Energy Storage in the Grid: The Holy Grail? (Part I)
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- Jul 28, 2020 12:00 am GMTJul 13, 2020 8:21 pm GMT
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This item is part of the Energy Storage - Special Issue - 07/2020, click here for more
Many challenges ahead, but great and innovative deployment opportunities in a no so dystopic near-future for the grid.
PART I: Critical Need for Energy Storage
The decarbonization of the energy system is one of the biggest challenges facing the world today, and electric utilities have key roles to play in the acceleration toward a cleaner future. Energy storage is expected to play an increasingly critical role in the integration of increasing levels of renewable energy (RE) sources but several challenges remain to achieve large-scale storage deployment.
According to the International Energy Agency (IEA), only 140GW of large-scale, grid-connected energy storage has been deployed worldwide, with 99% of this pumped-storage hydroelectricity. To support electricity sector decarbonization, an estimated 310GW of additional grid-connected energy storage capacity would be needed in China, India, Europe, and the United States by 2050.
Advanced energy storage provides an integrated solution to some of America’s most critical energy needs: electric grid modernization, reliability, and resilience; sustainable mobility; flexibility for a diverse and secure, all-of-the-above electricity generation portfolio; and enhanced economic competitiveness for remote communities and targeted micro-grid solutions.
Storage technologies strengthen and stabilize the U.S. grid by providing backup power, levelling loads, and offering a range of other energy management services. Electric vehicles (EVs) are also poised to become an integral part of this new grid paradigm as their batteries both draw power from and supply it back to the grid (when beneficial) – while eliminating tailpipe emissions.
The Role of Energy Storage in Low-Carbon Energy Systems
There could be a revolution in the role of energy storage as energy systems are decarbonized. Novel energy storage technologies are expected to make an important contribution in the future, particularly in the event of heat and transport electrification or if intermittent renewables and nuclear come to dominate electricity generation. Numerous energy storage technologies have been proposed to store excess electricity, with electrical energy conversion to mechanical, thermal, gravitational, electrochemical, and chemical energy for storage, and many of these technologies are classified in this chapter.
Energy storage technologies are complicated and poorly understood relative to most low-carbon technologies. A series of metrics have been proposed to compare storage technologies but understanding how to integrate energy storage into low-carbon energy systems remains a difficult challenge for several reasons.
The value of storage to an energy system depends on the electricity generation portfolio, particularly the relative amounts of inflexible and flexible generation. The existing energy system, dispatch, and network models are either not broad enough to examine all energy storage and alternative options or have an insufficient temporal resolution to realistically portray the need for and performance of storage technologies. Innovation is required to reduce technology costs.
“Energy storage deals with the relationship between stocks and flows: storing energy, whether by natural or anthropic processes, involves the accumulation of flows as stocks; exploiting stored energy involves the conversion of stocks to flows.” Plamer and Floyd from Monash University said in their book recently published via Springer (Energy Storage and Civilization) They also add “energy storage, as both a technological and natural phenomenon, has been much more significant to the development of human civilizations than usually understood.” Sunshine and wind energy – primary energy sources in a renewable energy future – are energy flows. Grains, butter, wood, coal, oil and natural gas are energy stocks.
The quest for the Holy Grail
Our current industrial civilization relies on the vast quantities of energy stored in our so-called fossil fuels. After millions of years in preparation, these energy stocks now allow us to consume energy anywhere on earth, at any hour and in any season.
Fossil fuels are higher in energy density than any previous energy stock at our control. That energy density means we can ship and store these stocks for use across great distances and long periods. Oil is so easy to ship that it is traded worldwide and is fundamental to the entire global economy. If the limited supplies of readily accessible fossil fuels weren’t running out, and if their burning weren’t destabilizing the climate and threatening the entire web of life, we might think we had discovered the Holy Grail of our time.
In particular, fossil fuel stocks can be readily converted to electrical energy flows. And electricity, which is so magnificently versatile that it too is fundamental to the global economy, cannot be stored in any significant quantity without being converted to another energy form, and then converted back at a time of use – at a significant cost in energy losses and further costs for the storage technologies. Fossil fuel usage generates a lot of resources waste and CO2 emissions.
This is no more so holy. In fact, it’s not the only crux of the problem. The vision of a renewable energy economy relies on the use of solar PV, wind turbines and similar RE technologies to generate all our electricity – plus the electrification of systems like transportation, which now rely directly on fossil fuel combustion engines.
