Electricity Storage in North America


Energy Storage is said by some to be the ‘’Holy Grail’’ of energy technology.1 Energy grids are built to handle peak loads; if the peaks and the related capital investment can be reduced huge cost savings result. Some service offerings like electric vehicle (‘’ev’’) charging are impossible without it. The ERQ asked two of the leading experts in North American energy storage regulation to provide a current snapshot of the current situation.


In October 2015, employees at the Aliso Canyon natural gas facility in Los Angeles, California, discovered a methane leak that resulted in closure of the facility and California Gov. Jerry Brown issuing a state of emergency. In addition to the related environmental and health concerns, regulators worried about how the leak would impact availability of electricity for the region, and weeklong blackouts seemed inevitable. The solution to this problem was for utility Southern California Edison to rush energy storage projects online on an emergency basis. Within nine months, 60 MW of battery storage facilities were sited, constructed and operating, providing peak-demand energy at a time of concern and instability. Since then, developments in battery technology, state executive and legislative policies, and the recent Federal Energy Regulatory Commission (FERC) Order 8413 have continued to push energy storage into the national spotlight, signaling its role as a pillar of energy policy in the U.S.

According to the Energy Information Administration (EIA)’s May 2018 report “U.S. Battery Storage Market Trends” (EIA Report),4 at the end of 2017, 708 MW of power capacity representing 867 MWh of energy capacity of large-scale (greater than 1 MW) battery storage capacity was operational in the U.S. — two-thirds of which was installed in the past three years.5 Approximately 90 per cent of large-scale battery storage is installed in regions covered by regional transmission organizations (RTOs) and independent system operators (ISOs). In fact, nearly 40 per cent of existing large-scale battery storage power capacity (and 31 per cent of energy capacity) lies in the Pennsylvania-New Jersey-Maryland Interconnection (PJM) region while another 18 per cent of existing large-scale battery storage power capacity (and 44 per cent of energy capacity) lies in the California Independent System Operator (CAISO) region. According to the EIA report, as of December 2017, 239 MW of planned large-scale battery storage is expected to become operational in the U.S. between 2018 and 2021, with California accounting for 77 per cent of that number.

Advances in Storage Technology

Over the last 20 years, the energy industry has tested many different types of energy storage technologies, but for the first time, a market-tested front-runner has emerged: lithium-ion batteries. While nickel-based, sodium-based, lead acid and flow batteries have been deployed in the U.S., lithium-ion batteries comprised over 80 per cent of all U.S. large-scale (greater than 1 MW) battery storage capacity by the end of 2016. Typically, lithium-ion batteries are designed to implement 365 cycles per year, with a four-hour capability per cycle, and have a lifetime of 20-30 years. As seen in the deployment of the California battery storage facilities, with a four-hour duration battery, a standard 20 MW lithium-ion energy storage facility can deliver 80 MWh of capacity to meet peak demand. One of the most attractive aspects of these batteries is that the cost of lithium-ion technology has been rapidly decreasing; between 2010 and 2016, the price of lithium-ion batteries dropped 73 per cent, a decrease primarily driven by Chinese electric vehicle demand. The total installation cost of lithium-ion battery storage (including inverters and balance of plant) was approximately $1,300-$1,500 per kilowatt in 2017, and Bloomberg New Energy Finance has predicted that these installation costs will continue to drop 6 per cent per year over the next 10 years.

Competitive Advantages

The most alluring proposition related to energy storage is that storage can serve multiple purposes. Typically, energy assets serve one purpose in the energy system, but energy storage can act as generation when connected to the grid and as transmission when it is transmitting power. This is in addition to alleviating load stresses, as needed. Overall, energy storage has capacity and grid-balancing capabilities, and can regulate frequency, provide voltage support and enact blackstart capability services. As evidenced in the Aliso Canyon leak, energy storage can be deployed quickly, making it an ideal solution under circumstances of natural resource shortage, weather or incident-related outage, natural disaster or necessary growth of distributed generation.

