This section describes (1) electricity grid functions, operations, and planning; (2) energy storage operational characteristics, technologies, and deployment; and (3) the electricity regulatory framework. The electricity grid involves four distinct functions: generation, electricity transmission, electricity distribution, and grid operations (see fig. 1). Electricity is generated at power plants by burning fossil fuels; through nuclear fission; or by harnessing renewable sources such as wind, solar, geothermal, or hydropower. Once electricity is generated, it is sent through the electricity grid, which consists of high-voltage, high-capacity transmission systems, to areas where it is transformed to a lower voltage and sent through the local distribution system for use by residential and other customers. Throughout this process, a grid operator, such as a local utility, must constantly balance the generation and consumption of electricity. To do so, grid operators monitor electricity consumption from a centralized location using information systems, and send minute-by- minute signals to power plants to adjust their output to match changes in the demand for electricity. As we previously reported, continuously balancing the generation and consumption of electricity can be challenging for grid operators because customers may use sharply different amounts of electricity over the course of a day and throughout the year. For example, in many areas, customer demand for electricity rises throughout the day and reaches its highest point—or peak demand—in late afternoon or early evening. Throughout the day, grid operators direct power plants to adjust their output to match changes in demand for electricity. Grid operators typically first use electricity produced by baseload power plants that are the least expensive to operate, then progressively increase the supply of electricity generated by power plants that are more expensive to operate as needed to match increases in electricity demand. As a result, providing electricity to meet peak demand is generally more expensive than during other parts of the day, because to do so, grid operators use power plants that are more expensive to operate. Peak periods are generally short and account for only a few hours per day and, overall, a small percentage of the hours during a year, but can significantly contribute to the overall costs of serving customers. Grid operators conduct planning to assess the adequacy of existing grid infrastructure, identify capacity needs, and evaluate the cost and effectiveness of potential solutions to address these needs. As we previously reported, to ensure that grid infrastructure has sufficient capacity to meet future peak demand, grid operators typically develop forecasts of future electricity demand based on historical information about customer electricity use combined with assumptions about how customer demand will change in the future based on population growth, economic conditions, and other factors. Utilities deal with uncertainty partly by producing a range of forecasts based on demographic and economic factors, and by maintaining excess generating capacity, known as reserves. Models help utilities choose the least-cost combination of generating resources to meet demand. If demand forecasts are too high or low, a utility could end up with more or less generating capacity than it needs to serve its customers reliably, or it could end up with a mix of generating capacity that is not cost effective. These outcomes can affect electricity rates as well as the utility’s financial situation. To meet demand for electricity, utilities can construct new plants, upgrade existing plants, purchase power from others, build new transmission and distribution lines, and provide incentives to customers to reduce and shift their demand for electricity through energy efficiency or demand-response programs. In addition, utilities may use time-based pricing—prices that vary throughout the day and year to reflect the costs of serving consumers—to encourage consumers to lower their electricity use at times of high prices or shift their use to times of the day when prices are lower, which can lower their electricity bills. Energy storage includes a number of different technologies that have the ability to store energy for use at a later time. Energy storage systems can be designed with a range of technologies, such as pumped hydro, compressed air, batteries, and flywheels, according to DOE. Each technology has its own performance characteristics that make it more suitable for certain grid services than for others. Specifically, compressed air and pumped hydro are capable of discharge times—the length of time that a storage device can discharge electricity—in tens of hours and have large capacities that can reach 1,000 megawatts (MW). According to DOE and CRS, storage projects involving these types of technologies generally have unique siting requirements, including specific geographical features, or long construction times. In contrast, other storage technologies such as batteries and flywheels are smaller in terms of capacity and have shorter discharge times, ranging from a few seconds to several hours, and these technologies can generally be built without specific geographical features at the site. These energy storage systems are comprised of storage technologies and other system components such as inverters, wiring, temperature regulation, and other equipment. According to DOE’s Global Energy Storage Database, about 24 gigawatts (GW) of grid-connected energy storage were in operation in the United States and about 2 GW of storage capacity was under development as of March 20, 2018. Pumped hydro comprises about 93 percent of this storage capacity in operation. Many of the operational pumped hydro systems in the United States were commissioned during the 1960s through the 1980s; the most recent became operational in 2012. See figure 2 for information about the proportion of energy storage capacity in operation or under development in the United States that comes from certain types of technology. While pumped hydro comprises the majority of energy storage in operation, batteries are driving the recent growth in energy storage. Since 2013, the capacity of utility-scale (1 MW or greater) battery deployments grew by 283 percent (from about 185 MW to about 709 MW), though such utility-scale batteries comprised about 0.07 percent of utility-scale generating capacity on the U.S. electric grid, according to data from the Energy Information Administration. See figure 3 for information on the capacity of utility-scale battery installations each year from 2003 through 2017. Figure 4 shows how grid-connected storage of all technology types was distributed nationwide as of March 20, 2018, according to DOE’s Global Energy Storage Database. Responsibility for regulating the electricity industry is divided between the states and the federal government. Most electricity customers are served by electric utilities on the retail level that are regulated by the states, generally through state public utility commissions or equivalent organizations. As the primary regulator of electricity on the retail level, state public utility commissions have a variety of responsibilities, such