Beyond simple technologies like huge tanks or reservoirs of oil and gas, and stockpiles of coal, our current economy has little need for complicated means of energy storage.
How much storage would we need to manage current energy demand with the highly intermittent flows of solar and wind energy? and, Are there methods known today which could create those quantities of energy storage? In Palmer and Floyd’s estimations, to maintain an economy with today’s energy consumption without fossil fuels, we will need to expand “current technologically-mediated storage capacity by three orders of magnitude”.
It’s definitely not just one method that will be required. It’s a mix of various solutions that, working together, will generate the required amount with a much more viable carbon footprint that the actual fossil-fuel-dependant infrastructure.
Toward a More Robust Electric Grid
State-level 100% clean energy targets are increasingly becoming the norm across the United States thanks to fast-falling renewable energy prices and forward-looking policymakers. While states have led the way so far, federal policymakers have also proposed a 50% by 2035 national clean energy standard that could advance in 2021.
These targets represent a clean energy transition. This fundamental paradigm shift in how we build and operate our energy infrastructure offers tremendous opportunities to improve public health, limit climate disruptions, and expand our economy.
This paradigm shift, like any other, faces major barriers preventing an accelerated clean energy transformation—yet smart policy can overcome them. So what will it take for the U.S. energy system to reach ambitious clean energy targets by 2035, 2040, or 2050?
Clean energy generation and other technologies on the distribution network are often referred to as “distributed energy resources” (DERs). These DERs can produce electricity (e.g., rooftop solar panels), modulate or shift demand (e.g., batteries or smart thermostats), or efficiently use electricity in new and important ways (e.g., LEDs, heat pumps, and electric vehicles).
In addition to emitting zero pollution, the principal advantages of DERs compared to fossil fuels are that they are local (more efficient and resilient), are not land intensive (use existing infrastructure), are easily mass-produced (drives down cost), and can have more diverse ownership capital (draw investment from a wider capital pool and involve additional investors with a stake in the clean energy transition).
Clean DERs are central to reaching clean energy targets and navigating the resulting energy infrastructure paradigm shift, but their need for scale creates barriers to their deployment.
For energy consumers and the distribution network, the clean energy transition necessitates deployment at scale of mass-produced technologies like EVs, rooftop solar, heat pumps, and building efficiency upgrades. Unfortunately, deployment at scale faces a complicated deployment environment, split incentives, red tape, and hostile incumbents.
Fortunately, the barriers to deployment at scale can be overcome with incentives, improved standards, and fairer laws and regulations.
For grid applications, electricity must be reliably available 24 hours a day. Even second-to-second fluctuations can cause major disruptions that could potentially cost billions of dollars. New approaches to maximize energy storage capacity are essential to bring intermittent renewables into the grid and effectively manage electricity generation to meet peak demand. Many utilities seek to enable a smarter, more flexible electric grid by advancing research on novel materials and system components that would resolve all the key challenges for energy storage systems in one shot:
- Affordability. Meet system needs at minimal costs
- Efficiency. Optimize assets and reduce delivery losses
- Flexibility. Handle dynamic supply and demand and accommodate diverse technologies
- Reliability. Consistently deliver high-quality power
- Resiliency. Maintain critical functions/quick recovery
Yes, this might be great if this new Holy Grail is found and all is resolved at once, but the reality might be more complex. But this might come too late for some operators already in a so-called Death Spiral.
The Utility Death Spiral
Declining usage, increasing costs, and distributed energy resources challenge the traditional utility business model fashioned on monopoly services in an environment of perpetual economic growth. To avoid the clichéd “utility death spiral,” the industry needs real solutions that address resilience, customer engagement, digitalization, and attracting the workforce of the future. A centralized electric grid will always be needed to provide reliable and affordable electricity, but all utilities will not survive this disruption. Those that do survive will be the ones that can innovate and adjust rapidly to our evolving environment.
The past offers little insight into how quickly utilities will adopt the technology, which helps integrate renewables onto the grid, deliver peak capacity without carbon emissions, instantly adjust the frequency of the system and more. It’s because, for almost every year in the historical record, the majority of utilities paid no attention to battery storage.
