types of industrial projects of statewide significance. To qualify for designation as a project of statewide significance, a project must meet capital investment or job creation requirements. Possible designations include: (1) border-crossing projects; (2) private projects investing in manufacturing, research, and development; (3) projects that will provide a net environmental benefit; and (4) projects that will further commercialization of an innovation. The Legislature has designated certain types of projects as projects of statewide significance; for all other types of projects, an application for designation as a project of statewide significance must be submitted to the Department of Commerce. The application must include a letter of approval from jurisdictions where a project is located and must commit to providing the local staff necessary to expedite the completion of a project. Counties and cities with projects must enter into agreements with the Governor's Office of Regulatory Innovation and Assistance (ORIA) and local project managers to expedite the processes necessary for the design and construction of projects. The ORIA must provide facilitation and coordination services to expedite completion of industrial projects of statewide significance. The project proponents may provide the funding necessary for the local jurisdiction to hire the staff required to expedite the process. State Environmental Policy Act. The State Environmental Policy Act (SEPA) establishes a review process for state and local governments to identify environmental impacts that may result from governmental decisions, such as the issuance of permits or the adoption of land use plans. The SEPA environmental review process involves a project proponent or the lead agency completing an environmental checklist to identify and evaluate probable environmental impacts. If an initial review of the checklist and supporting documents results in a determination that the government decision has a probable significant adverse environmental impact, known as a threshold determination, the proposal must undergo a more comprehensive environmental analysis in the form of an environmental impact statement (EIS). If the SEPA review process identifies significant adverse environmental impacts, the lead agency may deny a government decision or may require mitigation for identified environmental impacts. Under SEPA rules adopted by the Department of Ecology (Ecology), after the submission of an environmental checklist and prior to a lead agency's threshold determination, an applicant may ask the lead agency to indicate whether it is considering a determination of significance. If the lead agency indicates that a determination of significance is likely, the applicant may clarify or change features of the proposal to mitigate the impacts which led the agency to consider a determination of significance to be the likely threshold determination. If an applicant revises the environmental checklist as necessary to describe the clarifications or changes, the lead agency must make its threshold determination based on the changed or clarified proposal. Lead agencies undertaking SEPA review must aspire to finish an EIS as expeditiously as possible without compromising the integrity of the analysis. For complex government E2SHB 1216- 2 -House Bill Report decisions, the lead agency must aspire to finish an EIS within 24 months of making a threshold determination that an EIS is needed; for government decisions with narrower and more easily identifiable environmental impacts, the lead agency must aspire to finish in far less time than 24 months. The aspirational time limit does not create civil liability or a new cause of action against a lead agency. Ecology must submit a report to the Legislature every two years on recent EISs. Under SEPA rules, when a lead agency prepares an EIS on a nonproject proposal, the lead agency has less detailed information available on environmental impacts and the environmental impacts of any subsequent project proposals that may follow the EIS. The lead agency's nonproject EIS must discuss impacts and alternatives in the level of detail appropriate to the scope of the proposal and the level of planning for the proposal. If a specific geographic area is the focus of a nonproject EIS, site specific analyses are not required but may be included for specific areas of concern. After the approval of a nonproject EIS by the lead agency based on the EIS assessing the proposal's broad impacts, when a project is proposed that is consistent with the approved nonproject action that was the subject of the nonproject EIS, the EIS for the project proposal must focus on the impacts and alternatives, including mitigation measures, that are specific to the subsequent project and that were not analyzed in the nonproject EIS. Procedures allow for the adoption and use of portions of the nonproject EIS in a subsequent project-level SEPA review. Lead agencies must, at the time of project-level SEPA review, evaluate the nonproject EIS that was previously completed to ensure that the nonproject analysis is valid when applied to the current proposal, knowledge, and technology. If a nonproject EIS's analysis is no longer valid, the analysis must be reanalyzed in the project-level EIS. Local Project Review. Counties and cities planning under the Growth Management Act (GMA) are required to establish an integrated and consolidated development permit process for all projects involving two or more permits and to provide for no more than one open record hearing and one closed record appeal. Other jurisdictions may incorporate some or all of the integrated and consolidated development permit process. The permit process must include a determination of completeness of the project application within 28 days of submission. A project permit application is determined to be complete when it meets the local procedural submission requirements even if additional information is needed because of subsequent project modifications. Within 14 days of receiving requested additional information, the local government must notify the applicant whether the application is deemed complete. The determination of completeness does not preclude the local government from requesting additional information if new information is required or substantial project changes occur. A project permit application is deemed complete if the GMA jurisdiction does not provide the determination within the required time period. Summary: Interagency Clean Energy Siting Coordinating Council. E2SHB 1216- 3 -House Bill Report An Interagency Clean Energy Siting Coordinating Council (Coordinating Council) is created, and is co-chaired and co-staffed by the Department of Ecology (Ecology) and the Department of Commerce (Commerce). The Coordinating Council must have participation from at least 11 named state agencies or offices in addition to Ecology and Commerce. The Coordinating Council's responsibilities are enumerated and include: identifying actions to improve the siting and permitting of clean energy projects;• tracking federal government efforts;• soliciting input from parties with interests in clean energy project siting and permitting; and • supporting the creation and annual update of a list to be published by the Governor's Office of Indian Affairs containing contacts at federally recognized Indian tribes, applicable tribal laws on consultation, and tribal preferences regarding clean energy project siting and outreach. • The Coordinating Council must provide annual updates to the Governor and the Legislature. The Coordinating Council must advise Commerce in contracting for an independent third party to evaluate state agency siting and permitting processes, identify successful models used in other states for siting and permitting clean energy projects, and make recommendations for improvements by July 1, 2024. The Coordinating Council, led by Ecology, must also pursue development of a consolidated clean energy application and must explore development of a consolidated permit for clean energy projects. Ecology must update the Legislature on the consolidated clean energy application and the consolidated permit by the second half of 2024. Clean Energy Projects