Within the context of renewables, energy storage also has other advantages over solar and wind technologies. Whereas solar and wind often are subject to fluctuating output and rapid ramp-up and ramp-down, energy storage is stable for grid purposes, as it often features short charge and discharge cycles and responds better to fluctuating outputs. Further, energy storage can reduce stress on the electric system by addressing “duck curve” issues, increasing demand off-peak and increasing supply during peak times. (For example, two utilities in California and Arizona are proceeding with battery storage systems offering peaking capacity, as in the case of San Diego Gas & Electric’s 40 MW (160 MWh), four-hour duration battery storage facility in Fallbrook, California, and the Salt River Project (SRP)’s 10 MW (40 MWh), four-duration battery storage facility in Chandler, Arizona). Finally, under market environments with great load uncertainty driven by economic development, population shifts and expanded distributed energy needs, the employment of energy storage is ideal for policymakers who are concerned about making large investments that are both expensive and time-consuming. Energy storage can be used to avoid huge costs that would otherwise cause a plant or project to become an overbuild, as energy storage can be designed to meet exact offtake needs and help mitigate forecast error risk and costs.

Aggressive State Goals

State policymakers have recognized the technological advancements in energy storage as well as its competitive advantages and have in turn pursued executive and legislative policies to pursue front-of-the-meter energy storage. The nation’s leader in forward-thinking energy storage policy is California, which in 2013 passed a collective mandate requiring its investor-owned utilities (IOUs) to procure 1,325 MW in energy storage by 2020. Last year, the California Public Utilities Commission implemented Assembly Bill 2868 and issued an order requiring the IOUs to procure up to an additional 500 MW of distributed energy storage. In 2015, Oregon passed a mandate to hit 5 MWh per utility by 2020.

Not to be left behind, states on the East Coast have pledged support for energy storage as well. Earlier this year, New York issued a deployment initiative to reach 1,500 MW in energy storage by 2025, and Gov. Andrew Cuomo proposed that the NY Green Bank commit $260 million for energy storage-related investments. At the end of last year, Gov. Cuomo signed legislation that encourages the New York Public Service Commission to pursue and develop policies that will promote energy storage proliferation in the state. In June last year, the Massachusetts Department of Energy Resources announced a 200 MWh energy storage procurement target for electric distribution companies to be achieved by January 1, 2020.6 This was in accordance with bipartisan energy diversification legislation passed last year. Earlier this year, a new clean energy bill was introduced in the Massachusetts Senate that had included an energy storage target of 1,766 MW by 2025. In Arizona, a proposed plan would require 3,000 MW in energy storage by 2030. In May this year, as part of new renewable energy legislation, New Jersey adopted energy storage targets of 600 MW of energy storage by 2021 and 2 GW of energy storage by 2030, among the most aggressive in the U.S. New Jersey’s energy storage targets are the first to be set in a PJM region state. More states are expected to follow with announcements of energy storage targets and mandates. Some states are now also requiring utilities to include energy storage in their integrated resource plans.

Impact of FERC Order 841

As states set aggressive energy storage goals across the country, and battery technology became more accessible and common in the marketplace, critics still found that FERC’s traditional rules surrounding energy storage left them “financially hobbled” due to burdensome technical requirements contained in many RTO/ISO market rules. FERC’s limits on preventing energy storage from earning revenue from multiple streams also proved to be a roadblock for developers. Breaking this tradition and signaling a massive change in energy policy, in February this year, FERC issued Order 841, aiming to remove those market barriers that prevented “electric storage resources” from participating in wholesale energy markets.

Specifically, FERC Order 841 requires “each RTO and ISO to revise its tariff to establish a participation model consisting of market rules that, recognizing the physical and operational characteristics of electric storage resources,”7 facilitate the participation of such resources in the RTO/ISO markets. The RTOs/ISOs are directed to accomplish four principal objectives: (i) make changes such that an electric storage provider can fully participate in all capacity, energy and ancillary services markets, (ii) ensure that electric storage resources can be dispatched and that an electric storage provider can set the wholesale market clearing price as both a wholesale seller and wholesale buyer, (iii) account for the “physical and operational characteristics of electric storage resources through bidding parameters or other means,” and (iv) set a minimum size requirement for participation in the wholesale markets that does not exceed 100 kW.8 FERC Order 841 marked the first time that the nation’s leading energy regulatory body recognized that electric storage resources are different from other energy assets because such resources can deliver power into the grid and also withdraw it as both potential sellers and buyers. Additionally, prior to FERC Order 841, each electric storage provider was required to pay retail rates for electricity it took off the grid, making such participation prohibitive. Under FERC Order 841, each RTO/ISO has 270 days from the publication date of the order in the Federal Register to make a compliance filing and an additional 365 days to take action and implement the tariff revisions.9 Most experts agree that these target dates will likely be pushed back due to related comment and hearing delays.