As costs have fallen and early adopters generally liked what they saw from initial trials, though, the cycle from pilot to evaluation to widespread adoption is speeding up. And that’s what we should see in the coming years.
A new analysis sheds some light on how that adoption cycle works. Wood Mackenzie storage researcher Gregson Curtin tallied up utility integrated resource plans from the last three years (those are the documents where companies tell the world what power plants they expect to build in the coming years).
In 2017, almost none of the 43 utilities that Curtin surveyed expected to build any energy storage. The official outlook from that year suggested storage would not play a meaningful role in grid operations during the 2020s.
In 2018, six utilities decided to pencil in some battery procurement, amounting to a smidge more capacity expected online in the coming decade.
In 2019, 10 utilities planning to install storage in their 2019-2020 integrated resource plans called for five times more capacity, on average, than the utilities including it in their 2018 plans.
As a result, the combined resource plans now anticipate 6.3 gigawatts of battery deployments from 2020 to 2029. The Tennessee Valley Authority, the Puerto Rico Electric Power Authority and PacifiCorp led in expected deployments during that decade.
Even in regulated markets, energy storage interest does not always register in IRPs. Arizona Public Service’s 2018 IRP called for massive investment in gas capacity; the following year, the utility announced an 850-megawatt storage deployment spree, and this week it committed to 45 per cent renewables by 2030. That massive ramp in storage ambitions transpired before the release of a new IRP, which will eventually reflect the change.
Falling prices for batteries also help avoid the death-by-pilot phenomenon, because project economics keep getting better. The Wood Mackenzie's analysis found that utilities often rely on outdated pricing for their storage models, meaning actual bids frequently beat expectations. The observed spike in interest reflects a learning process, where small pilot projects give utilities operational experience with the technology, and the results encourage them to expand their ambitions. It's important to note that this analysis does not fully capture energy storage uptake. For one thing, long-range plans differ from actual procurements; utilities sometimes buy more, sometimes less of a resource than they had expected to. Also, the integrated resource plan (IRP) data points come primarily from regulated utility markets that engage in long-term planning of electricity supply; additional construction is already underway from independent developers in competitive markets. To make a long story short: It depends because utilities/operators are perpetually walking a tightrope.
PART II: Walking a tightrope
Power grid operators are continuously trying to balance the supply of generation and the capacity to deliver it with customer needs at any given moment and location within the service territory. The gradual decentralization of power generation and delivery is adding a new facet to this challenge: How can the power grid account for customers who generate their own power?
Reversing the flow of electricity is not something anyone intended when power grids were first designed and built. But what if all stakeholders involved were coordinated and could use real-time price signals to determine the best course of action automatically, in accordance with supply and demand? What if the laws of economics could function harmoniously with the laws of physics?
Many utilities have launched innovation incubators to collaborate with technology companies and develop solutions for common challenges. While there are worthy reasons to collaborate with outside organizations, this won’t provide the necessary industry solutions. Creating innovative ideas to bring back to the organization is one thing, but fundamentally creating an innovative organization is much more difficult.
In short, there are creative and maintenance models of an organization. Immature companies experience an intensely creative and entrepreneurial phase. However, success during an organizational phase inevitably produces a crisis that constrains progress and growth. Thus, the creative phase is followed by a control crisis. Following the resolution of the control crisis, the more mature organization enters a maintenance phase. Organizations in the maintenance phase are not unlike utilities. They are stable, rational, analytical, and have an evaluative ethos. They are also management heavy, have a bureaucratic structure, threatened by change, and have low motivation. Throughout time, these mature organizations must work through what some call a “stagnation crisis” to get back into a re-creative phase to properly integrate Energy Storage in their business model.
Grid edge entrepreneurs often bemoan “death by pilot,” where utilities run small-scale tests of promising technologies but never move to widespread deployment. Market observers might wonder why a utility like Dominion Energy still feels the need to test whether batteries can store solar power for use later on when a utility like APS has already awarded contracts for full-scale solar-battery peaker plants.
It is difficult for highly regulated companies, like utilities, to be capable of being creative organizations. Utilities need to feel comfortable with how batteries perform before they can integrate them into system planning and grow their fleets. It is a system intended to prevent radical change and to ensure that certain things happen. It is essentially a maintenance organization will tolerate inefficiencies to avoid unpredictable situations. Parts of the utility organization really do need to be highly regulated. The key is not being either maintenance or creative organization, but rather being both. Utilities should strive to be organizations that provide predictability and consistency while also being forward-thinking, creative, and innovative. Semi-autonomous business units, without interference and intrusion by the traditional organization, are one way for utilities to achieve this result.