of Statewide Significance. Commerce must establish an application process for the designation of Clean Energy Projects of Statewide Significance (CEPSS). The CEPSS process contains similar elements to the existing Projects of Statewide Significance process, but is independent of that process. Applicants must demonstrate certain information to Commerce as part of the CEPSS application, including an explanation of how the project will contribute to the state's achievement of state greenhouse gas emission limits and be consistent with the state energy strategy, how the product will contribute to the state's economic development goals, and a plan for meaningful engagement and information sharing with potentially affected federally recognized Indian tribes. The clean energy projects eligible for designation as a CEPSS include: certain types of clean energy product manufacturing facilities;• electrical transmission facilities that don't primarily or solely serve fossil fuel electric generation facilities; • facilities that produce electric generation from renewable resources or that do not result in greenhouse gas emissions, with the exception of certain hydroelectric facilities; • storage facilities;• E2SHB 1216- 4 -House Bill Report facilities and projects at any facilities that exclusively or primarily process biogenic feedstocks into biofuel; • biomass energy facilities;• facilities or projects at any facilities that exclusively or primarily process alternative jet fuel that has 40 percent lower greenhouse gas emissions than conventional jet fuel; • projects or facility upgrades undertaken by emissions-intensive trade exposed industries classified under the Climate Commitment Act (CCA) to align with the CCA's cap trajectory, where a project does not degrade local air quality; and • storage, transmission, handling, or other related and supported facilities associated with any of the above facilities. • Commerce must determine within 60 business days of receipt of a complete application whether to designate a clean energy project as a CEPSS, taking into consideration criteria including the applicant's need for coordinated state assistance, whether a nonproject environmental review process or least-conflict siting process has been carried out in the project's area, and the potential impacts on environmental and public health. Commerce may designate an unlimited number of CEPSS. The Coordinated Permit Process Available to Clean Energy Projects. Ecology is given certain responsibilities for coordinating a fully coordinated permitting process for clean energy projects. The coordinated permitting process serves as an option, but not a requirement, for those seeking permits for clean energy projects. Upon request, Ecology must conduct an initial assessment of a clean energy project to determine the level of coordination needed and the complexity, size, and need for assistance of the project, including specified permitting and environmental review processes. Ecology's initial assessment must be documented in writing, made available to the public, and completed within 60 days of the request for the initial assessment. A clean energy project proponent may request that Ecology convene a fully coordinated permit process. A clean energy project proponent must provide specified information and enter into a cost reimbursement agreement with Ecology to cover the costs to Ecology and other agencies in carrying out the coordinated permit process. To convene the coordinated permit process, Ecology must determine that the clean energy project raises complex coordination, permit processing, or substantive review issues. Ecology serves as the main point of contact for the project proponent and participating agencies, and keeps a schedule identifying procedural steps in the permitting process and highlighting substantive issues that require resolution. A project proponent may withdraw from the coordinated permit process. Within 30 days of accepting a project for the coordinated permit process, Ecology must convene a work plan meeting to develop a coordinated permit process schedule with the project proponent, local government, and participating permit agencies. Each participating agency and the lead agency under the State Environmental Policy Act (SEPA) must send E2SHB 1216- 5 -House Bill Report representatives to the work plan meeting, and relevant federal agencies and potentially affected federally recognized Indian tribes must be notified and invited to participate. Any accelerated time periods for permits or SEPA review under the coordinated permit process schedule must be consistent with statute, rules, regulations, or adopted state policies, standards, and guidelines for public participation and the participation of other agencies and federally recognized Indian tribes. The coordinated permit process schedule must be finalized and made available to the public after the work plan meeting. Cities and counties with development projects determined as eligible for the coordinated permit process within their jurisdictions must enter into an agreement with Ecology or project proponents for expediting the completion of projects, including expedited permit processing and environmental review processing. Following specified procedures, Ecology must offer early, meaningful, and individual consultation with any affected federally recognized Indian tribe on a clean energy project participating in the coordinated permit process. Ecology must identify overburdened communities that might be potentially affected by the clean energy project and verify that these communities have been meaningfully engaged in the regulatory processes in a timely manner by participating agencies. Applicants using the fully coordinated permit process are not eligible to apply for site certification under the Energy Facility Site Evaluation Council (EFSEC) process unless a substantial change is made to the proposed project. The CEPSS designation and coordinated permit process does not affect the jurisdiction of the EFSEC, limit or abridge the powers of a participating permit agency, or prohibit a state agency, local government, federally recognized Indian tribe, or CEPSS applicant or project proponent from entering into nondisclosure agreements related to confidential proprietary information. State Environmental Policy Act for Clean Energy Projects. A number of new provisions are added to SEPA that apply to clean energy project proposals: In addition to the 24 month aspirational timeline that applies to all SEPA environmental impact statements (EISs), lead agencies are directed to complete an EIS for a clean energy project within 24 months of a threshold determination. Lead agencies may work with a project applicant to set or extend a time limit longer than 24 months. Lead agencies must work collaboratively with agencies that have actions requiring SEPA review for a clean energy project to develop a schedule that includes a list of agency responsibilities, actions, and deadlines. Failure to comply with the SEPA timeline requirements is not subject to appeal, does not invalidate SEPA review, and does not create civil liability or create a new cause of action. • Lead agencies may not combine the evaluation of a clean energy project proposal with other proposals unless the proposals are closely related or the applicant agrees to • E2SHB 1216- 6 -House Bill Report a combined SEPA review. Lead agencies may require mitigation measures for clean energy projects only to address the environmental impacts that are attributable to and caused by a proposal. After submitting an environmental checklist, but prior to a threshold determination, a lead agency must notify a clean energy project applicant that a project proposal is likely to result in a determination of significance. The lead agency must provide the project applicant the option of withdrawing or revising the application, and must use any revised application as the basis for the threshold determination. • Ecology must prepare three nonproject EISs: one for solar energy projects, one for onshore wind energy projects, and one for green electrolytic or renewable hydrogen projects. Each nonproject EIS must include analysis of co-located battery storage for such