as approving utility investments in generation and distribution assets, the rates retail customers pay, and how those rates are set. Before electricity is sold to retail customers, it may be bought, sold, and traded in wholesale electricity markets that the federal government oversees through FERC. FERC is responsible for overseeing regional transmission organizations’ (RTO) development and operation of markets to ensure that wholesale electric rates are “just and reasonable” and not “unduly discriminatory or preferential.” To do so, FERC reviews and approves RTO market rules and monitors the competitiveness of RTO markets. Figure 5 indicates the location of major RTOs that have developed in certain regions of the United States. RTOs serve as grid operators by managing regional networks of electric transmission lines and also operate wholesale electricity markets to buy and sell services needed to maintain a reliable grid. These markets include capacity markets—auctions through which owners of power plants can be compensated for agreeing to make their plants available to provide electricity at a specified time in the future—designed to incentivize the building and retention of enough generation and other resources to meet future power demands; energy markets for scheduling which power plants will generate electricity throughout the day to maintain the balance of electricity generation and consumption, and at what prices; and ancillary services markets, which are designed to maintain electric reliability and ensure that supply and demand remain in balance from moment to moment so that grid operators can deliver electricity within technical standards, such as at the right voltage and frequency. RTOs are responsible for developing and implementing market rules, approved by FERC, that provide the framework for the design and operation of wholesale electricity markets. RTO market operations encompass multiple services that are needed to provide reliable and economically efficient electric service to customers. Each of these services has its own parameters and pricing. The RTOs use markets to determine the providers and prices for many of these services. In regions of the country without RTOs, electric utilities generally serve in the role of grid operator. In these regions, the local utility often integrates the delivery of electricity services—energy to maintain the balance of electricity generation and consumption, capacity to meet demand, and a range of ancillary services. Utilities in these regions may build and operate power plants to provide electricity to serve their retail customers. These utilities may also buy electricity from other power plant owners. Energy storage can be used in various ways to enhance the reliability, resilience, and efficiency of grid operations, according to studies we reviewed and stakeholders we interviewed. Storage can be deployed throughout the electricity system and act as a generation, transmission, distribution, or customer-sited asset to provide various services, address operational challenges and needs, and potentially reduce costs. For example, storage can help grid operators address supply disruptions, relieve transmission congestion during periods of high demand, defer the need for transmission or distribution system upgrades, and provide backup power during a power outage. Figure 6 illustrates examples of potential applications across the electricity grid. Energy storage can support the reliability of grid operations by helping grid operators respond to fluctuations in electricity supply resulting from the variability of renewable energy resources, such as solar or wind, or disruptions to the grid, such as the loss of a transmission line or a generating unit. Specifically, according to some studies we reviewed, the fast-ramping nature of some storage technologies that can change generation output quickly—within a few seconds or minutes—makes them suitable for addressing short-term changes in variable energy generation resources (referred to as variable resources) such as when the sun sets and output from solar resources quickly declines. Moreover, storage can provide ancillary services needed to maintain system reliability and support the transmission of electricity. Specifically, according to some studies we reviewed, storage can provide frequency regulation services—which entail moment-to-moment reconciliation of the difference between supply and demand—to maintain the stability of the system. The services that storage provides can be performed by traditional assets but because certain storage technologies are fast- ramping they can be better-suited to provide certain services, according to several studies we reviewed and stakeholders we interviewed. Systems with a large portion of generating capacity from variable resources can face reliability challenges because the intermittent nature of these sources can cause fluctuations in voltage and frequency, according to some studies we reviewed. Grid operators are adopting storage to support increasing use of renewable energy and address the associated challenges. For example, in 2017, San Diego Gas & Electric deployed a 30 MW energy storage facility at its Escondido substation to help improve regional reliability and support greater amounts of renewable energy in the region’s energy supply (see fig. 7). According to San Diego Gas & Electric, the Escondido storage facility is helping to enhance grid reliability and increase the use of renewable energy; the facility is capable of the equivalent of serving 20,000 customers over a period of 4 hours. Similarly, in 2017, according to Tucson Electric Power documents, the utility installed two 10 MW battery storage projects to support its ability to achieve long-term renewable energy goals without compromising the reliability of service. According to representatives from the utility, the projects provide frequency control and voltage support and the deployment shortened the reaction time to system disruptions and supported the utility’s compliance with reliability standards in its role as balancing authority. Storage can also provide services that support resilience by helping the grid adapt to changing conditions and potentially disruptive events and, if a disruptive event occurs, to rapidly recover, according to several studies we reviewed and stakeholders we interviewed. Specifically, in the event of an outage during which power sources or power lines become unavailable, storage can respond quickly to provide backup power or black start services—the provision of the power necessary to restore a generation plant when power from the grid is unavailable during a major outage. In addition, storage can also support microgrids—systems that can connect and disconnect from the grid depending on operating conditions—that could maintain power for a small area independent of the grid. For example, in 2015 a Vermont utility installed a 4 MW energy storage system in conjunction with a 2.5 MW solar project at a school that serves as an emergency shelter. In case of grid failure or an extended emergency, the facility can separate from the rest of the grid and operate independently. In addition, in 2016 in Massachusetts, the Sterling Municipal Light Department installed a storage system