Leaders of the Pack
There are examples of these sorts of constructive efforts within the utility industry. Utility innovation centres like those at Duke Energy and AEP quickly come to mind. The culture of these innovation centres is so drastically different than that of the traditional utility; they must be in a different physical building for it to work correctly.
AEP Charge was created to “power what’s next” for the utility. AEP Charge has technologies and capabilities that were previously not available or in use in the industry. It works with internal business partners to efficiently and cost-effectively realize their visions and re-imagine the industry. Similarly, Duke Energy has a digital transformation accelerator known as Lighthouse. There, more than 400 employees work on company-wide initiatives. Lighthouse has developed new products using AI, machine learning, automation, and more. New products developed by both innovation centres include mobile applications for field operations, robotics to expedite tedious accounting operations, analytics for predictive maintenance, advanced decision science-based systems with revenue loss detection capabilities, and 3D-printed test switch isolators. These semi-autonomous organizations are the innovation leaders of the utility industry.
With Energy storage and DER coming at a fast pace, systemic trends are forcing utilities to confront the need for rate design changes. Electric utilities, especially in the USA, are seeing their industry transformed. Many items have drawn revenues and customers away from traditional utilities and created a mismatch between electricity rates and utilities’ costs, notably:
- renewable portfolio standards,
- nonutility generators of renewable electricity,
- net metering,
- behind-the-meter storage, and
- other distributed energy solutions.
Flexibility, Rate Structure and Transactive Energy
In the long term, policy and technology trends, largely spurred by decarbonization,6 could continue to motivate customers to decrease their dependence on—or even abandon—traditional utilities in favour of third-party suppliers. There is no cure-all, but electricity rate designs must be reformed to ensure a stable transition to less carbon-intensive sources and secure utilities’ role in the future system.
Historically, electricity rate structures have bundled all-electric services into one volumetric rate—charging customers by kilowatt-hour of use served all major stakeholders’ objectives. Customers within the same rate classes (commercial, industrial, residential) received the same level of service and understood that their electric bills varied based on the amount of electricity they used. Utilities recovered their costs and capital investments without significant rate increases. Policymakers liked that volumetric rates encouraged energy efficiency. And with few substitute options for customers, the system was stable.
Today, against the backdrop of decarbonization, increasing customer sophistication, and new competition, utilities’ fixed costs are increasing. Grid modernization, Energy Storage, DER and other investments to meet sustainability goals come at a significant capital expense. As a larger share of electricity is sourced from renewables, utilities will need to secure enough system flexibility to maintain reliability when supply from renewables is intermittent or low. With volumetric rates, mounting fixed costs are passed on to customers who have not taken advantage of decentralized, third-party arbitrage opportunities (such as net metering or behind-the-meter storage). Customers find their bills confusing as a result, unable to understand why their bills are increasing despite limited changes in their usage and level of service.
Unless utilities update their pricing and offerings, they will find themselves with a shrinking base of customers among which to distribute rising costs. With regulatory processes that can last years, rate-design reform must start today if utilities hope to address the problems coming in the next decade.
Blockchain actually enables transactions between consumers without traditional third-party involvement. So, the usual system would be a utility or bank that manages the transaction. Blockchain uses a decentralized model and enables trading electricity from distributed energy resources, like storage. But to implement a transactive energy economy, blockchain or other types of distributed ledger technology must be scalable as well as secure.
This represents a shift from a centralized to a decentralized model that allows for negotiation between stakeholders. Today’s information technology systems could support such a model, but regulatory approvals are needed still. Low latency is key. When dealing with power and real-time transactions, it has to be quick. And, in order to scale, it has to be low cost.
Progress toward a lower-carbon, the customer-centric electric-power industry is underway; previous McKinsey research has explored flexibility and resilience questions underlying decarbonization.7 A critical element needed to enable this transition is an overhaul of rate design. An updated rate design must align rates with system-wide costs, encourage flexibility, and address customers’ differing needs.
According to the National Renewable Energy Laboratory (NREL), blockchain serves as a distributed digital record of actions agreed to and performed by multiple parties. The main value in applying the technology is the mathematical proof about the state of the data, so all parties can agree on outcomes regardless of their relationship with one another.