Energy storage proponents have praised FERC Order 841 for promoting energy storage projects in the U.S., though some critics are concerned that the order does not do enough for the industry. Some say that by issuing FERC Order 841, FERC “passed the buck” to the RTOs/ISOs, relying on them to drive the energy storage markets. In fact, most projections of energy storage growth are in transmission and distribution, sectors that are beyond FERC’s immediate jurisdiction. Under FERC Order 841, states still have the flexibility and discretion to adapt rules to meet their particular energy needs, allowing grid operators to set minimum run time requirements, design their own bid standards, set rules for charging policies and determine if energy storage projects are permitted to sell ancillary services without directly participating in the regulated energy markets. Evidently, FERC Order 841 has given the green light to states to engage and promote energy storage, but the states themselves will need to drive energy storage to the finish line.

Future of RFPs

Due to the various pro-energy storage state policies and goals described, we expect to see states, motivated by executive and legislative mandates, use their FERC-granted discretion to integrate energy storage into electricity requests for proposals (RFPs) in a meaningful way. RFPs that included energy storage prior to FERC Order 841 may have been open to bid packages that included energy storage, but they did not preference or tailor requirements to suit it.

For instance, Arizona’s SRP power company issued an RFP earlier this year, before FERC Order 841 was released. The SRP RFP invited bids for 100 MW of capacity and stated, “Proposals with a battery storage component are also encouraged (as long as an alternative proposal without storage is also provided)”10 and that “[bids with] a renewable energy project with a storage component must also include a separate bid without the storage component.”11 This RFP treated energy storage as ancillary to, and severable from, bid packages, and it did not acknowledge the multiuse or other positive benefits of energy storage.

It is interesting to note that last year, SRP signed a 20-year power purchase agreement with NextEra Energy Resources for the now-completed 20 MW Pinal Central Solar Energy Center photovoltaic solar project, paired with a 10 MW (40 MWh) lithium-ion battery storage system. In May this year, NextEra Energy Resources closed on a $45 million loan provided by prominent project financing institutions Mitsubishi UFJ Financial Group and Mizuho Bank for the project that is Arizona’s largest utility-scale solar-plus-battery storage system.

Once FERC Order 841 is implemented by the RTOs/ISOs, we expect RFPs to be tailored to accommodate and, most likely, require energy storage as part of the bids. In addition, as the state-set goals for energy storage capacity approach, the RTOs/ISOs may feel pressure to issue RFPs that explicitly award preference for bid packages that substantively incorporate energy storage.

Electricity Storage Has Arrived

2018 has proven to be a major milestone and turning point for energy storage in the U.S.A perfect storm of more affordable, reliable batteries and ambitious, state-initiated capacity goals, along with FERC Order 841 has created an ideal environment for energy storage to grow at a fast rate and play an integral role in national energy policy. As the RTOs/ISOs begin to alter their approach to energy storage pursuant to FERC’s directive, it is safe to say that energy storage has finally arrived. Lower costs, increased deployment and ever-growing regulatory support will make project financing energy storage, particularly for lithium-ion, a more viable proposition in the future.


Energy storage has long been a staple in certain regions across Canada. The rich hydro resources found in British Columbia, Quebec and along the eastern seaboard, amongst others, have enabled hydroelectric facilities located there to provide many of the touted benefits of energy storage (capacity, time shifting, and demand response) simply by loosening or tightening the taps, as it were. Consequently, geographic differences have played a significant role in how different power grids have developed in Canada over time and such effects have largely spilled over into energy storage.

On the regulatory front, Canada does not have a national energy regulator along the lines of the United States’ FERC (Canada’s National Energy Board is primarily concerned with oil, natural gas as well as international and inter-provincial transmission), which would allow for a common approach to both the generation and storage of electricity. As a result, individual Canadian provinces often have more power linkages with American states to their south than with their Canadian peers on an east-west axis.

It’s perhaps no surprise that each of Canada’s provinces and territories is approaching energy storage separately and that newer energy storage technologies (lithium-ion, compressed air, and flywheel), which are not dependent on geographic bounty, are primarily gaining momentum in central Canada, particularly Ontario and to some extent, Alberta.

As of this writing, Canada’s energy storage is a patchwork of: (i) government procurement; (ii) behind-the-meter cost reduction opportunities; (iii) utility implementations and (iv) power-reliability solutions for remote communities, but given recent traction and trajectory, Canada is projected to be a 1.1 GW/2.5 GWh market by 2022.