that can isolate from the main grid in the event of a power outage and provide emergency backup power to the Sterling police station and dispatch center, a facility providing first responder services. In the event of an outage, the 2 MW storage system could provide the police station with up to 12 days of power, according to the utility. Storage also has the potential to improve efficiency of grid operations and help reduce operating costs, according to studies we reviewed and stakeholders we spoke with. For example, storage has the potential to reduce costs by capturing energy generated during low-cost periods to be used to meet demand later during more expensive periods, according to studies we reviewed. Specifically, energy time-shift, also referred to as arbitrage, involves utilities purchasing inexpensive electric energy, available during periods when prices or system marginal costs are low, to charge the storage system so that the stored energy can be used or sold at a later time when the price or costs are high. In addition, storage can help make the capacity of variable resources more consistent by storing electricity during periods of high generation, such as a sunny afternoon, and releasing it later during periods of high demand, such as the early evening. Moreover, storage can provide similar energy time-shift by storing excess energy production from renewable sources, which could otherwise be curtailed. Storage also has the potential to reduce costs by avoiding or delaying investments in infrastructure. Specifically, storage may be used to reduce the capacity demands on existing generation, transmission, and distribution infrastructure. As a result, according to many studies and stakeholders we interviewed, utilities may be able to avoid or delay investments in generation, transmission, and distribution infrastructure that would otherwise be necessary to maintain adequate supply. For example, in 2017, a utility that serves customers in Massachusetts announced plans to install a 6 MW energy storage system with an 8-hour duration alongside a new diesel generator on Nantucket Island to provide backup power and postpone the need to construct a costly submarine transmission cable to bring electricity from the mainland to meet anticipated growth in electricity demand. In some cases, an investment in a storage system could be a more cost-effective way to manage peak demand, and in such cases, utilities could reduce the need for operation of peaking resources or investment in new peaking resources, such as a natural gas plant. Additionally, according to many studies we reviewed and stakeholders we interviewed, storage can help customers reduce demand charges. Demand charges are fees included on electricity bills in many parts of the country to cover the cost of ensuring that sufficient generation and transmission resources are available to serve customers during periods of peak demand. Energy storage provides an opportunity for potential savings by helping a customer to manage their peak demand. Using storage can also allow some utilities to avoid charges that they might incur when purchasing wholesale electricity to serve their customers during a system’s peak demand; this could allow them to pass savings on to their customers in the form of lower rates. For example, although the Sterling, Massachusetts, Municipal Light Department installed its storage system to provide emergency backup power, the primary benefits of the project since its installation have resulted from using it to reduce peak demand which has reduced the utility’s transmission charges, and, in turn, has allowed it to reduce rates paid by its customers, according to utility representatives. Studies we reviewed and stakeholders we interviewed identified a variety of factors that affect energy storage deployment. These factors include industry and technology readiness, safety concerns and stringency of siting requirements, increasing use of renewable resources, the cost- competitiveness of storage and challenges with quantifying the value of storage, and the regulatory environment. Grid operators and utilities have limited experience with storage and face technical challenges integrating storage into existing systems, according to studies we reviewed and stakeholders we spoke with. For example, according to some studies and stakeholders, grid operators may not have experience planning for the integration and operation of storage and they may not consider it as an option. The models that grid operators typically use to help make decisions about investments in generation, transmission and distribution infrastructure are based on traditional resources with better-understood capabilities. Moreover, storage can be more challenging to integrate than other resources, such as solar, because it changes its function in the system from charging—consuming electricity— to discharging—generating electricity, according to some stakeholders. Because storage must provide power when called upon but also must be recharged from another resource at a later time, tools that planners rely on must keep an accurate accounting of the amount of energy stored and available to supply power to meet demand. According to one stakeholder, installation of storage requires grid operators to develop operating requirements and identify control and mitigation strategies for proper coordination with larger grid operations. In addition, existing utility systems may not be designed to incorporate storage and may require customization to integrate storage, according to several stakeholders. Industry and technical challenges affecting deployment of storage include uncertainty about the performance of certain storage technologies over time and in various operating conditions. Energy storage systems generally are expected to last for a decade or more, but the actual degradation of battery storage under various conditions is still largely unknown, according to some studies we reviewed and stakeholders we spoke with. The electric utility industry has historically been slow to adopt new technologies and, unless new storage technologies prove highly reliable, utilities may be slow to deploy these assets, according to several studies we reviewed and stakeholders we spoke with. Although the adoption of storage has been increasing, safety codes and standards for storage are still under development, and questions have been raised about safety risks and how to mitigate those risks, according to studies we reviewed and stakeholders we interviewed. Efforts are under way to ensure that safety codes and standards address energy storage systems, but these types of standards tend to lag behind the development of storage technologies, according to some studies and stakeholders. Until existing codes and standards are updated, or new ones are developed and adopted, entities seeking to deploy energy storage or needing to verify a storage system’s safety may face challenges with applying existing codes and standards, according to some studies we reviewed. In addition, concerns about the operational safety of large storage systems as a fire hazard can be a barrier to their deployment in urban areas or in proximity to other grid resources such as substations, and local entities such as fire departments