hydrogen, solar, and wind projects. Ecology must include certain information in the nonproject EIS and address specified types of environmental impacts, and determine the EIS's scope based on input from specified parties. Ecology must offer early and meaningful consultation on the nonproject EIS's with any affected federally recognized Indian tribe. The nonproject EISs must result in the development of maps identifying probable significant adverse environmental impacts for evaluated resources. Following the completion of nonproject EISs, the Coordinating Council must review the findings and make recommendations to the Legislature and the Governor on potential areas to designate as clean energy preferred zones for the technology analyzed, and any taxation, regulatory, environmental review, or other benefits that should accrue to projects in those zones. Project proponents of actions covered by these nonproject EISs must consider the impact analysis from the nonproject EIS in carrying out project-level SEPA reviews, and may rely on the nonproject EIS in specified ways when carrying out project-level SEPA review. Clean energy projects that follow the recommendations of the nonproject environmental review must be considered to have mitigated environmental impacts unless the project-specific environmental review identifies project-level adverse environmental impacts not addressed in the nonproject environmental impact review. Other. During a local project review of a project to construct or improve electric generation, transmission or distribution facilities, a local government may not require a project applicant to demonstrate the necessity or utility of the project, other than to require as part of the completed project application the submission of documentation required by Federal Energy Regulatory Commission or other federal agencies with regulatory authority over electric power transmission and distribution needs, or the Utilities and Transportation Commission. A county may not prohibit the installation of wind and solar resource evaluation equipment necessary for the design and environmental planning of a renewable energy project. The Washington State University (WSU) Energy Program must conduct a pumped storage siting process to support expanded capacity to store intermittently produced renewable E2SHB 1216- 7 -House Bill Report energy, with a goal of understanding issues and interests related to areas where pumped storage might be sited, and to provide useful information to developers and for subsequent SEPA reviews of environmental impacts. The WSU Energy Program must allow ample opportunity for participation by stakeholders, governments, and federally recognized Indian tribes who self-identify an interest in the process, and must complete the process by June 30, 2025. The WSU Energy Program must develop and make available a map with geographical information systems data layers highlighting areas identified through the process. The map may not include sensitive tribal information as identified by federally recognized Indian tribes and the WSU Energy Program must take precautions to prevent disclosure of any sensitive tribal information it receives. Commerce must conduct at least three stakeholder meetings focused on certain rural clean energy impacts, with at least one in Eastern Washington and at least one in Western Washington. These stakeholder meetings must be held with rural, agriculture, natural resource management and conservation, and forestry stakeholders to gain a better understanding of the benefits and impacts of anticipated changes in the state's energy system, including the siting of facilities under the jurisdiction of the EFSEC, and to identify risks and opportunities for rural communities. Commerce must then complete a report on rural clean energy and resilience, which must consider the stakeholder consultation and must include recommendations for how to more equitably distribute costs and benefits to rural communities. The report must specifically examine the impacts of energy projects in rural areas to jobs, local tax revenue, agriculture, and tourism, and it must forecast what Washington's clean energy transition will require for energy projects in rural Washington. Commerce must complete a report on these topics by December 1, 2024. The Joint Committee on Energy Supply and Energy Conservation is renamed the Joint Committee on Energy Supply, Energy Conservation, and Energy Resilience (Joint Committee). The Joint Committee must hold at least two meetings to consider policy and budget recommendations to reduce impacts and increase benefits of the clean energy transition for rural communities. The Joint Committee must report its findings and any recommendations to the EFSEC and the Legislature by December 1, 2024. A severability clause is included. Votes on Final Passage: House 75 20 Senate 30 18 (Senate amended) House 78 18 (House concurred) Effective:July 23, 2023 E2SHB 1216- 8 -House Bill Report EXHIBIT G © PSC 2 4010 Lake Washington Blvd NE Suite 300 Kirkland, WA 98033 P: 425-822-8489 W: https://www.pscconsulting.com Page i Energy Storage System Location Study For: Puget Sound Energy Prepared by Tracy Rolstad (Technical Director) Power Systems Consultants Client Reference : Puget Sound Energy PSC Reference : JU8426 Revision: Final (revised) Date: 25 June 2021 EXHIBIT H © PSC Revision Final 4010 Lake Washington Blvd NE Suite 300 Kirkland, WA 98033 Page i P: 425-822-8489 W: https://www.pscconsulting.com Contents 1. Introduction .......................................................................................................................................... 1 1.1. Disclaimer ..................................................................................................................................... 2 1.2. Energy Storage System (ESS) Discussion and Example ................................................................. 3 2. Methodology ......................................................................................................................................... 4 2.1. Qualitative Method ....................................................................................................................... 4 2.1.1. Substation Interconnection Suitability ....................................................................................... 4 2.1.2. ESS Siting Suitability .................................................................................................................... 5 2.2. Qualitative Method - Example ...................................................................................................... 6 2.3. Quantitative Method .................................................................................................................... 7 2.3.1. Quantitative Software Use and Approach .................................................................................. 8 3. Results ................................................................................................................................................... 9 3.1. Qualitative Results ........................................................................................................................ 9 3.1.1. Candidate Stations .................................................................................................................... 10 3.2. Quantitative Results ................................................................................................................... 12 3.2.1. Quantitative Results .................................................................................................................. 12 4. Analysis ............................................................................................................................................... 16 5. Conclusions and Recommendations ................................................................................................... 21 Figures and Tables Figure 1.1 Hornsdale Power Reserve…….………………………………………………………………………………………………….3 Figure 2.1 Undesirable Station: Klahanie.