Developers of energy storage projects have complained in the past that existing regulations regarding tax credits for energy storage force projects to operate in ways that do not necessarily make the best use of storage assets.

An energy storage project can make use of the ITC only if it is part of a solar power installation and meets specific criteria.

The energy storage device must be charged by the renewable resource 75% of the time, and falling under 100% renewable charging docks the tax credit by a commensurate amount. The rule also looks backward for the first several years of a project and so could threaten the tax credit at any point during that period.

Energy storage interests are now seeking to remedy that situation. They see an opening for energy storage in a potential tax extenders bill that has been talked about recently in the context of the pending tax cut legislation that Congress is expected to vote on soon.

In one view, the tax extenders bill would provide extensions for technologies that were left out, or orphaned in Beltway lingo, when the ITC and the production tax credit (PTC) were extended in a 2015 bill.

The letter by the ESA and other storage interests is a “direct response to public discussions of an energy tax extenders bill,” Jason Burwen told Utility Dive via email. The tax extender provisions could be part of a continuing resolution that Congress must pass by Dec. 22 in order to continue funding the government. The more likely vehicle, however, would be as part of a January omnibus bill.

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California is considering energy storage to replace two peaking plants and one larger facility, the 580 MW Metcalf plant. It is not the first time the state has turned to batteries for a grid solution, but shows how the solution is becoming increasingly viable.

The Yuba City and Feather River plants are each about 47.6 MW, and are needed for capacity and high voltage sub-area shortfalls, respectively. Last month, CAISO determined that the entire Metcalf Energy Center was necessary for local reliability needs in a sub-area of the Bay Area local capacity area.

The CPUC proposal would order PG&E to hold at least one one solicitation to address “two local sub-area capacity deficiencies and to manage a high voltage issue in another sub-area.” The utility can solicit bids for energy storage and other alternative energy resources individually or in aggregation. 

Regulators have embraced energy storage in other recent situations to replace capacity, such as the Aliso Canyon gas leak. 

In May 2016, the CPUC directed Southern California Edison (SCE) to conduct an expedited procurement for both utility-owned and third party storage resources to address the Aliso Canyon gas leak and resulting generator shortages.

It’s not the first time SCE was asked to consider energy storage as an alternative capacity resource: in 2013, the CPUC required the utility to procure a minimum amount of energy storage and other alternative resources, related to the closure of the San Onofre nuclear plant, and wound up far exceeding it. For storage alone, SCE’s target was 50 MW and more than 260 MW were procured. 

Gas plants, and proposals to build new ones, are increasingly drawingregulatory scrutiny, especially after the Los Angeles Times investigated whether the state was overbuilding the resource. Earlier this year, NRG Energy asked the California Energy Commission to suspend its application to build the 262 MW Puente natural gas facility.

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Energy storage deployments are growing rapidly, propelled by regulatory action, improving economics and utility moves to include the resource in their long-term planning. 

A total of 41.8 MW of energy storage projects were deployed in the third quarter, marking a 46% year-over-year increase from third quarter 2016, according to the latest Energy Storage Monitor from GTM Research and the Energy Storage Association.

There were also 10% more energy storage deployments in the third quarter than in the second quarter, which saw a total of 38.2 MW deployed, the report said.

Utility-scale projects lead

Utility-scale projects led the market in the third quarter, with a single 30 MW storage project in Texas accounting for about two-thirds of the quarter’s total. That also resulted in behind-the-meter installations taking a smaller share of the market, 26%, in the third quarter, compared with 42% in the second quarter.

In terms of duration, deployments dropped quarter over quarter as many utility scale projects had discharge durations of less than one hour. There were 42.5 MWh of energy storage projects deployed in the third quarter, a 5% increase year-over-year, but a 17% decline compared with the second quarter.