may not allow the deployment of storage on certain sites. Moreover, local jurisdictions and emergency responders, along with storage system installers, insurers, and others may not have a complete understanding of the hazards associated with storage and best approaches to addressing these hazards, such as the appropriate fire protection measures, according to some studies and stakeholders. In addition, local entities’ review of energy storage systems, for example, can add additional time to the permitting process, given that these entities may not be familiar with storage systems and potential safety concerns, according to some studies. On the other hand, in some locations siting requirements may be less stringent for some types of energy storage projects than for other resources such as a large power plant that must comply with more stringent environmental requirements, according to some studies and stakeholders. In some cases, according to some studies, the permitting process may be simpler for storage projects and construction timelines considerably shortened for a variety of reasons, including that energy storage systems do not need to complete modifications to comply with air quality standards because they do not produce emissions. In addition, certain storage projects require a much smaller footprint than conventional power plants, whereas building new power plants or transmission lines can involve large land requirements. As mentioned previously, storage can help address reliability issues associated with the variability of renewable energy generation resources making them attractive to grid operators. Consequently, the increased use of solar and other renewable energy resources has in turn encouraged the installation of storage, according to some studies we reviewed and stakeholders we interviewed. According to the Energy Information Administration, utility-scale solar installations grew at an average rate of 72 percent per year between 2010 and 2016, faster than any other generating technologies. Moreover, increasing use of these resources is expected to continue, which could drive the adoption of storage deployment in the future, according to some studies we reviewed and stakeholders we spoke with. The Energy Information Administration estimated in January 2018 that nearly half of the approximately 25 GW of new utility-scale electric generating capacity added to the grid in 2017 used renewable technologies, particularly wind and solar. Moreover, according to some studies and stakeholders, states with aggressive renewable portfolio standards—such as Hawaii, which aims to achieve 100 percent renewable sources by 2045—will need to adopt storage resources to meet those goals. In addition, California’s renewables portfolio standard includes targets of 33 percent by 2020 and 50 percent by 2030. According to some stakeholders and documents we reviewed, California is experiencing excess solar and wind generation and curtailment at certain times of the day and year and, as the state moves toward a target of 50 percent renewables, storage could help address these challenges. According to some stakeholders we spoke with, long-duration technologies will support greater integration of renewable energy on the grid. As mentioned previously, pumped hydro and compressed air energy storage can provide long duration storage, and other technologies, including flow and lithium ion batteries, have the potential to provide for long duration storage, according to some studies we reviewed and stakeholders we spoke with. Grid operators’ decisions to invest in energy storage must consider both costs and benefits. While the cost of some technologies has fallen in recent years, the cost of storage systems—including all the system components, installation, and integration costs—is still high when compared to more traditional resources available to electric utilities, according to many studies we reviewed and stakeholders we spoke with. On the other hand, the adoption of storage for certain purposes, such as supporting increased use of renewable resources or providing backup power, includes potential benefits such as reducing greenhouse gas and other harmful emissions, or enhancing the resilience of the grid. While the cost of lithium-ion batteries has declined in recent years, the storage device is one component of a storage system, and estimates of the device’s share of the total cost of an energy storage system range from about 25 percent to 50 percent of the total costs, according to studies we reviewed. According to some stakeholders, the cost of the system components and other costs to integrate storage with the grid can be substantial and are not declining as quickly as the cost of storage devices. In addition to the cost of the storage device, other system component costs include power conversion electronics, software, and monitoring and control systems, among others, that are essential to maintain the health and safety of the entire system, according to some studies. Moreover, valuing investments in energy storage must consider both the cost and benefits, but assessing the potential benefits and costs of storage can prove challenging, according to several studies we reviewed and stakeholders we spoke with. These challenges identified in these studies and by these stakeholders include the following: Quantifying benefits. Benefits can be difficult to quantify, as they depend on the application, location, and ability to capture multiple benefits. Specifically, the compensation for services that storage can provide reflects local market conditions, and these vary across regions. In addition, the value of certain storage applications can be harder to quantify than for others. For example, if a utility is considering deployment of storage in order to defer an investment in a transmission and distribution infrastructure upgrade, then determining the value of the storage asset involves analyzing the avoided cost of that investment, which is quantifiable. However, it is more difficult to quantify the value of less tangible benefits of storage, such as improvements to operational flexibility and grid resilience, which are not monetized and therefore are difficult to quantify. Life expectancy. For certain storage technologies, much is still unknown about their useful life, which depends on the number of charge and discharge cycles, among other things. Reliable estimates of the expected life of an asset are necessary for accurately estimating lifecycle costs and benefits. Given the fact that battery technologies are evolving, the lack of data makes it more challenging for utilities to estimate expected costs and benefits to justify their investment expense. Limited information on cost. Sufficient information on the cost of storage systems is not readily available, limiting utilities’ ability to include storage in modeling and investment decisions, according to some stakeholders. Energy storage price and cost data vary among sources because of aggregation to protect proprietary interests, which unit is chosen to present price and cost data, and limited information about how projects operate. Specifically, information on the operational conditions, specifications, and performance of energy storage systems is difficult to obtain. In