…………………………………………………………………………………………………6 Figure 2.2 Desirable Station: Alderton………………………………………………………………………………………………………7 Figure 4.1 Location of Selected Stations…………………………………………………………………………………………………20 Table 3.1 Qualitative Results for Low Risk (Green) and Medium Risk (Yellow) Stations …………………………10 Table 3.2 Qualitative Results for High Risk (Red) Stations ………………………………………………………………………11 Table 3.3 P0 Quantitative Results ………………………………………………………………………………..………………………..13 Table 3.4 P1 Quantitative Results ………………………………………………………………………………..………………………..14 Table 3.5 P6 Quantitative Results ………………………………………………………………………………..………………………..15 Table 4.1 Combined Quantitative Results………………………………………………………………………..……………………..17 Table 4.2 Locational Data with Maximum ESS Results……………………………………………………….……………………18 Table 4.3 Final Results……………………………………………………………………………………………………….……………………19 JU8426 - PSC Report for Puget Sound Energy ESS Locations © PSC 14 4010 Lake Washington Blvd NE Suite 300 Kirkland, WA 98033 P: 425-822-8489 W: https://www.pscconsulting.com Page 1 of 21 1. Introduction Puget Sound Energy (PSE) engaged Power Systems Consultants (PSC) to perform a qualitative and quantitative analysis for siting a possible Energy Storage System (ESS) within the PSE electrical system. PSE filed a draft All-Source Request for Proposals (RFP) for peak capacity resources on May 4, 2020. Interconnection studies of an ESS onto a transmission system can result in the need for significant and costly network upgrades, depending upon interconnection location. This report serves as a starting point for proponents or bidders into the RFP as an aid to determine potential / lower risk locations (with respect to network upgrade costs) for interconnection of energy storage resources (and others) into PSE’s transmission system. The ESS is expected to perform in a manner consistent with the FERC defined Network Resource Interconnection Service. In general, this study is like a Feasibility Study in concept, but not necessarily in scope. Screening techniques examined the potential ESS capacity available at several Puget stations. Detailed analysis (like those completed for a Feasibility Study) was not performed. The FERC definition of Network Resource Interconnection Service (below) can be used as a contextual guide in order to understand the purpose of this study. Network Resource Interconnection Service shall mean an Interconnection Service that allows the Interconnection Customer to integrate its Large Generating Facility with the Transmission Provider’s Transmission System (1) in a manner comparable to that in which the Transmission Provider integrates its generating facilities to serve native load customers; or (2) in an RTO or ISO with market based congestion management, in the same manner as Network Resources. Network Resource Interconnection Service in and of itself does not convey transmission service. Transmission Provider must conduct the necessary studies and construct the Network Upgrades needed to integrate the Large Generating Facility (1) in a manner comparable to that in which Transmission Provider integrates its generating facilities to serve native load customers; or (2) in an ISO or RTO with market based congestion management, in the same manner as Network Resources. Network Resource Interconnection Service Allows Interconnection Customer’s Large Generating Facility to be designated as a Network Resource, up to the Large Generating Facility’s full output, on the same basis as existing Network Resources interconnected to Transmission Provider’s Transmission System, and to be studied as a Network Resource on the assumption that such a designation will occur. The Interconnection Study for Network Resource Interconnection Service shall assure that Interconnection Customer’s Large Generating Facility meets the requirements for Network Resource Interconnection Service and as a general matter, that such Large Generating Facility’s interconnection is also studied with Transmission Provider’s Transmission System at peak load, under a variety of severely stressed conditions, to determine whether, with the Large Generating Facility at full output, the aggregate of generation in the local area can be delivered to the aggregate of load on Transmission Provider’s Transmission System, consistent with Transmission Provider’s reliability criteria and procedures. This approach assumes that some portion of existing Network Resources are displaced by the output of Interconnection Customer’s Large Generating Facility. Network Resource Interconnection Service in and of itself does not convey any right to deliver electricity to any specific customer or Point of Delivery. The Transmission Provider may also study the Transmission System under non-peak load conditions. However, upon request by the Interconnection Customer, the Transmission Provider must explain in writing to the Interconnection Customer why the study of non-peak load conditions is required for reliability purposes . JU8426 – PSC Report for Puget Sound Energy ESS Locations © PSC 4010 Lake Washington Blvd NE Suite 300 Kirkland, WA 98033 Page 2 of 21 P: 425-822-8489 W: https://www.pscconsulting.com 1.1. Disclaimer Note that all the information used for the study is available to any member of the public either directly (i.e., geo-location from the Department of Homeland Security) or via non-disclosure agreements with the Western Electricity Coordinating Council (for WECC base cases). Some information (one-lines and station configurations) used (as an analytical aid) is based on FERC Form 715 submissions that pre-date (circa October 2001) the CEII classification of FERC 715 data. Station configurations and interconnections were confirmed with recent imagery. The best possible data and analytical technique was used for this study; however, no warranty is offered by Power Systems Consultants for fitness of use of any data associated with this report or the contents of the report itself. PSC did not perform a purposeful review of base cases, maps, or one-lines for accuracy. This study was completed outside of the OATT and is intended to broadly inform interested readers. It does not replace any OATT driven processes or documentation, nor is it intended to do so. The results in this document do not indicate that available transmission exists or that a station is suitable for interconnection from an official FERC LGIA process viewpoint. JU8426 - PSC Report for Puget Sound Energy ESS Locations © PSC 14 4010 Lake Washington Blvd NE Suite 300 Kirkland, WA 98033 P: 425-822-8489 W: https://www.pscconsulting.com Page 3 of 21 1.2. Energy Storage System (ESS) Discussion and Example Modern utility scale ESS’s store energy in the form of electro-chemical or mechanical energy, then convert that energy into electrical energy when appropriate, based on sophisticated control schemes. Examples of electro-chemical storage include Lead Acid, Nickel-Cadmium, Lithium-Ion, and Molten Salt amongst others. Flow batteries are another type of electro-chemical battery, with Redox being an example. Mechanical energy storage examples include Flywheels, Pumped Hydro, and Compressed Air Energy Storage systems. The study effort is agnostic to energy storage technology type and focuses primarily on the requirements of the ESS to interconnect on the PSE transmission system. An example of a deployed Energy Storage System (located in South Australia) is shown in Figure 1.1. This is presently the world’s largest ESS that uses Lithium-Ion batteries. The purpose of introducing this project is to give a sense of relative scale associated with a high energy capacity/high power ESS. Figure 1.1 Hornsdale Power Reserve ESS JU8426 – PSC Report for Puget Sound Energy ESS Locations © PSC 4010 Lake Washington Blvd NE Suite 300 Kirkland, WA 98033 Page 4 of 21 P: 425-822-8489 W: https://www.pscconsulting.com 2. Methodology Two methodologies were employed for this study. A qualitative and a quantitative method. The qualitative method is a high-level review to determine potential for interconnection at the substation and to determine the potential to site an ESS in the area (PSE’s property is not available for siting the ESS for this analysis). If a substation meets the evaluation metrics (detailed below) for the qualitative method, the locations will be further studied with the quantitative method. The quantitative method is a high-level power flow analysis of the PSE transmission system, using official WECC databases to review the system performance with the addition of an ESS during charging and discharging conditions, for a multitude of system conditions and system contingencies. These details of the qualitative and quantitative methods are discussed in the relevant section below. 