Procurement/Assessment by Governmental Agencies

In Ontario, the Independent Electricity System Operator (IESO) has undertaken competitive processes that which have led to the procurement of over 20 storage projects since 2012 and will result in approximately 50MW of capacity when fully installed and commissioned. The current procurement framework reflects a two-phase approach, with phase 1 focused on storage capacity as part of a suite of ancillary services that promote system reliability, and phase 2 designed to address issues such as how storage can meet future system needs, allow for deferral of transmission investments, and enhance the value of renewable generation.12 In addition, the IESO regularly runs frequency regulation and demand response RFPs, in which energy storage proponents are becoming increasing competitive.

These procurements, largely the result of the storage industry’s (as represented by Energy Storage Canada) education and advocacy efforts, created a firm basis for the testing of a variety of technologies and the grid and/or utility-scale services which energy storage can provide, while steering clear of the public incentives and subsidies on which a significant portion of the renewable industry across Canada has relied and which are subject to the prevailing political winds (the new Ontario government has cancelled and/or repealed a number of the previous administration’s renewable programs and regulations).

On the regulatory front, Ontario’s 2017 Long-Term Energy Plan (LTEP)13 recognized the need to address regulatory barriers to storage technologies. As a result, the IESO established the Energy Storage Advisory Group in April 2018 to identify potential obstacles to fair competition for energy storage and address related market issues and opportunities. In parallel, the Ontario Energy Board (OEB) issued an implementation plan that aims to, among other things, facilitate the development of distributed energy resources (including storage projects).

In addition, the IESO has concluded that energy storage technologies can be used to provide some of the services needed to reliably operate the power system (e.g., regulation services, voltage control, and operating reserve). Energy storage could also help improve the utilization of existing transmission and distribution assets by deferring some costs associated with their upgrades or refurbishments, as well as improve the quality of electricity supply in certain areas of the system by controlling local voltages. The IESO has further suggested that in order to utilize the full potential of energy storage, proponents should target those areas of the system where they can provide multiple services to the IESO-controlled grid, the IESO-administered markets and local market participants.

In Alberta, the Alberta Electric System Operator (AESO) has been studying the value of energy storage since 2012, when it began to formally examine storage technologies in relation to market rule issues and technical standards. Most recently, in May 2018, the AESO completed an assessment of dispatch-able renewable generation and energy storage in the context of grid reliability requirements and Alberta’s transition toward 30 per cent renewable generation by 2030 and concluded that low-energy, short-duration applications, such as lithium-ions batteries, may be able to cost-effectively compete (primarily in the ancillary services market), provided that certain market rules and transmission tariff issues are addressed. As part of the AESO’s plan for implementing a three-year capacity market by 2021, energy storage capacity that meets the minimum discharge requirements will be eligible for market participation.

Behind-the-Meter Storage Solutions

Behind-the-meter generation and/or storage solutions have historically been used to time-shift energy usage in order to take advantage of cheaper market windows and to provide increased reliability in areas where this was a challenge for the local power grid. In Ontario, this has taken on a new flavour as a result of the Industrial Conservation Initiative (ICI),14 which rewards certain users for reducing their electricity demand during peaks and the way in which inherent and historical system costs and charges (“Global Adjustment”) (as more fully explained below) are allocated among electricity users. Global Adjustment is designed to address the “missing money” problem (i.e., insufficient market revenue to cover certain fixed capacity costs) by recovering the difference between the total contracted cost and the market value of certain contracted generation. A decrease in the market price of electricity leads to an increase in Global Adjustment, and vice versa. Over the years, Ontario’s Global Adjustment costs have grown significantly, from $700 million in 2006 (8 per cent of total electricity supply costs) to $11.9 billion in 2017 (over 80 per cent of total electricity supply costs).

Under the ICI, the allocation of Global Adjustment to certain large industrial consumers (i.e., Class A) is determined by their respective contribution to the province’s top five peak demand hours in a twelve month period, while the remaining Global Adjustment costs are passed on to the other consumers (i.e., Class B) in proportion to their energy consumption. To minimize Global Adjustment charges – which can far exceed the commodity costs of electricity in some cases, Class A consumers are incentivized to shift consumption away from peak hours (or what they anticipate to be peak hours) by curtailing production or installing onsite supply (including energy storage). As a result, Ontario has experienced a bit of a behind-the-meter “gold rush” with a number of local and international energy storage players chasing commercial and industrial users with the largest Global Adjustment spend. A few publically available examples are noted below.15

Use of Electricity Storage by Electricity Utilities

Independent of the provincial procurement process, a number of Ontario utilities are piloting and assessing different storage technologies for a variety of uses. Their experiences to-date suggest that storage technologies have the potential of becoming integral tools for managing peak loads, regulating voltage frequency, ensuring reliability from renewable generation, and creating a more flexible transmission and distribution system. A number of utilities have also proposed that related costs become part of the rate base. For customers, energy storage might be a useful tool for reducing costs related to peak energy demand.