The Texas project put the Lone Star state at the top of the list for utility-scale deployments for the quarter. California topped the list for the non-residential market with 6.5 MW of deployments, and for the residential market with 1.87 MW of deployments. Hawaii ranked second in residential deployments in the quarter with 1.21 MW of projects and was third in non-residential deployments with 5 kW.

GTM expects a total of 295 MW of energy storage to be deployed in 2017, a 28% increase from the 231 MW deployed in 2016.

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Energy storage is increasingly being included in utilities’ chief planning tool: the integrated resource plans (IRP). That inclusion is a sign that utilities are beginning to see the value and benefits that energy storage brings.

“Utilities are becoming more active players in the energy storage market,” Brett Simon, energy storage analyst at GTM Research, told Utility Dive in an email.

A significant number of utilities now include energy storage in their IRPs, including Arizona Public Service, Tucson Electric Power, Florida Power and Light and Puget Sound Energy.

PG&E’s contract with EDF RE does not come as a surprise, Simon said. Like California’s other two investor owned utilities, PG&E is required to procure energy storage under AB 2514 that was passed in 2010.

Some foreign utilities have also shown an increased interest in the storage market over the last 12 to 24 months, Simon says, citing ENGIE and Enel.

ENGIE North America and Holyoke Gas & Electric in October said they plan to build a 3 MW, 6 MWh storage project at a Massachusetts solar farm that used to house a coal plant. Also in October, Enel told Bloomberg that the company is looking for energy storage acquisitions.

“This is a trend I’d expect to continue as storage economics continue to improve and utilities begin to explore new technologies to ensure effective system operations in the face of a changing grid,” Simon said

In the PG&E deal, EDF RE will build, own and operate a portfolio for PG&E that will include behind-the-meter battery storage projects for commercial and industrial customers in PG&E’s service territory.

The aim of the projects is to help C&I customers to lower their electric bills by reducing their demand charges and maximizing consumption during off-peak hours, as well as bringing in revenue by using storage to provide services to California’s wholesale power market.

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Since its inception, power generation has been notoriously difficult to build. Even once developers sort through regulatory preferences and siting difficulties, they still must construct huge slabs of modern industry on time and on budget — a feat that’s tripped up more than one utility in 2017.

Whether in a regulated or restructured state, building even relatively simple natural gas plants or grid upgrades can take years, and the process for more complex nuclear generators or transmission lines often stretches decades. The long lead times mean utilities must plan for new infrastructure many years in advance and make it difficult to respond to short-term changes on the grid.

But recent developments in California could prove to be a turning point. After the worst methane leak in United States history took the Aliso Canyon gas storage facility offline, California regulators early last year issued a series of mitigation measures, including energy efficiency programs and an expedited approval process for energy storage projects.

It was the opening the energy storage industry was waiting for. A year and a half from the decision, California utilities have deployed multiple long-duration storage applications, including installations from Tesla, AES and Greensmith/AltaGas.

The largest of these facilities is the 30 MW, 120 MWh Escondido energy storage project built by AES, and is one of the biggest lithium ion battery installations in the world. Built in about six months, it and a smaller, 7 MW battery provide daily ramping and peak shaving services for San Diego Gas & Electric — services typically delivered by gas generators.

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Energy storage is hot, but some new entrants into storage struggle financially. However companies, like CALMAC and Ice Energy that use cooled liquid storage, say their profits are robust.

Cooled liquid storage uses low-priced nighttime electricity to freeze or cool a liquid and then uses the chilled liquid to help offset electric air conditioning loads when power prices peak during the day. Even before the announced merger, CALMAC was working with Trane to integrate its ice storage tanks with Trane commercial HVAC systems to take pressure off of the energy grid.

CALMAC says its thermal storage systems reduce energy usage by roughly 35% by decreasing need for carbon-emitting peaking power plants. Its business model targeted building owners, wooing customers by simply cutting their electricity bills, and impacting how high demand charges from peaking air conditioner use can be controlled.

“We made the decision to join Trane because of our long tenure and history with Trane’s people, application expertise and system design,” CALMAC President Mark MacCracken, said in a statement.