2.1. Qualitative Method Overhead imagery was utilized to determine the location of Puget’s substations. This imagery was analysed in conjunction with WECC base cases and FERC 715 filings (pre-2001) that contain one-line drawings of the Puget system. We note that prior to October 2001 FERC 75 filings were available to the public. The stations were geo-located, mapped, locations were populated in the power flow-based cases, and then substations were created in the power flow base cases in order to support more detailed analysis using modelling and simulation tools. 2.1.1. Substation Interconnection Suitability PSC examined the candidate substations to determine their suitability for expansion to accommodate interconnection of an ESS to the substation. This study assumes the ESS is sited off of PSE land in the area near the substation. Evaluation metrics are as below: Must interconnect to an existing Puget station Interconnects to PSE “native” network west of Cascades, no wheeling No radial or “return loop” transmission Above >100 kV point of interconnection (POI) per following details: o At least 4 lines for 115 kV candidate stations o Or non-radial 230 kV station Expansion space “in-the-gravel” in the station exists Development potential of existing station for interconnection is evident o Open space is desirable o Heavy residential presence is not desirable o Must pass the “Good Neighbor” test, which from an electric utility perspective has the following attributes: Use of eminent domain proceedings is the absolute last resort with condemnation only used for those projects that are extremely mission critical and are supported politically. The minimal number of landowners are impacted by a project and those landowners are justly compensated at prevailing rates. Projects are developed with a focus on maximizing the use of existing “encumbered” properties. JU8426 - PSC Report for Puget Sound Energy ESS Locations © PSC 14 4010 Lake Washington Blvd NE Suite 300 Kirkland, WA 98033 P: 425-822-8489 W: https://www.pscconsulting.com Page 5 of 21 Land use should be reasonably consistent with its present use and the addition of electric utility infrastructure should be designed to be as unnoticeable as possible Early involvement of the public in the development process is a must and the public should be encouraged to provide constructive input and alternative projects/locations The public knows their neighbourhood best and can suggest minimum impact alternatives Successful “Good Neighbor” projects leave the affected area better than it was before the project was executed. Identify substation configuration allows for additional breaker position o Ring bus, breaker and a half, double bus double breaker is preferred. o Main bus (with aux bus) has questionable reliability and could result in additional upgrades, up to rebuilding the substation to a different configuration. o Main bus (without aux bus) has poor reliability and is not suitable for interconnection of an ESS and would require substation upgrades, up to rebuilding the substation to a different configuration An internal failure of a circuit breaker causes loss of entire station Identify existing unused breaker position (breaker not installed) Identify if the substation area allows for expansion o Examine available space inside substation fence o Examine available space outside substation fence If substation has 115 kV and 230 kV voltages, preference should be given to interconnect at the 115-kV side, unless interconnection at 230 kV results in substantial benefits. 2.1.2. ESS Siting Suitability PSC examined how practical ESS siting near the substation is. This examination included: Land use and Zoning compatibility o Imagery analysis and general land usage was examined using tools such as Google Earth and Land Grid. These tools provide a means to develop a general qualitative sense of how favourable the location near a particular PSE station might be for an ESS project. o Highly residential areas, constraints for possible transmission rights-of-ways to the PSE station, schools, hospitals, and other notable land uses indicate that that specific PSE station was less desirable as a practical location to interconnect an ESS. Environmental Constraints o Overhead imagery analysis was performed in order to identify the possibility of complicated environmental constraints. For example, the PSE Snoqualmie Falls station met the basic requirements of electrical connectivity but clearly it is not a desirable location for additional development. Thus, that station was not a candidate for further analysis. JU8426 – PSC Report for Puget Sound Energy ESS Locations © PSC 4010 Lake Washington Blvd NE Suite 300 Kirkland, WA 98033 Page 6 of 21 P: 425-822-8489 W: https://www.pscconsulting.com 2.2. Qualitative Method - Example Two examples of qualitative review (i.e., go or no-go) of candidate stations are briefly discussed as follows. The Klahanie station (Figure 2.1) would be characterized as a high “risk” or red station. The Klahanie station is not desirable for an ESS interconnection due to its lack of space, residential encroachment, and general lack of development potential. Figure 2.1 Undesirable Station: Klahanie JU8426 - PSC Report for Puget Sound Energy ESS Locations © PSC 14 4010 Lake Washington Blvd NE Suite 300 Kirkland, WA 98033 P: 425-822-8489 W: https://www.pscconsulting.com Page 7 of 21 The Alderton station (Figure 2.2) is an example of a low “risk” (i.e., green station) that has desirable attributes associated with the station such as: Space for development in the immediate area Space in the station for expansion Fairly rural area that might be more easily support new rights-of-way, station expansion, or ESs siting Figure 2.2 Desirable Station: Alderton 2.3. Quantitative Method PSC used WECC power flow base cases to examine the PSE transmission system for the list of substations feasible for ESS interconnection. PSC used the PowerWorld (version 21) power flow ATC tool to perform analysis that approximates a “light-weight” generation interconnection feasibility screening study. This study is not a feasibility study under the OATT, but rather an informational screening that could aid an RFP respondent in determining where to queue for a detailed LGIA interconnection request. These POI’s were examined as charging (load) and discharging (generating) resources. JU8426 – PSC Report for Puget Sound Energy ESS Locations © PSC 4010 Lake Washington Blvd NE Suite 300 Kirkland, WA 98033 Page 8 of 21 P: 425-822-8489 W: https://www.pscconsulting.com Study Cases (WECC PowerWorld *.pwb power flow cases): o 2029-2030 Heavy Winter Case used was 30HW1a1.pwb o 2030 Heavy Summer Case used was 30HS1a.pwb A 2029 HS case was originally used but then rejected due to an incomplete PSE transmission project that caused contingency performance issues (29HS1a1.pwb) o Off-peak load case (at consultants’ discretion) which was the 2030 Light Spring case (30LSP1Sa.pwb) ESS studied as generation (discharging) and also as a load (charging) o ESS was studied one at a time No groups or combinations of ESS’s were studied Only single ESS’s were studied Only one interconnection per site location (either 115 kV or 230 kV, not both) Determine maximum ESS size at each location that results in acceptable system performance, for NERC TPL-001-4 PSE P0, P1 (N-1), and P6 (N-1-1) contingencies, while studying limited and sensitive neighbouring contingencies. 