For example, Toronto Hydro has been working with its partners to amongst other things: (i) analyze the electrical grid benefits of underwater compressed air energy storage by running a pilot project which focuses on the technology’s ability to provide reserve power, shift load and mitigate transmission and distribution congestion and (ii) develop a pole-mounted solution to store electricity during off-peak hours and release power to help improve reliability through an automatic response to smart meter data. Expected system benefits include load levelling, deferral of infrastructure upgrades, and increased reliability and operational flexibility.

Similarly, Hydro One Networks has been operating a temporal flywheel system in Clear Creek, Ontario to regulate the large voltage swings caused by a 20 MW wind farm and Oshawa Power and its partners developed a pilot project to allow homes in the City of Oshawa to use solar energy at home and store it using a lithium-ion battery for shifting energy demand from on-peak to off-peak and provide backup power supply during power outages.

In Alberta, the Alberta Utilities Commission (AUC) approved a proposal from Turning Point Generation16 to construct and operate the Canyon Creek Pumped Hydro Energy Storage Project. The project will utilize pumped hydro energy storage. When power requirements are low, water would be pumped from a lower reservoir to an upper reservoir. When power is needed, for instance during peak demand or periods of low wind to power the wind farms in southern Alberta, water would be allowed to flow back to the lower reservoir and drive the turbines to generate power.

Electricity Storage, Distributed Generation and Remote Communities

As distributed generation sources, energy storage deployments can enhance supply adequacy and respond to contingencies. For instance, in an islanding scenario (many of Canada’s remote northern communities are effectively “islands”), battery storage can react quickly to maintain power supply when a portion of the system becomes disconnected from the main grid because of a planned or unplanned outage. Further, when stored electricity is injected into the grid at times of high demand, system peak loading (which underpins key planning criteria used by transmission and distribution system engineers) is reduced, thus relieving loading on critical substation components. This would potentially extend the useful lives of related assets and/or defer the need for capital upgrades which would otherwise be required sooner to meet forecast peak demand.

A successful example of energy storage being used for distributed generation purposes (and a welcome precedent showing that non-hydro energy storage can still have a place in locations which are lavishly endowed with hydro resources) is BC Hydro’s 1 MW battery bank, which is sited in two remote mountain communities in British Columbia to store power from renewable sources.

Up until 2013, the two mountain communities of Golden and Field, in the East Kootenay region of British Columbia, had experienced significant power reliability issues. Both towns receive power from BC Hydro’s Golden substation, which uses four radial distribution feeders to supply the town of Golden and surrounding areas. In early 2010, load forecast for the area predicted substation capacity would be exceeded by the winter peak of 2013-2014. In addition, the town of Field, located approximately 50 km to the east of Golden, is supplied by a single 25-kV feeder from Golden. This distribution line experiences frequent and prolonged outages because of the heavily forested environment and cold, snowy conditions of Yoho National Park, in which the town of Field is located. The feeder does not always follow the road, and the rugged terrain makes it especially difficult for crews to locate faults and restore power. BC Hydro partnered with Natural Resources Canada to install a battery storage system in the problematic areas which would address these issues and defer the cost of transformer upgrades at the substation for two years. Since being deployed in 2013, the battery system has helped to supply area load for up to seven hours, and reduce system load during peak demand periods.

In addition, many of Canada’s far north indigenous communities are considering the benefits of renewable generation mated with energy storage as a way to reduce the use of diesel generators, the fuel for which is delivered by air, resulting in (i) high cost and (ii) reduced system reliability (due to outages).


Energy storage has the potential to play an important role in optimizing and modernizing the electricity grid. The costs of energy storage system prices (particularly batteries) have decreased significantly in the past two decades. The downward trend in costs is projected to continue (albeit at a slower rate) into the foreseeable future. The prospect of lower capital investment requirements, coupled with the potential mitigation of regulatory and market barriers, as well as the myriad of reliability and customer benefits that energy storage can provide, has many betting on energy storage as the key missing component to a renewable-dominated, modernized and efficient power system: Grid 2.0.