addition, according to some studies we reviewed, uncertainty exists about the future cost outlook and pace of technological maturity. The regulatory environment can pose barriers to the deployment of energy storage. Specifically, market rules and regulations do not always clearly address whether entities may own and operate storage assets and how, if at all, the cost of investments in storage assets can be recovered, according to several studies we reviewed and stakeholders we interviewed. In addition, each RTO establishes the rules in a different way, and their implementation of reforms to accommodate storage varies, according to studies and documents we reviewed and stakeholders we spoke with. According to a FERC document, under current market rules, resource bidding parameters—the physical and operational constraints that a resource identifies when submitting offers to sell services in electricity markets—vary greatly among the RTOs. Moreover, state regulators and RTOs may be slow to change their policies and rules to address energy storage, and delays in such changes hinder deployment, according to some studies we reviewed. In RTO regions, some states do not allow utilities to own generation assets, and when storage is classified as a generation asset, an electric utility can be prevented from owning storage. Moreover, when market rules do not clearly define what type of asset they consider storage to be, this can make it difficult to determine whether storage can participate in the market or to receive compensation, making storage in that market financially unviable, according to some studies and stakeholders. One RTO, the California Independent System Operator (ISO), has established participation models to accommodate resources, such as storage, that are operationally unique. In addition, uncertainty exists about the ability of storage project owners to recover costs of storage used for multiple applications, according to documents and studies we reviewed and stakeholders we spoke with. Moreover, the variation in rules and regulations across regions makes it difficult for energy storage project developers to navigate different potential markets because each has its own characteristics, stakeholders, regulations, and market designs, according to some stakeholders. Storage project developers must keep abreast of the activities of multiple regulatory agencies and the variation by region makes potential revenue streams difficult to predict. In addition, according to one study we reviewed, the inconsistency of rules adds a level of complexity for project developers that want to deploy storage resources across multiple markets because they must conduct separate analyses to determine the regulatory outlook, market requirements, and profit potential in each region. Federal and state policymakers have used a variety of policies and other efforts to encourage the deployment of storage and address market barriers. For example, DOE has undertaken various efforts in response to several challenges to the deployment of storage, but funding to continue these efforts is uncertain. In addition, FERC has taken steps to address market barriers to storage deployment in wholesale markets but the final impact of these steps depends on implementation by RTOs. Moreover, the Department of the Treasury and the Internal Revenue Service (IRS) are considering changes that could clarify the eligibility of energy storage for a tax credit. Lastly, state policies and other efforts aim to encourage the deployment of energy storage or to address market barriers; these include establishing mandates and targets for storage adoption, revising interconnection rules and planning requirements, and offering financial incentives and funding. According to documents we reviewed, DOE has undertaken various efforts in response to the challenges to deploying energy storage identified in a 2013 report, including challenges concerning the safety and reliability of such storage, its acceptance by industry, the regulatory environment, and cost-competitiveness. Efforts to Address Safety and Reliability Challenges. In 2017, DOE developed, through its Pacific Northwest National Laboratory (PNNL) and Sandia National Laboratories, the DOE safety roadmap, which established a goal to foster confidence in the safety and reliability of energy storage systems. The roadmap built on previous efforts including an Energy Storage Safety Forum that Sandia held in 2017 for stakeholders to share information and identify future needs. The objectives of the roadmap include research and development, codes and standards, and collaborative resources with a focus on electrical safety, fire and smoke hazard detection and mitigation, health and environmental hazards, natural and man-made disasters, ventilation and thermal management, and system controls. The roadmap aims to cover the development of energy storage systems through their decommissioning or refurbishment and includes design, installation, commissioning, operation and maintenance, repair, decommissioning, and reuse. DOE has also supported efforts to develop and deploy energy storage safety codes with industry groups, according to documents we reviewed. For example, DOE established working groups focused on safety and standards, including the Energy Storage Systems Safety Working Group, which aims to facilitate the timely development and deployment of safe energy storage systems by implementing the DOE safety roadmap through collaboration with stakeholders. In addition, as part of these efforts, a DOE working group on codes, standards, and regulations monitors the development of standards and model codes and provides input to those activities. Additionally, DOE coordinates with industry-led and international code-setting agencies such as the National Fire Protection Association and the International Code Council, as well as companies that conduct testing. In addition, PNNL published several resources including an inventory of codes and standards, an overview of the development and deployment of codes and standards, and a compliance guide. The compliance guide prepared by PNNL and Sandia, which includes safety codes and standards, aims to facilitate the timely deployment of storage systems and assist with documenting compliance with current safety- related codes and standards and verifying compliance with codes and standards. Efforts to Support Industry Acceptance. DOE has provided technical assistance and funded demonstration projects to help utilities and other entities install, procure, and evaluate storage projects, according to documents we reviewed. For example, DOE provided funding and technical support in the deployment of a storage project at an emergency shelter in Vermont that can separate from the rest of the grid and operate independently in case of an emergency. DOE also supported the development of documentation and tools to assist utilities in the design, deployment, and operation of energy storage systems including valuation models, procurement guidelines, commissioning procedures, and data acquisition guidelines. In addition, Sandia published guidance to provide information for municipalities on the elements that should be included in a solicitation for procurement and installation of an energy