BOSTON — Clean energy storage could get a boost under grid resiliency legislation approved by the Massachusetts House of Representatives on Thursday.

Among other things, H.4739 instructs the Department of Energy Resources to study the feasibility of mobile battery storage systems. Such systems could take the place of downed substations in an emergency, said Rep. Thomas A. Golden Jr., D-Middlesex, chairman of the Joint Committee on Energy, Telecommunications, and Energy.

Around 450,000 households lost power during coastal storms in March, Golden said from the floor, highlighting the need for Massachusetts to “move into the future.”

Energy storage can shave peak power demand, relieve congestion on the grid, save money, and help reduce emissions, Golden said.

The House bill creates an Energy Storage Innovation Research Institute, and establishes a Center for Clean Transportation to conduct research and development.

On the resiliency side, it creates new requirements for utilities to assess and improve their transmission and distribution systems.

The utilities would have to submit annual reports including “heat maps” that show areas of load and congestion on the grid. Additionally, they would be urged to solicit competitive bids for “non-wires alternatives” — such as storage or demand response — when their lines need upgrades.

Grid resiliency means hardening regional power systems in the face of extreme weather or natural disasters, and such efforts must focus on “prevention, survivability, and recovery,” according to the Electric Power Research Institute.

The Baker administration in December awarded $20 million to help kick-start energy storage in Massachusetts.

The University of Massachusetts Amherst received one of the largest awards, $1.14 million, to install a lithium ion battery system in its energy supply system. Separately, Holyoke Gas & Electric built the state’s largest utility-scale storage system at its Mount Tom Solar plant.

Nationwide, the energy storage industry hopes to deploy 35 gigawatts of capacity by 2035.

Falling solar panel prices coupled with favorable national and state policies are giving energy storage technologies the jolt they need to electrify the market place. The latest such example is Pacific Gas & Electric that wants to install four battery projects totaling 2,270 megawatts.

Energy storage could be anything from shaving peak load to storing and injecting wind and solar electrons onto the grid.

“Energy storage plays an increasingly important role in California’s clean energy future, and while it has been a part of PG&E’s power mix for decades – starting with the Helms Pumped Storage Plant in the 1980’s – recent decreases in battery prices are enabling energy storage to become a competitive alternative to traditional solutions,” said Roy Kuga, vice president, grid integration and innovation, PG&E, in a release. 

“As a result, we believe that battery energy storage will be even more significant in enhancing overall grid reliability, integrating renewables, and helping customers save energy and money,” he added.

If the projects are approved by the California Public Utility Commission, the first of them will come online in 2019 while the others would follow a year later. California’s Independent System Operator is incorporating energy storage into mix of generation assets, as PG&E Corp., Sempra Energy and Edison International must collectively buy 1,325 megawatts of energy storage by 2020.

As for Pacific Gas & Electric, it would be replacing three natural gas-fired power plants owned by Calpine Corp. The utility picked three projects: 1,540 megawatts, 385.5 megawatts and 182.5 megawatts. It would also own one such project by itself, totaling 750 megawatts. The 1,540 project would be owned by Texas-based Vistra Energy and run by its Dynergy Marketing and Trade, which is different from the utility company Dynegy.

The Possibilities

The Brattle Group issued a study earlier this year that said energy storage markets could grow to as much as 50,000 megawatts over a decade if cost continue to fall and if federal policies that promoting the technology take root. Those policies must also be matched at the state level, it says.

Halfway through 2018 and large-scale battery storage in the UK has reached over 450MW installed capacity, with around 250MW being completed this year alone. This is made up of projects bigger than 1MW, including larger behind-the-meter projects that have begun to emerge.

The past few weeks have seen a flurry of activity with supply contracts being awarded, projects changing hands as well as those being completed. With sites under construction from the likes of Centrica, Anesco and Ørsted, and when projects from UK Power Reserve recently awarded to Fluence are factored in, it seems very like that the capacity installed in 2018 could reach over 500MW.

Uncertainty continues from the top

The challenge in financing energy storage is getting someone else to own it. Cost and availability of financing, in general, are directly tied to risk. The ample amount of capital looking to invest in energy looks for proven and simple. Storage is neither. Utilities’ defensive tariff filings are spurring market interest in the technology, but financing is still looking at it with lab coats on, and some people feel it will be that way for a long time.

Any analysis of battery economics starts with the problem needing a storage solution. Financing options unfold from there. Each of the numerous ways to use batteries calls for different hardware characteristics and properties, for specialized energy management systems (EMS) software, for engineering configurations and other considerations that impact the value received. Once those variables are established, then their performance must be modeled against the displaced utility power. If the model does not “pencil,” then available alternative tariffs must be researched against which to operate the storage.

Leading modeling company Energy Toolbase offers 30,000 rate schedules in the United States to help developers make sense of a battery application. None of that guarantees anything.