2.3.1. Quantitative Software Use and Approach The results of the qualitative analysis and study were obtained using the “ATC” tool of PowerWorld Simulator. The details for implementing this in PowerWorld are briefly described as follows: Create an ALL WECC injection group of generators to dispatch against o The following metrics were used to select generators: Pmax>10 MW Pgen>10 MW Pmin>0 o ALL WECC injection group metrics (from 30HS case) Number of generators is 2272 Total MW injection is ~191,294 MW Insert a single ESS (i.e. generator) and create an injection group for each station in Table 3.1 Create an auto-inserted list of contingencies for Area 40 Performed “Iterated Linear then Full Ctg” ATC analysis o Ignore elements with OTDFs < 3.0 o Ignore elements with PTDFs<3.0 o Report only: 20 Transfer Limiters 3 Limiters per ctg 3 Limiters per element The results were manually inspected and those limiting elements and/or contingencies that were not relevant to the ESS were ignored for further analysis. o One may view this as machine aided learning to determine those contingencies and electrical system elements that are truly associated with electrical service to the ESS sites. Many of these ignored elements/contingencies were 500 kV elements/contingencies with remedial action schemes or near their limits in the base case (for example various series capacitors associated with the California Oregon Intertie, etc). JU8426 - PSC Report for Puget Sound Energy ESS Locations © PSC 14 4010 Lake Washington Blvd NE Suite 300 Kirkland, WA 98033 P: 425-822-8489 W: https://www.pscconsulting.com Page 9 of 21 The metrics associated with the quantitative analysis are noted below: o All elements with valid ratings were scanned for performance with the ATC tool for PO, P1, and P6 conditions of the NERC TPL-001-4 standard Summer Emergency ratings were RATEA Winter Emergency ratings were RATEC Spring Emergency ratings were RATEG o P1 & P6 contingencies were those in the Northwest >100 kV P1: 1135 out of 5081 contingencies were examined for detailed P1 performance The smaller list of contingencies was selected using the Linear ATC tool which determined those contingencies sensitive to the PSE BESS sites. P6: 1107 out of 144,453 contingencies were examined for detailed P6 performance The smaller list was tested for performance using the Iterated Linear feature of the ATC tool. The larger amount was screened with the linear ATC tool. 3. Results The results of the qualitative and quantitative analysis are listed below. 3.1. Qualitative Results The results of the qualitative analysis and study were obtained in an iterative fashion. The list of candidate stations was then inspected both in PowerWorld Simulator and with overhead imagery to cull undesirable locations. The results follow: 382 total PSE initial stations (based on software results). o The 382-station count may not be a figure that exactly matches the number of stations that PSE has. This is due to the software requirement for a tapped line to be modeled with a bus, which might not be representative of an actual substation bus. o These 382 stations were geo-located. 36 PSE stations were kept for overhead imagery analysis based on the following: o Is 230 kV non-radial service. o Or is > 4 lines of 115 kV non-radial service. o And within PSE network Determined from geo-location and bus ownership o Substation configuration metrics were not included in determining of the initial candidate stations. The 36 PSE stations were analysed and grouped by the following criteria for risk regarding ESS site location and interconnection: o Substation area analysis o Surrounding area analysis o Refined understanding of interconnection based on imagery analysis 12 stations (of the 36) were assigned “green”, for initial low risk ESS interconnection 8 stations (of the 36) were assigned “yellow”, for initial medium risk ESS interconnection 16 stations (of the 36) were assigned “red”, for high risk due to not meeting the initial qualitative screening metrics JU8426 – PSC Report for Puget Sound Energy ESS Locations © PSC 4010 Lake Washington Blvd NE Suite 300 Kirkland, WA 98033 Page 10 of 21 P: 425-822-8489 W: https://www.pscconsulting.com 3.1.1. Candidate Stations Table 3.1 lists the 20 PSE stations that were analyzed in detail. These stations were visually inspected with recent overhead imagery and are organized by color for low risk and medium risk substations. As previously stated, the substation configuration metrics were not used for the initial candidate stations and will be addressed later in the report. Substations that are of a main bus configuration are highlighted in red. Table 3.1 Qualitative Results for Low Risk (Green) and Medium Risk (Yellow) Stations Sub Name Nominal kV Range # of Lines Bus Configuration (low & high voltage) Zone Alderton 115.0 (only) 7 Main & Aux PIERCE Berrydale 115.0 to 230.0 7 Main & Aux / Brk & half S.KING Christopher 115.0 (only) 6 Main Bus S.KING Frederickson 13.8 to 115.0 4 Main Bus PIERCE Fredonia 13.8 to 230.0 (115kV) 2 Main Bus SKAGIT Lake Tradition 115.0 (only) 8 Main Bus N.KING March Point 115.0 to 230.0 12 Main & Aux / Xfrm Term SKAGIT Midway 115.0 (only) 6 Main & Aux S.KING Saint Clair 115.0 to 230.0 7 Main & Aux / DB-DB THURSTN Sammamish 115.0 to 230.0 11 Main & Aux / Main & Aux N.KING Talbot Hill 115.0 to 230.0 14 Main & Aux / DB-DB S.KING Tono 115.0 (only) 4 Main & Aux THURSTN Bellingham 115.0 (only) 11 Brk & half WHATCOM Krain Corner 57.5 to 115 6 Main Bus PIERCE O’Brien 115.0 to 230.0 11 Main & Aux / Xfrm Term S.KING Portal Way 115.0 (only) 5 Main & Aux WHATCOM S. Bremerton 115.0 to 230.0 6 Main & Aux / Xfmr Term KITSAP Sedro Woolley 115.0 to 230.0 12 Main & Aux / Brk & half SKAGIT Starwood 115.0 (only) 4 Main Bus S.KING White River 115.0 to 230.0 12 Main & Aux / DB-DB PIERCE JU8426 - PSC Report for Puget Sound Energy ESS Locations © PSC 14 4010 Lake Washington Blvd NE Suite 300 Kirkland, WA 98033 P: 425-822-8489 W: https://www.pscconsulting.com Page 11 of 21 Table 3.2 lists those stations that were deemed high risk and thus not selected for more detailed analysis. Table 3.2 Qualitative Results for High Risk (Red) Stations Sub Name Nominal kV Range # of Lines Substation Type Zone ARCO C 115.0 (only) 4 Main Bus WHATCOMI BAKER SW 115.0 (only) 4 Main Bus SKAGIT BALDI 230.0 (only) 2 Tap S.KING CASCADE 34.5 to 230.0 3 Xfmr Term/Main Bus KITTITAS COTAGEBR 115.0 (only) 4 Main Bus N.KING ELECTHTS 57.5 to 115.0 5 Xfmr Term/Main Bus PIERCE HORSRNCH 230.0 (only) 3 Main Bus N.KING HRNCHTAP 230.0 (only) 2 Tap N.KING KLAHANIE 230.0 (only) 2 Tap N.KING LAKESIDE 115.0 (only) 7 Main Bus N.KING MINTFARM 13.8 to 230.0 1 Main (Gen Interconnection) Portland Area NOVELTYH 115.0 to 230.0 7 Main & Aux/Main Bus N.KING OLYMPA P 115.0 (only) 9 Main Bus THURSTN SHUFFLETON 115.0 (only) 4 Main & Aux S.KING SNOQ SW 2.0 to 115.0 5 Main Bus N.KING FREDONIA 13.8 to 115.0 4 Main Bus SKAGIT Note that there are two Fredonia stations, one serves a gas turbine power plant and the second serves local load. The “red” Fredonia station is the load serving station. Although these stations are “red” (or less desirable for ESS integration) they may be worthy of further review and analysis. JU8426 – PSC Report for Puget Sound Energy ESS Locations © PSC 4010 Lake Washington Blvd NE Suite 300 Kirkland, WA 98033 Page 12 of 21 P: 425-822-8489 W: https://www.pscconsulting.com 3.2. Quantitative Results 3.2.1. Quantitative Results Table 3.3, 3.4, and 3.5 lists the results from the quantitative analysis. The gen/load limit is equivalent to the discharge/charge limit for the ESS at the listed station for TPL-001-4 P0, P1, and P6 conditions (for the most limiting element). Units for the limits are MW. Note that we omit the negative sign for load since the sign is implicit in the definition of load. Results shown in the tables indicate the ESS sizes for the different substations on an individual bases, meaning the potential size for a single ESS to be placed at any one of the locations listed. The results are not meant to indicate that the ESS sizes listed can be installed for all locations simultaneously. BPA 500 kV contingencies (such as the Raver-Paul 500 kV line loss) were noted, but not considered as limiting contingencies since it is known that these contingencies have remedial action schemes associated with them. BPA has historically planned its system for P1 outages and has not necessarily planned (and built) its system to perform for P6 outages (without operator action). A 2030 Light Spring case was examined to test performance under P0, P1, and P6 conditions to determine if there was any notable sensitivity to light spring conditions (in addition to the Heavy Summer and Heavy Winter cases). JU8426 - PSC Report for Puget Sound Energy