storage project and a handbook to provide information and tools to guide investors’ evaluations of energy storage opportunities. DOE has a proposal under way for a study to gather pricing information for energy storage technologies that will be used as part of future updates to the handbook. DOE also held a financial summit in June 2017 to provide information to the financial community on solicitations and contracts. In addition, to evaluate storage projects, DOE and the Washington Department of Commerce established a memorandum of understanding to have PNNL characterize and analyze the technical and economic attributes of storage projects. DOE also supports new deployments through funding, including the Grid Modernization Laboratory Consortium awards aimed at integrating conventional and renewable sources with energy storage. Provide Technical Assistance to Regulators. According to documents we reviewed, DOE has hosted workshops and provided technical assistance for several state public utility commissions and other entities aimed at providing them with information on storage technology development, project procurement, and valuation. In addition, in 2012 Sandia developed guidance for state regulatory authorities and planning personnel to provide information about opportunities for energy storage to play a greater role in the electricity grid. Research and Development to Improve Cost-Competitiveness. DOE’s Energy Storage Program’s research and development activities focus on improving materials and system factors that affect the cost, efficiency, and capacity of certain energy storage technologies, including flow batteries. DOE’s fiscal year 2018 budget request includes a performance goal to improve the cost- benefit ratio of storage to compete with current peak generation resources and, by 2020, increase to 5 percent the commercial use of grid-scale storage to buffer renewables. A DOE advisory committee in 2016 conducted an assessment of DOE’s energy storage-related research, development, and deployment programs that produced 15 recommendations. The recommendations included, among others, improving the visibility of DOE’s efforts; addressing the need for storage models and studies of market impediments; and providing additional funding and resources for energy storage research, development, and deployment programs. While DOE has undertaken a range of efforts over the past several years to address challenges to deployment, future funding of these efforts is uncertain. In 2017, DOE allocated $31 million to work on energy storage within its Office of Electricity Delivery and Energy Reliability. DOE’s fiscal year 2018 budget request proposed reducing this funding by about 74 percent, to $8 million, and proposed eliminating, among other efforts, work related to engagements with states, utilities, and storage providers for conducting tests and trials; engagements with state and federal regulatory officials on efforts to understand regional market barriers to deployment; validation of system performance and analysis of regional use cases; support to states and regional entities for the procurement, commissioning, and analysis of deployed systems; the development of enhanced tools and data for sharing with industry for the development and use of grid-scale batteries; and participation in both industry-led and international codes and standards development. Because fiscal year funding through March was provided under continuing resolutions, energy storage funding remained on par with fiscal year 2017 levels for the first half of the fiscal year, and the Consolidated Appropriations Act, 2018, increased funding for energy storage to $41 million. However, DOE’s fiscal year 2019 budget request again proposes reducing the funding for energy storage work to $8 million. According to DOE’s fiscal year 2019 budget request, DOE plans to focus on accelerating the development of new materials and technologies that can lead to improvements in the cost and performance of utility-scale energy storage systems and accelerate the adoption of energy storage systems into the grid infrastructure. FERC has taken several steps to address market barriers to energy storage deployment, but the impact of these efforts will depend on implementation by RTOs. In March 2018, FERC published a final rule that aims to address barriers to integrating storage into organized wholesale markets. The rule requires that RTOs establish participation models consisting of market rules that recognize the physical and operational characteristics of electric storage resources to facilitate their participation in the RTO markets. In prior years, FERC issued several orders that also aimed to address barriers to storage participation in organized wholesale electric markets. For example, FERC Order 792—issued in 2013—revised the definition of a small generating facility in the pro forma Small Generator Interconnection Agreement—which establishes the terms and conditions for interconnection of resources no larger than 20 MW—to specifically include energy storage devices. In addition, FERC Order 755—issued in 2011—required RTOs to compensate frequency regulation resources in a manner that acknowledges the performance of faster-ramping resources, such as batteries and flywheels. Additionally, in May 2018, FERC published a final rule that revised the definition of a generating facility in the pro forma Large Generator Interconnection Procedures and pro forma Large Generator Interconnection Agreement—which establishes the terms and conditions for interconnection of resources larger than 20 MW—to explicitly include electric storage resources. FERC also published guidance in February 2017 on the ability of electric storage resources to provide transmission or grid support services at cost-based rates, while providing other electric storage services, such as power sales, at market-based rates. According to some studies we reviewed and stakeholders we spoke with, FERC orders have helped alleviate some of the barriers to storage participation in wholesale markets, but the impact of these orders depends on RTO implementation. Moreover, RTO implementation of FERC’s requirement to establish participation models to accommodate storage may not occur until the end of 2019 or later. Figure 8 shows the timeline of key FERC efforts that aim to address market barriers to the deployment of storage and time frames for implementation from November 2016 through 2019. According to FERC’s final rule, RTO implementation of the requirement to establish participation models could take 21 months from the publication of the final rule. RTOs will need to develop the participation models, obtain input through their stakeholder review processes, and may need to update modeling and dispatch software. Treasury and the IRS are considering changes that could clarify the eligibility of energy storage for a business tax credit under section 48 of the Internal Revenue Code, according to IRS documents. Currently, customers who install storage systems may be eligible for this tax credit when they use the storage system to store energy from renewable energy systems more than 75 percent of the time; however, at this time there is no federal tax incentive for stand-alone storage. Since 2011, the IRS has issued