“When you have hundreds of thousands or millions of devices out there that want to interact, you face a significant trust challenge,” said Tony Markel, a senior engineer in NREL’s secure cyber-energy systems group. “Trust between devices can only be achieved through methods that verify and enable proof that each system does what it said it was going to do. With blockchain, we may have a path to achieve secure, trusted communications between players without a need for central control.”
On the other hand, with the right prices as incentives, customers can contribute to grid operations in multiple ways, including demand-response, flexibility, and distributed generation. Over time, customers could be integrated into an on-grid market that prices energy, capacity, and flexibility in real-time based on system needs. In this future, the utility could function as a platform that facilitates transactions—for a fee—between itself and customers, between third parties and customers, and between customers. Rate-based compensation for these services is a potential first step toward such a grid-based market. Energy Storage of all types would facilitate that for forward-thinking utilities in order to get efficient in this new revenues stream context.
NREL put these ideas to a test, conducting experiments on homes connected by blockchain and equipped with rooftop solar arrays. In the system, the homes had the ability to sell surplus electricity to one another. This functionality required a secure data signal with information on energy generated as well as payment information between the buyer and seller.
NREL’s home energy management system, called foresee, was the keystone to this. It can interconnect solar panels, energy storage and smart appliances and then apply machine-learning algorithms, data analytics and physics-based modelling to analyze usage patterns. Foresee alerted one home when solar power was cheaper to buy from the other rather than paying utility rates, then used digital currency to buy the power. According to NREL, this shows the potential ability to make purchasing decisions automatically that benefit all participants as well as regulate demand from end-users.
Dylan Cutler, a senior engineer with NREL and the lead investigator on the project, said the experiment provided valuable evidence of the technology’s potential.
“There’s a lot of talk and buzz out there about blockchain but very little documentation,” Cutler said. “This project was a necessary first step in this field — for me, at least, and I think the lab in general — to get some comfort with the technology.”
Cutler added that blockchain’s use in the energy market requires a closer look at grid resiliency, reliability and cybersecurity concerns. According to NREL, the scope of Cutler’s research did not consider what role a utility might play in peer-to-peer energy transactions.
A couple of years ago, a larger study was commissioned by the California Energy Commission using support and customers from Southern California Edison (SCE) as well as technology by prime contractor Universal Devices Inc. and TeMix Inc. Ron Gales, senior adviser for corporate communications with SCE, said the Retail Automated Transactive Energy System (RATES) pilot-tested a technology-enhanced interface that enabled customers to adapt end-use consumption to hourly dynamic prices transmitted to an in-home hub.
SCE participated in the pilot to better understand how the technology interface could work with real-time independent system operator (ISO) and distribution system operator (DSO) prices as well as learn more about the sensitivity of consumption to retail prices that change hourly. Gales said the RATES pilot offered the option for customers to hedge their risk exposure to the dynamic price by subscribing a preselected amount of energy consumption available at the retail tariff.
According to Gales, the ISO manages supply and demand characteristics on the bulk generation system today that results in hourly generation energy prices. Because the distribution system is different from the bulk generation system, industry participants will have to partner with regulatory commissions and market settlement agencies to define the economic optimality of hourly prices on the distribution system. Protocols will have to be established to determine the pecking order of local constraints cascading up to bulk system constraints.
“Billing systems, customer load management and information sharing between industry participants and market settlement agencies will need to be coordinated to ensure the efficient functioning of such a decentralized approach,” Gales said, adding that processes and standards will act as enablers for disaggregated load management while also reducing the potential for gaming the system.
With respect to benefits, many utilities are already looking at how individual storage units or storage units in conjunction with power-flow controller devices may be the least-cost solution to address case-specific reliability issues on the transmission network. The development of storage benefit cost-analysis tool could prove useful to determine which energy storage solutions are cost-efficient compared to traditional solutions, like line and transformer upgrades. This tool could be customized based on different market and policy conditions.
In addition, some utilities are investigating how Energy Storage can provide power-quality grid support services such as volt/reactive volt-ampere (volt/VAR) and frequency-watt support. The inverters used to connect the direct-current (dc) battery system to the alternating-current (ac) electric grid can support the grid by regulating the system voltage, responding to and regulating the system frequency changes, forming an island system to enhance resiliency and providing communication the utility can use for dispatch. It also can support the bulk power system’s stability by using the ride-through capability.