ESS Locations © PSC 14 4010 Lake Washington Blvd NE Suite 300 Kirkland, WA 98033 P: 425-822-8489 W: https://www.pscconsulting.com Page 13 of 21 Table 3.3 P0 Quantitative Results Charging limits have a parenthetical ( ) used in order to clearly indicate that the number is a charging (i.e. load) value. The maximum ESS sized is determined by the maximum size that the ESS can operate for all cases. Therefore, the minimum value between the three seasonal cases determines the maximum ESS size for performance under P0 conditions. Quantitative Results - P0 Results in MW (Green shaded stations are low risk; yellow shaded stations are medium risk) Substation 2030 Heavy Summer 2030 Heavy Winter 2030 Light Spring Maximum ESS Size Generating Charging Generating Charging Generating Charging Generating Charging Alderton 725 (790) 872 (823) 886 (998) 725 (790) Berrydale 982 (248) 1077 (273) 1031 (569) 982 (248) Christopher 751 (419) 1031 (648) 842 (622) 751 (419) Frederickson 432 (316) 485 (440) 404 (466) 404 (316) Fredonia 510 (803) 679 (873) 538 (878) 510 (803) Lake Tradition 725 (534) 993 (701) 888 (837) 725 (534) March Point 664 (367) 834 (367) 701 (412) 664 (367) Midway 550 (263) 711 (333) 558 (368) 550 (263) Saint Clair 520 (546) 756 (732) 810 (854) 520 (546) Sammamish 409 (677) 517 (818) 546 (702) 409 (677) Talbot Hill 754 (768) 935 (916) 834 (896) 754 (768) Tono 755 (445) 567 (524) 548 (699) 548 (445) Bellingham 695 (578) 1028 (894) 809 (1072) 695 (578) Krain Corner 250 (222) 480 (351) 377 (308) 250 (222) O’Brien 681 (554) 807 (694) 672 (627) 672 (554) Portal Way 443 (565) 441 (772) 337 (740) 337 (565) S. Bremerton 426 (328) 471 (341) 457 (420) 426 (328) Sedro Woolley 779 (950) 935 (1134) 867 (995) 779 (950) Starwood 573 (335) 693 (341) 637 (578) 573 (335) White River 872 (802) 1029 (945) 955 (887) 872 (802) JU8426 – PSC Report for Puget Sound Energy ESS Locations © PSC 4010 Lake Washington Blvd NE Suite 300 Kirkland, WA 98033 Page 14 of 21 P: 425-822-8489 W: https://www.pscconsulting.com Table 3.4 P1 Quantitative Results Charging limits have a parenthetical ( ) used in order to clearly indicate that the number is a charging (i.e. load) value. The maximum ESS sized is determined by the maximum size that the ESS can operate for all cases. Therefore, the minimum value between the three seasonal cases determines the maximum ESS size for performance under P1 conditions. Quantitative Results – P1 Results in MW (Green shaded stations are low risk; yellow shaded stations are medium risk) Substation 2030 Heavy Summer 2030 Heavy Winter 2030 Light Spring Maximum ESS Size Generating Charging Generating Charging Generating Charging Generating Charging Alderton 96 (366) 510 (581) 529 (655) 96 (366) Berrydale 756 (167) 848 (181) 702 (437) 702 (167) Christopher 552 (217) 758 (362) 613 (386) 552 (217) Frederickson 135 (96) 308 (314) 266 (388) 135 (96) Fredonia 110 (532) 161 (619) 124 (585) 110 (532) Lake Tradition 518 (136) 811 (425) 664 (545) 518 (136) March Point 272 (214) 555 (189) 485 (271) 272 (189) Midway 432 (164) 530 (207) 446 (262) 432 (164) Saint Clair 45 (254) 239 (423) 311 (685) 45 (254) Sammamish 323 (99) 411 (370) 495 (425) 323 (99) Talbot Hill 552 (242) 741 (459) 688 (590) 552 (242) Tono 437 (85) 275 (374) 282 (543) 275 (85) Bellingham 322 (109) 545 (452) 384 (656) 322 (109) Krain Corner 136 (34) 250 (88) 188 (112) 136 (34) O’Brien 535 (258) 634 (276) 559 (401) 535 (258) Portal Way 105 (446) 392 (628) 284 (614) 105 (446) S. Bremerton 313 (89) 301 (27) 375 (185) 301 (27) Sedro Woolley 287 (589) 577 (715) 450 (700) 287 (589) Starwood 373 (181) 545 (250) 459 (299) 373 (181) White River 583 (379) 838 (434) 715 (592) 583 (379) JU8426 - PSC Report for Puget Sound Energy ESS Locations © PSC 2-- 4010 Lake Washington Blvd NE Suite 300 Kirkland, WA 98033 P: 425-822-8489 W: https://www.pscconsulting.com Page 15 of 21 Table 3.5 P6 Quantitative Results Charging limits have a parenthetical ( ) used in order to clearly indicate that the number is a charging (i.e. load) value. The maximum ESS sized is determined by the maximum size that the ESS can operate for all cases. Therefore, the minimum value between the three seasonal cases determines the maximum ESS size for performance under P6 conditions. Those limits with an asterisk (*) indicate that a pre-existing limit was ignored, and the first non-zero ATC transfer limit was recorded for the ESS charging and discharging contingency-based limit. Quantitative Results – P6 Results in MW (Green shaded stations are low risk; yellow shaded stations are medium risk) Substation 2030 Heavy Summer 2030 Heavy Winter 2030 Light Spring Maximum ESS Size Generating Charging Generating Charging Generating Charging Generating Charging Alderton 134* (76*) 448 (205) 324 (290) 134* (76*) Berrydale 515* (52*) 847 (90) 707 (336) 515* (52*) Christopher 484* (57*) 756 (337) 610 (386) 484* (57*) Frederickson 99* (86*) 275 (284) 222 (389) 99* (86*) Fredonia 9* (378) 101 (421) 69 (479) 9* (378) Lake Tradition 521* (44*) 805 (387) 664 (545) 521* (44*) March Point 9* (54) 201 (62) 172 (78) 9* (54) Midway 428* (56*) 512 (121) 444 (218) 428* (56*) Saint Clair 39* (412) 147 (528) 159 (633) 39* (412) Sammamish 323 (46*) 411 (370) 495 (445) 323 (46*) Talbot Hill 450* (48*) 622 (359) 833 (896) 450* (48*) Tono 592 (122*) 267 (339) 548 (698) 267 (122*) Bellingham 10* (108) 418 (67) 382 (657) 10* (67) Krain Corner 136* (34*) 178 (4*) 188 (112) 136* (4*) O’Brien 520* (54*) 225 (176*) 560 (521) 225 (54) Portal Way 11* (446) 185 (362) 298 (614) 11* (362) S. Bremerton 314 (89*) 79 (23*) 375 (185) 79 (23*) Sedro Woolley 48* (590) 519 (622) 447 (755) 48* (590) Starwood 370* (13*) 240 (107*) 460 (311) 240 (13*) White River 365* (13*) 382 (121*) 714 (750) 365* (13*) JU8426 – PSC Report for Puget Sound Energy ESS Locations © PSC 4010 Lake Washington Blvd NE Suite 300 Kirkland, WA 98033 Page 16 of 21 P: 425-822-8489 W: https://www.pscconsulting.com 4. Analysis A review of Table 3.2, Table 3.3, and Table 3.4, indicate to the user the following: A single ESS performs for both discharging (generator) and charging (load) depending upon the substation location o Between 248 MW – 802 MW under P0 conditions o Between 45 MW – 434 MW for P1 conditions o Between 9 MW – 122 MW for P6 conditions Summer ratings can be most limiting and generally (but not always) summer may be the defining season for limiting an ESS. o This is due to limits being thermally based and higher summer temperatures causing de- rating of thermally limited equipment. Pre-existing conditions exist that should be examined in greater detail if any of these ESS locations are considered for interconnection. Limitations exist for P6 summer operations o Note that for ESS limits indicated with an asterisk (*) in the tables indicate there pre- existing P6 issues may exist. Some P6 contingencies may, surprisingly, perform better than P1 contingencies o The reasons for this are complex but, in many cases, the P1 limiting element is removed from service by the P6 contingency and thus a higher limiting element is relevant. Table 4.1 shows the results for each substation on a contingency category bases, and also shows the maximum size for the ESS when generating or charging. Similarly, to before, the maximum size is the minimum value across the three contingency categories (i.e. P0, P1, and P6). Further, the table shows the Total Maximum size of the ESS. The Total Maximum size is the minimum value (absolute) between the generating and charging values and represents the maximum size of the ESS that allows for unconstrained use during varying seasonal load conditions, varying operating conditions, and varying contingencies. The Total Maximum size is the value used to show the potential ESS size that might be achieved for NRIS while limiting the risk of additional costly network upgrades (transmission line rebuilds / reconductoring, etc.) outside of those required for interconnection to the substation. The Operational Agreements determined with the developer could increase the Total Maximum size beyond the P6 charging limitations of the ESS listed in the table below. JU8426 - PSC Report for Puget Sound Energy ESS Locations © PSC 1-- 4010 Lake Washington Blvd NE Suite 300 Kirkland, WA 98033 P: 425-822-8489 W: https://www.pscconsulting.com