some written determinations that the storage portion of a renewable energy system would be eligible for the credit. However, only the specific taxpayer addressed by a determination can rely on it as precedent. In October 2015, Treasury and IRS solicited comments from the public on how to define certain types of property that qualify for this tax credit, including whether property such as storage devices may also be considered energy property. According to IRS documents, comments filed in response requested revisions to the tax credit that include, among other things, providing a technology-neutral definition of energy storage property, providing a specific list of types of energy storage property that qualify for the credit, and determining that storage is eligible for the credit on a stand-alone basis. According to some stakeholders we interviewed, the requirement for storage to be paired with renewable energy to obtain the tax credit is limiting because there are other potential applications and benefits storage can provide to the grid that are unrelated to renewable energy integration. Additionally, one stakeholder we spoke with said that regions with relatively small renewable energy resource capacities are unable to receive federal support for energy storage, even though it may benefit their grid. Through interviews with stakeholders and our review of documents, we identified examples of state policies and other efforts that have encouraged the deployment of energy storage or aim to address market barriers. Appendix I includes a detailed list of state policies and other efforts encouraging deployment of energy storage we identified. In summary, these policies and other efforts include: Mandates and Targets. Several states have established or proposed mandates or targets that require or encourage electric utilities to procure a specific amount of energy storage capacity. States have taken a range of approaches to implementing these mandates and targets. For example: The California Public Utilities Commission requires investor-owned utilities to collectively procure 1.3 GW of energy storage by 2020. Oregon is in the process of implementing a requirement for certain utilities serving more than 25,000 retail customers to procure energy storage systems with at least 5 megawatt hours of energy storage capacity by January 1, 2020. The Massachusetts Department of Energy Resources adopted a 200 megawatt-hour energy storage target for electric distribution companies to collectively meet by January 2020. In November 2017, New York State enacted legislation requiring the state public service commission to adopt an energy storage target. In January 2018, the Governor of New York announced an energy storage goal of 1.5 GW by 2025. A number of other states are also considering the adoption of targets for storage capacity in the state. Mandates and targets that require or encourage utilities to procure energy storage can help create certainty in the market for energy storage by assuring that there is a demand for storage, according to some stakeholders we interviewed. Additionally, according to one document we reviewed, mandates and targets may impact deployment by encouraging the development of model regulatory frameworks that serve as examples to other states. States with storage mandates and targets may also serve as case studies to demonstrate the impact of energy storage deployment on a large scale and provide the industry with operational experience, examples of how to best integrate storage, and opportunities to evaluate storage. Changes to Interconnection Rules. Some states have changed or are considering changes to interconnection rules to account for energy storage. States are taking a number of approaches to revising interconnection rules. For example: In 2015, Hawaii’s Public Utility Commission made changes to interconnection standards and energy policies to provide for the interconnection of energy storage to the grid. The Arizona Corporation Commission is developing statewide interconnection rules for distributed generation. Draft rules include interconnection requirements for energy storage systems and Commission officials told us that stakeholders are debating the scope and nature of those requirements. Planning. Some states allow for the inclusion of energy storage in integrated resource and transmission planning processes; grid operators and utilities undertake these planning processes to ensure that the grid infrastructure has sufficient capacity and grid operators are able to meet future power demands. For example: The New Mexico Public Utility Commission’s integrated resource planning rules require investor-owned utilities to evaluate all feasible energy resources as part of their resource planning process. When the Commission’s integrated resource planning rules were originally implemented, energy storage was not commercially feasible; however, the state commission recently amended these rules to include energy storage as a resource in planning. The Oregon Public Utility Commission directed Portland General Electric to address energy storage in its future integrated resource plans. Washington’s Utilities and Transportation Commission directs utilities to demonstrate that, when considering a new resource acquisition, their analysis should include an evaluation of the costs and benefits of a storage alternative. The Commission also directs utilities procuring resources to issue requests for proposals that are technology neutral, allowing energy storage to bid. Several states are also incorporating storage into broader energy planning efforts, including conducting research to identify the benefits of and opportunities for storage in the state. For example: North Carolina passed legislation directing the North Carolina Policy Collaboratory, at the University of North Carolina, to conduct a study on energy storage to address how and if storage may benefit consumers, the feasibility of storage in the state, and policy recommendations. Massachusetts has also undertaken a number of efforts including launching the Energy Storage Initiative, an initiative administered by the Massachusetts Department of Energy Resources and the Massachusetts Clean Energy Center to facilitate the deployment of storage and provide environmental and ratepayer benefits. As part of this initiative the 2016 State of Charge report was released and, among other things, identified barriers to energy storage adoption in the state and made recommendations to increase deployment of storage, setting a target of 600 MW of energy storage capacity by 2025. Financial Incentives and Funding. Several states offer financial incentives including tax credits, tax exemptions, and rebate programs that encourage the deployment of residential, commercial and industrial energy storage systems by offsetting costs. For example: California’s Self Generation Incentive Program—designed to help reduce emissions, demand, and customer electricity costs—provides rebates to support existing, new, and emerging distributed energy resources installed on the customer’s side of the utility meter. This program is open to many different technologies, but according to the California Public Utilities Commission, the largest share of funding is allotted for energy