Increasing Energy Storage usage will ensure electric reliability for customers during peak summer months and defer the need for construction of an additional underwater supply cable to the island. The utilities will benefit not only by installing energy storage but also taking the opportunity to study the use cases and adapting it to various situations. Artificial Intelligence will be of great help in doing that optimization
Energy storage can offer a variety of benefits and challenges. With respect to benefits, an energy storage resource — either by itself or in conjunction with power-flow controller devices and artificial intelligence — may be the least-cost solution to address case-specific reliability issues on the transmission network. This combination also can provide power-quality grid support services, like volt/VAR and frequency-watt.
With respect to challenges, the first one centres on cybersecurity. Specifically, cybersecurity with the energy management system (EMS) can be problematic as some energy storage inverters are manufactured outside the U.S. Cybersecurity standards need to be updated frequently to maintain the resiliency of the electric grid.
A second challenge is some regional planning processes by regional transmission organizations and independent system operators do not consider energy storage as a potential solution to meet reliability needs.
Furthermore, because of the variety of storage inverter designs and proprietary information protected by manufacturers, a third challenge is the lack of standard storage models. This poses a challenge to utilities when trying to properly model energy storage in their planning studies.
All in all, considering both the benefits and the challenges, utilities should be allowed to own energy storage where there are reliability needs, and they should be able to participate in the wholesale market. Energy storage projects will become a critical part of unlocking the full potential of clean energy and increasing the resiliency of the electrical grid.
What Was Learned?
According to a summary of transactive energy pilot programs supplied by SEPA, the electric utility industry has learned much in the past decade about transactive energy’s far-reaching potential to remake the power grid. According to SEPA documents, the designers of pilot programs identified tariff establishment and other policy changes as key early steps to pursue.
“Once this is in place, designers can focus on pursuing customers and vendors. However, the main lesson learned is that this form of transactive energy is effective,” SEPA authors wrote about the RATES pilot. “By pairing mechanics and transactions, and studying the thermodynamics of buildings where devices reside, the system can work reliably.”
Mark Knight, one of the coauthors of the report, said there are a lot of policy changes needed to pave the way for a transactive energy future.
“It’s illegal most places for me to sell my power if I produce my own because that means I’m acting as a utility and I can’t do that,” Knight said, adding that — in areas where there are no policy barriers — large facilities that make their own power, like college campuses or commercial and industrial complexes, might make their own markets.
The technology for allowing buildings and customers to trade and purchase power among one another is there. The thing that is missing is the economics and the market side of things. We could have it tomorrow from a tech perspective. The regulatory side and economics are kinds of preventing it.” With 50 states and 50 different utility commissions in the U.S., what is needed to move forward is some consistency and agreement on the benefits a transactive energy market could provide.
We can already envision one possible transactive energy application for large commercial and industrial consumers that involves electric vehicles (EVs). With the proper transactive energy topology applied, a large customer with a fleet of EVs could optimize their use of renewable energy and know when to charge EVs to maximize factors like cost and green energy use. The main thing we need to find out is the pattern of consumption. That would optimize the use of renewables and knowing when to charge your EVs to optimize that. We need computers to be able to forecast the wind and solar resource as well as the EV consumption patterns.
A second application would be a local-scale transactive energy system (TES) could forecast the wind and solar resources and then combine this data with high-powered computing and analytics solutions to optimize across different criteria, like energy cost and using more green power.
For both already feasible applications (1- large consumers with EVs and 2- local-local TES), the short-term objective for the grid operator could be to optimize the costs and maximize the benefit when exploiting on-site generation. There is still some resistance in the developed countries. In developing countries, the concept of Transactive Energy Technology is already welcome and expected in the near future. But in under-developed countries, it may take some time to accept/implement this concept. The Underdeveloped countries have a different prevalent socio-economic system and individual status may vary with respect to their purchase powers. In socialistic countries, the national power utilities/undertakings were set up to have government control on laying of tariff and even cross-subsidies are made to afford the purchase of power for various categories of consumers.
This article (in 2 sections) is part of 5 sections series by Stephane Bilodeau, Eng., PhD, FEC, on the Energy Storage near-future in the grid.