Page 17 of 21 Table 4.1 Combined Quantitative Results Substation Substation Type P0 Results P1 Results P6 Results Maximum ESS Total Maximum Generating Charging Generating Charging Generating Charging Generating Charging Alderton Main & Aux 725 (790) 96 (366) 134* (76*) 96 (76*) 76* Berrydale Main & Aux 982 (248) 702 (167) 515* (52*) 515* (52*) 52* Christopher Main Bus 751 (419) 552 (217) 484* (57*) 484* (57*) 57* Frederickson Main Bus 404 (316) 135 (96) 99* (86*) 99* (86*) 86* Fredonia Main Bus 510 (803) 110 (532) 9* (378) 9* (378) 9* Lake Tradition Main Bus 725 (534) 518 (136) 521* (44*) 518 (44*) 44* March Point Main & Aux 664 (367) 272 (189) 9* (54) 9* (54) 9* Midway Main & Aux 550 (263) 432 (164) 428* (56*) 428* (56*) 56* Saint Clair Main & Aux 520 (546) 45 (254) 39* (412) 39* (254) 39* Sammamish Main & Aux 409 (677) 323 (99) 323 (46*) 323 (46*) 46* Talbot Hill Main & Aux 754 (768) 552 (242) 450* (48*) 450* (48*) 48* Tono Main & Aux 548 (445) 275 (85) 267 (122*) 267 (85) 85 Bellingham Brk & half 695 (578) 322 (109) 10* (67) 10* (67) 10* Krain Corner Main Bus 250 (222) 136 (34) 136* (4*) 136* (4*) 4* O’Brien Main & Aux 672 (554) 535 (258) 225 (54*) 225 (54*) 54* Portal Way Main & Aux 337 (565) 105 (446) 11* (362) 11* (362) 11* S. Bremerton Main & Aux 426 (328) 301 (27) 79 (23*) 79 (23*) 23* Sedro Woolley Main & Aux 779 (950) 287 (589) 48* (590) 48* (589) 48* Starwood Main Bus 573 (335) 373 (181) 240 (13*) 240 (13*) 13* White River Main & Aux 872 (802) 583 (379) 365* (13*) 365* (13) 13* Those limits with an asterisk (*) indicate that a pre-existing limit was ignored, and the first non-zero ATC transfer limit was recorded for the ESS charging and discharging contingency-based limit. As stated above, the Operational Agreements determined with the developer could increase the Total Maximum size beyond the P6 charging limitations of the ESS. JU8426 – PSC Report for Puget Sound Energy ESS Locations © PSC 4010 Lake Washington Blvd NE Suite 300 Kirkland, WA 98033 Page 18 of 21 P: 425-822-8489 W: https://www.pscconsulting.com Table 4.2 shows a summary of the results for this effort. The table provides the reader with a convenient listing of the Total Maximum ESS output and the location of the electrical point of interconnection studied, as well as substation type, and operating voltage. Table 4.2 Location Summary with Maximum ESS Results . Substation Substation Type Voltage (kV) Location Total Maximum ESS (MW) Latitude Longitude Alderton Main & Aux 115 47.15344 -122.2365 76 Berrydale Main & Aux 115 47.37803 -122.1311 52 Christopher Main Bus 115 47.33708 -122.2393 57 Frederickson Main Bus 115 47.08061 -122.3647 86 Fredonia Main Bus 115 48.45461 -122.4371 9 Lake Tradition Main Bus 115 47.53069 -122.0117 44 March Point Main & Aux 115 48.45714 -122.5625 9 Midway Main & Aux 115 47.40239 -122.2944 56 Saint Clair Main & Aux 115 47.03511 -122.7356 39 Sammamish Main & Aux 115 47.68558 -122.1499 46 Talbot Hill Main & Aux 115 47.46864 -122.191 48 Tono Main & Aux 115 46.75539 -122.8775 85 Bellingham Brk & half 115 48.75939 -122.4604 10 Krain Corner Main Bus 115 47.23511 -121.9855 4 O’Brien Main & Aux 115 47.40317 -122.2432 54 Portal Way Main & Aux 115 48.90361 -122.63 11 S. Bremerton Main & Aux 115 47.53764 -122.6914 23 Sedro Woolley Main & Aux 115 48.50458 -122.204 48 Starwood Main Bus 115 47.29039 -122.3623 13 White River Main & Aux 115 47.239 -122.2096 13 JU8426 - PSC Report for Puget Sound Energy ESS Locations © PSC 4-- 4010 Lake Washington Blvd NE Suite 300 Kirkland, WA 98033 P: 425-822-8489 W: https://www.pscconsulting.com Page 19 of 21 As discussed previously, the main bus substation configuration (without an aux bus) has questionable reliability and interconnecting at a main bus substation has the potential to result in the need for high network costs to rebuild the substation. The substations that are configured with just a main bus (with no aux bus) were removed from the results to create the final results table as shown in Table 4.3. The table provides the reader with a convenient listing of the Maximum ESS output and the location of the electrical point of interconnection studied, as well as substation type, and operating voltage. Table 4.3 Final Results Table Substation Substation Type Voltage (kV) Location Total Maximum ESS (MW) Latitude Longitude Alderton Main & Aux 115 47.15344 -122.2365 76 Berrydale Main & Aux 115 47.37803 -122.1311 52 March Point Main & Aux 115 48.45714 -122.5625 9 Midway Main & Aux 115 47.40239 -122.2944 56 Saint Clair Main & Aux 115 47.03511 -122.7356 39 Sammamish Main & Aux 115 47.68558 -122.1499 46 Talbot Hill Main & Aux 115 47.46864 -122.191 48 Tono Main & Aux 115 46.75539 -122.8775 85 Bellingham Brk & half 115 48.75939 -122.4604 10 O’Brien Main & Aux 115 47.40317 -122.2432 54 Portal Way Main & Aux 115 48.90361 -122.63 11 S. Bremerton Main & Aux 115 47.53764 -122.6914 23 Sedro Woolley Main & Aux 115 48.50458 -122.204 48 White River Main & Aux 115 47.239 -122.2096 13 JU8426 – PSC Report for Puget Sound Energy ESS Locations © PSC 4010 Lake Washington Blvd NE Suite 300 Kirkland, WA 98033 Page 20 of 21 P: 425-822-8489 W: https://www.pscconsulting.com Figure 4.1 gives an approximate location of the substations with low and medium risk for interconnection. The figure shows that there are many opportunities throughout the native PSE system for interconnecting an ESS. Figure 4.1 Location of Selected Stations JU8426 - PSC Report for Puget Sound Energy ESS Locations © PSC 4-- 4010 Lake Washington Blvd NE Suite 300 Kirkland, WA 98033 P: 425-822-8489 W: https://www.pscconsulting.com Page 21 of 21 5. Conclusions and Recommendations PSC believes that opportunities exist for Puget Sound Energy to install Energy Storage Systems in several stations without undue impact (or required network upgrades) to the surrounding electrical transmission system. We base this conclusion of performance under P6 outages during heavy summer and winter peak load conditions, as required for Network Resource Interconnection Service for use as a capacity resource on PSE’s transmission system. As previously stated, the results of this effort are to be used to help guide proponents to locations (with approximate capacities) that might offer success for interconnection of an ESS for NRIS with limited network upgrades. The formal LGIA process, as detailed under the Puget Sound Energy FERC Open Access Transmission Tariff (OATT), will define required system interconnection upgrades and any potential network upgrades as a result of the more detailed studies (power flow and transient), impacts of projects already in the interconnection que, affected neighbouring transmission providers, and short circuit analysis. 1213 06/19 pse.com PSE: Washington's oldest local energy utility Puget Sound Energy service area Electric service: All of Kitsap, Skagit, Thurston, and Whatcom counties; parts of Island, King (not Seattle), Kittitas, and Pierce (not Tacoma) counties. Natural gas service: Parts of King (not Enumclaw), Kittitas (not Ellensburg), Lewis, Pierce, Snohomish, and Thurston counties. Washington state’s oldest local energy company, Puget Sound Energy serves approximately 1.1 million electric customers and nearly 840,000 natural gas customers in 10 counties. A subsidiary of Puget Energy, PSE meets the energy needs of its customers, in part, through incremental, cost-effective energy effi ciency, procurement of sustainable energy resources, and far- sighted investment in the energy-delivery infrastructure. PSE employees are dedicated to providing great customer service and delivering energy that is safe, dependable and effi cient. For more information, visit pse.com. Combined electric and natural gas service Electric service Natural gas service CANADA YAKIMA COWLITZ MASON CLALLAM GRAYS HARBOR PACIFIC WAHKIAKUM JEFFERSON SAN JUAN CHELAN PORT ANGELES PORT TOWNSEND HOQUIAM ABERDEEN LONGVIEW YAKIMA WENATCHEE WHATCOM SKAGIT SNOHOMISH KITTITAS PIERCETHURSTON LEWIS KITSAP ISLAND KING OAK HARBOR ANACORTES MOUNT VERNON MARYSVILLE EVERETTLANGLEY EDMONDS MONROE INDEX DUVALL REDMOND BELLEVUE RENTON SEATTLE BAINBRIDGE ISLAND BREMERTON GIG HARBOR SHELTON OLYMPIA CENTRALIA CHEHALIS TACOMA PUYALLUP AUBURN KENT NORTH BEND BLACK DIAMOND ENUMCLAW CLE ELUM ELLENSBURG KITTITAS BELLINGHAM EXHIBIT I