However, in addition to the progress made to date, the effective integration of utility-scale storage systems will require regulators, utilities and industry to work together to address remaining obstacles and limitations, including technical barriers to market participation by storage resources and unclear rules regarding the treatment of an unconventional asset that is both a load and a resource. The devil will be in the details, as utilities bring the issue before regulators in the course of rate proceedings, which are occurring in real time.

Given current trends, Canada’s energy storage market is projected to grow at 35 per cent per annum in each of the next four years. If pump storage is included (Ontario Power Generation’s 174 MW Sir Adam Beck project and Northland Power’s proposed (approx. 600 MW) Marmora project) the picture begins to look rosier still. As progress on multiple fronts begins to coalesce – including the evolution of technologies, removal of regulatory and market barriers, maturation of utility business and cost allocation models, as well as the continued reduction in capital investment requirements, a balanced and realistic optimism for energy storage in Canada may be the most sensible position going forward.

* Paul Kraske is a partner in the Washington DC office of Skadden Arps, Slate, Meagher & Flom.

** Milosz Zemanek is a partner at the Toronto office of Torys LLP, head of the firm’s energy storage practice and Chair of the Board of Energy Storage Canada.

*** Henry Ren and Tim Pavlov are energy associates at Torys LLP.

  1.  David Schmitt and Glenn Sanford, “Energy Storage: Can We Get It Right?’’ (2018) 32 Energy LJ 447, online: <https://www.eba-net.org/assets/1/6/20-447-502-Schmitt_[FINAL].pdf>.
  2.  The Electricity Storage in the United States section of this article is a republication : Paul Kraske “Electricity storage in the United States: Are We There Yet?’’, online : (22 June 2018) Skadden <https://www.skadden.com/insights/publications/2018/06/energy-storage-are-we-there-yet>.
  3.  Order No. 841, Electric Storage Participation in Markets Operated by Regional Transmission Organizations and Independent System Operators, 162 FERC 61,127, 83 Fed Reg 9,580 (2018) (to be codified at 18 CFR § 35) [hereinafter Order No. 841].
  4.  U.S. Department of Energy, ‘’U.S Battery Storage Market Trends’’, (May 2018), online: <https://www.eia.gov/analysis/studies/electricity/batterystorage/pdf/battery_storage.pdf>.
  5.  Ibid at 4.
  6.  Massachusetts Department of Energy Resources, ‘’State-of-Charge: Massachusetts Energy Storage Initiative Study’’, online: <http://www.mass.gov/eea/docs/doer/state-of-charge-report.pdf>.
  7.  Supra note 2 at i.
  8.  Ibid.
  9.  Ibid at 222.
  10.  Ibid at 207.
  11.  Ibid at 85-86.
  12.  See Energy storage procurement (Phase 1 and 2), online: <http://www.ieso.ca/sector-participants/energy-procurement-programs-and-contracts/energy-storage>.
  13.  See online: <https://news.ontario.ca/mndmf/en/2017/10/2017-long-term-energy-plan.html>.
  14.  Market Surveillance Panel, ‘’The Industrial Conservation Initiative: Evaluating its Impact and Potential Alternative Approaches’’, (December 2018), online: <https://www.oeb.ca/sites/default/files/msp-ICI-report-20181218.pdf>.
  15.  In November 2017, Convergent Energy + Power announced the completion of an 8.5 MWh energy storage project for Husky Injection Molding Systems Ltd. in Bolton, Ontario. The project is based on Lockheed Martin Energy’s GridStar lithium battery system. In April 2018, the Enel Group’s energy services division, Enel X, through its U.S. subsidiary EnerNOC, Inc., announced an agreement with Algoma Orchards to deploy a 1 MWh lithium-ion battery storage system, with the aim of reducing Global Adjustment and enhancing participation in the IESO’s demand response program. In June 2018, NRStor and IHI Energy Storage entered into a memorandum of understanding for IHI to deliver 42 MWh of behind-the-meter (BTM) lithium ion battery solutions for eight of NRStor’s commercial and industrial customers in Ontario. These storage projects are expected to be operational in 2019. In July 2018, Enel X announced an agreement with Amhil North America, a packaging company for the food services industry, to deploy a 4.7 MWh lithium-ion energy storage system at Amhil’s facility in Mississauga. Similar to the Algoma Orchards project, the Amhil project will reduce peak demand and enhance demand response participation.
  16.  See online: <https://turningpointgeneration.ca/the-canyon-creek-project>.

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