“Estimating the savings of an energy storage project is typically based on the historical interval usage data of customer,” Energy Toolbase’s COO Adam Gerza said. “But it’s challenging for developers to accurately model storage savings over the 10, 15 or 20-year term of the project, because utility rate tariffs constantly change, as does the shape of the customer’s load profile.”

None of this leads to eager third-party financiers.

Users and vendors are assuming the risks.

For those reasons, most C&I energy storage projects currently being built are funded by the user or the manufacturer. An end-user has all the standard options available for infrastructure upgrades: cash, credit or commercial PACE (C-PACE). As a C-PACE financing specialist, I arrange funding for a large number of solar/storage deals; hundreds of millions of dollars are eager to commit. For property owners it is the fastest and easiest way to get long-term capital, if they qualify. But C-PACE underwriting does not factor issues such as the IRS’ “75% cliff,” or whether the battery management system is proven over 15 years, or if the battery specs are bankable. C-PACE makes no commitment to a project’s success, beyond qualifying the contractor or EPC as being credible and compliant. The risk burden for the eventual viability of the installation rests primarily on the property owner.

Fortunately, some manufacturers are also doing their best to fill the void of third-party financing. Big and small industry names are financing their own product and engineered solutions. Energport, for example, sells designed and engineered systems using the batteries of Chinese manufacturer Gotion (Guoxin). According to its U.S. director of sales, Bobbie Muñoz, Energport offers five-year C&I leases for which the host’s monthly payment is 50% of the actualized savings, whatever they are, with a buy-out option at end of term. They also offer a ten-year, 70% version, with a $2 million project cost ceiling on those leases.

Socomec has won the Electrical Energy Storage prize at The Smarter E Europe exhibition held last month in Munich.

The exhibition hosts nearly 3,000 exhibitors presenting their latest solar energy solutions to 50,000 visitors.

The Electrical Energy Storage (EES) award recognises pioneering products and solutions for electrical energy storage systems. To select the winner, the jury considers the entire value-added chain of the technologies proposed, as well as the concrete applications and business models chosen.

The products and solutions candidates for the Award must demonstrate a particular technological and economic innovation, allowing the reduction of production or sales costs and that meet industrial or societal needs.

Energy storage for remote sites

This year Socomec proposed its energy storage system for microgrids, in particular the SUNSYS PCS2 IM converter. The solution provides electricity to a remote area while reducing the cost of building a new electrical grid. The system manages everything: power converters, batteries, energy sources… Designed for hybrid microgrids, the Socomec storage system is ideal for the electrification of rural or island areas. Among the many innovations proposed, Socomec stands out for its solution able to supply an isolated site completely autonomously thanks to renewable energies and energy storage.

A dedicated business unit for energy storage

“Socomec’s expertise in the control of low voltage energy conversion has been decisive in the development of energy storage solutions,” says Thierry Leroy, Director of the new Energy Storage Solutions Business Unit.

“The experience gained during the European Nice Grid and Nice Smart Valley pilot projects has enabled us to develop reliable and competitive storage solutions. This has led to the creation of a new entity within the Socomec Group dedicated to energy storage to enable us to control our development in a rapidly growing market.”

Delta has debuted its Battery Energy Storage Skid (BESS) Solution for industrial and commercial applications, as well as upgrades to its residential energy product portfolio, at Intersolar North America 2018. Delta’s pre-engineered BESS is a fully integrated battery storage system with PCS scalable from 125 kW to 500 kW, energy storage up to 2 MWh, and capable of adapting to the various energy, power and performance requirements of commercial energy users, including peak shaving, optimized load management, self-consumption and optimization of renewable energy sources. For the residential sector, Delta’s energy storage solution brings together the company’s leading E-series inverters along with top-of-the-line batteries to create an all-in-one turnkey solution that can be installed seamlessly in as few as 15 minutes.

“The shift to greater reliance on renewable energy, in combination with growing applications for battery power and microgrid-compatible solutions, has made power consumption more complex and dynamic than ever,” said M.S. Huang, president of Delta Electronics (Americas). “It’s critical that energy users have the infrastructure in place to adapt to long-term trends, and fluctuating daily energy demands, easily and quickly. Our BESS helps to fulfill this need for the industrial and commercial sectors, providing customers with an end-to-end solution, while our residential products continue to empower homeowners to take control of their energy consumption.”

Battery Energy Storage Skid Solution

Flexible in its design and able to scale up to a capacity of PCS 500 kW/ESS 2 MWh, Delta’s BESS provides an ideal solution for various power, capacity and cycle life needs. Developed for outdoor applications, the system is rugged and durable, with a compact and modular skid-mounted design based on industry standards for cabinet solutions. The format ensures that this investment is protected against harsh environmental conditions and continues to operate at maximum performance even in extreme temperatures.