storage projects. In 2017, Maryland established a state tax credit for a percentage of certain installed costs of energy storage systems on residential and commercial property. Legislation has also been proposed in New York that would create a state tax credit for residential energy storage systems equal to 25 percent of costs up to $7,000. A number of states offer funding for energy storage pilot and demonstration projects. For example: Massachusetts launched a $20 million grant program to pilot energy storage use cases to increase deployment of storage. The Washington Clean Energy Fund supports demonstration projects, including projects at utilities working with the Pacific Northwest National Laboratory to support understanding approaches to integrate and optimize storage control systems and development of a framework for evaluating the technical and financial benefits of storage. In addition to the efforts described above, we found that several states have proposed or undertaken a range of other efforts that may encourage the deployment of energy storage or address market barriers. For example, the Arizona Corporation Commission required two electric utilities to develop residential battery storage programs in order to lower customers’ energy use during peak demand. In addition, Maryland’s Public Service Commission initiated a grid modernization rulemaking that, among other things, will define residential energy storage, determine a classification for storage in the Commission’s rules, and create criteria to evaluate storage investments. Similarly, state legislation directs Oregon’s Public Utility Commission to create a framework for utilities to use when conducting storage evaluations. Moreover, the California Public Utility Commission has approved rules that increase the ways for energy storage systems to obtain revenue for multiple uses, or grid services, for example, from frequency regulation, capacity, or other services. We provided a draft of this report to DOE, FERC, and IRS for review and comment. In its comments, reproduced in appendix II, FERC generally agreed with our findings. DOE and FERC provided technical comments which we incorporated as appropriate. IRS did not provide written or technical comments. We are sending copies of this report to the appropriate congressional committees, the Secretary of Energy, the Chairman of FERC, the Commissioner of IRS, and other interested parties. In addition, the report is available at no charge on the GAO website at http://www.gao.gov. If you or your staff members have any questions about this report, please contact me at (202) 512-3841 or ruscof@gao.gov. Contact points for our Offices of Congressional Relations and Public Affairs may be found on the last page of this report. GAO staff members who made major contributions to this report are listed in appendix III. Through interviews with stakeholders and our review of documents, we identified examples of policies and other efforts that have encouraged the deployment of energy storage or aim to address market barriers, including the establishment of mandates and targets for storage adoption, the revision of interconnection rules and planning requirements, financial incentives, and funding. Table 1 describes examples of a range of state policies and other efforts that may encourage the deployment of energy storage. Frank Rusco, (202) 512-3841 or ruscof@gao.gov. In addition to the contact named above, Karla Springer (Assistant Director), Antoinette Capaccio, Janice Ceperich (Analyst-in-Charge), Philip Farah, Kristen Farole, Paul Kazemersky, and Daniel Kojetin made key contributions to this report. Also contributing to this report were Tara Congdon, R. Scott Fletcher, Cindy Gilbert, and Dan C. Royer.
Power plants' electricity output must be matched continuously with demand, which varies depending on the time of day and year. To maintain a reliable supply of electricity, operators of the electricity grid—a complex network of power plants and power lines managed by utility companies and other operators—take steps to ensure power plants are available to generate electricity when needed. Increasingly, renewable sources of energy, such as solar and wind, are being integrated into the grid. Energy storage allows for electricity to be stored and used later when it is needed and could change the operating capabilities of the electricity grid. Batteries and other energy storage technologies can store energy in one form—such as chemical, mechanical, or thermal energy—and transform that energy to generate electrical power at a later time. GAO was asked to provide information on the role of energy storage in grid operations. This report describes (1) how energy storage can be used to enhance grid operations and performance; (2) factors that affect the deployment of energy storage for grid operations; and (3) federal and state policies and other efforts that address the deployment of energy storage. GAO reviewed studies published from 2012 through 2017; and interviewed 41 stakeholders, including officials from government agencies and representatives of industry and other groups based on their knowledge of energy storage and grid operations. Energy storage can be used in various ways to enhance the reliability, resilience, and efficiency of grid operations, according to studies GAO reviewed and stakeholders GAO interviewed. Such storage can be deployed throughout the electricity system and act as a generation, transmission, distribution, or customer-sited asset to provide various services, address operational challenges and needs, and potentially reduce costs, as shown in the figure below. For example, storage can help grid operators address supply disruptions and the variability of renewable energy resources, such as solar and wind; relieve transmission congestion; defer the need for transmission or distribution system upgrades; and provide backup power during a power outage. Examples of Potential Storage Applications on the Electricity Grid Various factors affect energy storage deployment. These include industry and technology readiness, safety concerns and stringency of siting requirements, increasing use of renewable resources, cost-competitiveness of storage and challenges with quantifying the value of storage, and the regulatory environment, according to studies GAO reviewed and stakeholders GAO interviewed. For example, industry and technical challenges include uncertainty about the performance of certain technologies over time and in various operating conditions. Federal and state policymakers have used various policies and other efforts to encourage the deployment of storage and address market barriers. For example, the Department of Energy has undertaken various efforts, including research and development focused on improving factors that affect the cost and capacity of certain storage technologies. In addition, the Federal Energy Regulatory Commission has issued proposed and final rules to address market barriers to storage deployment in wholesale markets. Lastly, state policies and other efforts that aim to encourage the deployment of storage or to address market barriers include establishing mandates and targets for storage adoption, revising planning requirements, and offering financial incentives and funding.