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The recently revamped SGIP program closed its first funding round in May with $90 million allocated for energy storage projects.

The program has a total of $566 million in funds for clean energy programs, of which 79% are earmarked for energy storage. Under the PUC’s new program, enacted pursuant to AB 1550, 25% of the funds will be earmarked for low income communities, defined as those at or below 80% of the statewide median income or with median household incomes at or below the threshold designated as low income by the Department of Housing and Community Development.

The new program also applies to state and local government agencies, educational institutions, non-profits and small businesses that are located in disadvantaged communities.

“Our actions make the Self-Generation Incentive Program more equitable without increasing consumer costs,” Clifford Rechtschaffen, the PUC commissioner assigned to the proceeding, said in a statement announcing the program.

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Enel subsidiary Enel Green Power North America in August closed on the acquisition of EnerNOC, paying about $250 million for the energy management company. Earlier this year, Enel Green Power bought Demand Energy Networks, showing an appetite for energy management sector. Now it appears the utility is eyeing energy storage. 

Speaking at a conference in Moscow, Starace told Bloomberg that Enel is looking for acquisitions in energy storage as the technology becomes more widespread and important in balancing the intermittency of the growing amount of renewables on grids in Europe and North America. Starace said there are already regions where batteries are commercially attractive, including the U.S., Europe and Latin America. 

European utilities are showing an increasing interest in energy storage. In July, French oil company Total completed the $1 billion acquisition of battery maker Saft. In December 2015, Germany’s E.on invested in energy storage software company Greensmith Energy Management. Greensmith was later acquired by Finnish power system manufacturer Wartsila in a $170 million deal.

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Grid operators around the world continue to recognize the benefits of energy storage technologies, and one of the most intriguing applications is the ability to defer investments in conventional transmission and distribution (T&D) infrastructure.

Energy storage systems (ESSs) providing T&D upgrade deferral can be a disruptive force in the industry as they allow for a more efficient deployment of capital to meet evolving grid needs and can enable the development of new business models. T&D upgrade deferral ensures that electricity lines, substations and other equipment have enough bandwidth to handle peak demand. Navigant Research’s recent report, Energy Storage for Transmission and Distribution Upgrade Deferral, takes an in-depth look at both the opportunities and challenges in this market.

T&D systems adapt to end-user needs and the placement of generation assets. This is becoming increasingly complex because of changing demand patterns, congestion due to the development of renewable generation in remote areas, and the desire to improve the reliability of electricity supply for customers that have a growing number of alternative options to meet their electricity needs. At the same time, developing T&D systems is becoming more expensive and challenging in much of the world, leading to the demand for ESSs as an alternative to the traditional investments utilities have relied on for decades.

Falling costs, faster build times, and a smaller physical footprint make energy storage an attractive option for utilities facing the need for T&D upgrades. The table below summarizes the challenges facing T&D investments and the benefits provided by ESSs.

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Hawaiian Electric Co. (HECO) has big plans for energy storage, but is wary of moving too quickly. The utility is looking for better storage technology and economics before moving too much on deployment.

The island state is often considered a test case or laboratory for the integration of renewable energy. With a 100% renewable portfolio standard in Hawaii and a 2045 target date, the state’s main utility is quite focused on what its generation mix is going to be and how it is going to get there.

The utility is expecting 2,700 MW of energy storage on Oahu by 2030, said Colton Ching, senior vice president for planning and technology at HECO. That includes both customer sited, behind-the-meter batteries and utility-scale energy storage installations, either owned by the utility or competitively bid to a third party. But HECO has been slow to embrace energy storage, despite the rapid influx of solar power in the state.

Hawaii has the highest solar penetration of any state. There are already 80,000 rooftops with solar panels and HECO expects that number to double by 2030. But so far, the utility has only 3 MW of utility-scale storage projects, and all three of those were pilot projects.

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