The solution offers a variety of application advantages for users, including optimization of self-consumption from renewable and combined heat and power (CHP) systems. With Delta’s BESS, users can also capitalize on a range of grid services, including frequency regulation, renewables smoothing and power quality improvement, as well as facilitate demand charge management and time-of-use optimization. For those integrating electric vehicle (EV) charging stations into their facilities, Delta’s BESS can also provide charge management. Additionally, the solution can serve as a backup power supply, ensuring continuous operation in the event of grid power outages.

New York could go the extra mile under the energy storage roadmap released at the end of June.

The plan supports Democratic Gov. Andrew Cuomo’s energy storage target of 1,500 MW by 2025, but several sources say the final plan could call for an even more ambitious target. Reaching that target, though, could involve challenges that are largely outside of the scope of New York energy agencies.

The roadmap identifies near‐term policies, regulations, and initiatives needed to realize the governor’s 2025 target in anticipation of a 2030 target to be established later this year by the state’s Public Service Commission.

While higher storage targets will help with the growth of storage, the roadmap also addresses critical needs for clearer permitting guidelines. Progress for indoor siting is essential for deployment in congested areas like New York City, according to Doug Staker, vice president at energy storage developer Enel-X.

Shooting above the governor’s target

“The roadmap’s conclusion that the deployment of 2.8 GW to 3.6 GW of energy storage by 2030 would produce $3 billion in ratepayer benefits reinforces our expectation that the New York Public Service Commission could establish this December a 2030 storage target that builds upon and may likely exceed” Gov. Cuomo’s 1.5 GW by 2025 target, Timothy Fox, vice president at ClearView Energy Partners, told Utility Dive via email.

The 2,800 MW to 3,600 MW number laid out in the roadmap was the result of analysis by consulting firm Acelerex that examined system needs that can be met by energy storage in a least‐cost combination of resources as New York approaches its 50% by 2030 renewable portfolio standard target.

The report also says that analysis was “limited in its distribution system detail and consequently neither reflects an upper bound of ratepayer benefit nor maximizes the amount of storage that can be deployed in the state.”

“We see the ability to go up to 3,000 MW,” Bill Acker, executive director of the New York Battery and Energy Storage Technology consortium (NY-BEST), told Utility Dive. He said the document provides “a pathway” to reach a larger storage target by 2030.

The final target will “definitely be more than 1,500 MW” at the least because it is five years further out than the governor’s 2025 target, Jason Doling, program manager for energy storage at the New York State Energy Research and Development Authority, told Utility Dive. NYSERDA played a key role in the development of the roadmap.

A key factor when planning energy storage systems (ESS), for example for a microgrid, is to determine the expected cost savings and performance benefits provided by various ESS configurations.

Battery modelling offers a powerful way of predicting the lifetime performance and return on investment that will be provided by each ESS option.

Fuel savings are often a key factor in the choice of energy storage configuration, especially for microgrids which are often located in remote communities and rely on diesel generation, with logistical challenges around fuel delivery. However, cutting fuel consumption is just one of the purposes of battery modelling for microgrids.

Battery modelling techniques continue to evolve to better address the wider context of microgrid and renewable energy deployments. For example, simulations are now key to the project development process, as they deliver insights into renewable and storage applications ahead of deployment, and help determine how much power and energy are required overall.

Precise modelling

Modelling an entire microgrid at a high-level is a valuable exercise in assessing the viability of different deployments of renewable energy schemes with storage. However, when it comes to modelling the detail of these systems – such as bridging between multiple diesel generators in a large microgrid, or optimizing the set-points for operating with diesel generators in a smaller microgrid – more precise modelling is required.

High-frequency data, with granularity of no more than 10-minute intervals, is valuable. Such modelling provides insights into system operation, including diesel synchronization and cool-down times, to minimize diesel starts, maximize fuel savings and optimize battery life.

High-level modelling is typically based on hourly data, and the granularity of ESS dispatch is correspondingly coarse. This kind of modelling is feasible even with minimal data input.

For example, an initial model of a microgrid can be constructed with minimal inputs, such as the coordinates of an island village off the US Pacific coast having a peak load of 150 kW in January. Based on this information, high-level modelling can be used to construct a typical load profile, and location-specific solar or wind data can be downloaded.

The modelling software can then quickly carry out multiple simulations to discover the optimum renewable energy power rating, along with an appropriate level of energy storage. The results illustrate fuel savings and, if sufficient inputs are provided, ROI.

However, precise modelling requires more detailed inputs and time to optimize the dispatch methodology. Combining high-level and precise modelling leads to a more cohesive, informed insight into ESS requirements – in turn, enabling an accurate evaluation of a project’s viability, as well as the development of a detailed strategy to help ensure project success.

Investors’ focus and priorities shifting