This summer, Massachusetts became the third state to set an energy storage target. It is not mandatory, and the 200 MWh target was lower than some observers expected, but it still put the Bay State at the top of states encouraging energy storage.

Massachusetts is now continuing to push forward with energy storage, setting up an inquiry into the eligibility of energy storage for net metering benefits. Net metering is a popular policy mechanism that compensates distributed generation for excess energy sent to the grid — usually at the retail rate. Net metering policies vary by state and can include larger projects than typically found on residential rooftops. 

However, the policy is silent on the role of energy storage when paired with net-metered systems, like rooftop solar. 

But stakeholders are seeking to define energy storage’s role, with Massachusetts taking that first step. In part, the inquiry grew out of a petition filed by Tesla in May 2017, seeking a ruling on the eligibility of solar power systems paired with energy storage devices to receive net metering benefits. Last month, the DPU issued a “limited scope” advisory opinion, only applicable to Tesla, that small-scale battery storage and solar systems should be eligible for net metering. 

State regulators will now take up that issue holistically in this inquiry.

The inquiry will also review the current standards and procedures that electric distribution companies use to bid the capacity from certain net metering facilities into ISO-New England’s FCM, and how they use FCM revenues to offset the cost of net metering services.

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Energy storage is a good option for frequency response, a storage trade group will tell the Federal Energy Regulatory Commission this month.

Markets would be less efficient and “system costs greater than necessary if resource owners are mandated to provide frequency response service from generators more suited to provide energy and capacity,” the Energy Storage Association wrote in previously filed comments. 

The group is responding to FERC’s request for supplemental comment on its November 2016 notice of proposed rulemaking (NOPR) to begin the process of revising its interconnection rules for both large and small generators. FERC’s concern was that fewer generators were providing primary frequency response.

According to ESA, requiring generators to provide frequency response could produce an oversupply of frequency response headroom, imposing additional system costs. The group noted that many generators are not well suited to provide frequency response because doing so can lower operational efficiency, which will eventually result in higher system costs. Additionally, requiring all generators to provide frequency response would fail to create a market signal.

On the other hand, energy storage, particularly batteries, are well suited to provide frequency response, ESA said. They are fast responding and do not lose efficiency by needing to reserve headroom. In its comments, ESA cited studies by the Electric Reliability Council of Texas that found 1 MW of fast responding resources could be substituted for 2 MW of primary frequency response resources during some system conditions.

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Green Charge said it expects to complete installation of the Mt. Tom energy storage project by April 2018 in time for peak summer demand when capacity costs are highest.

HG&E said it will use storage system to reduce the burden on its electrical distribution system, increasing overall asset life.

Electricity from the solar farm will be stored in the storage system and will be called on during local and regional peak load periods.

The project won a $475,000 grant from the Massachusetts Department of Energy Resources as part of the state’s Peak Demand Management Program. The funds will be used to contract with, schedule, measure and analyze the storage system. The goal of the grant is to provide research and recommendations on the future distribution system value of battery storage devices throughout the state.

“We are pleased to work with ENGIE on the Mt. Tom energy storage project, which will produce peak demand and asset management benefits that will help HG&E stabilize electric rates over the long term,” Jim Lavelle, HG&E’s manager, said in a statement.

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One of the reasons California is a leader in energy storage are the multiple laws aimed at encouraging and supporting the technology, including AB 2514, enacted in 2010, that directs utilities in the state to energy storage resources.

The most recent energy storage related legislation, AB 546, is aimed at helping communities navigate the often confusing process of obtaining permits for energy storage projects. Though there are multiple state mechanisms for encouraging energy storage, the process can be very confusing.

AB 546 aims to speed that process by directing communities of 200,000 and more to provide web based resources and to provide a basis for making the permitting process and related fees more consistent from community to community.

The bill says that the implementation of energy storage is “not a municipal affair, but is a matter of statewide concern.”

The bill comes as municipal utilities invest in energy storage to meet ambitious renewable energy goals. 

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Senators rushed to file a slate of energy storage bills in recent days ahead of hearings on the subject scheduled for next week. 

On Tuesday, the House Energy & Commerce Committee will question energy industry leaders on reliability and resilience. At the same time, the Senate Committee on Energy and Natural Resources will hold a hearing specifically on energy storage. 

Those events could bring attention to the new legislation aimed at boosting federal support for the emerging technology. At a discussion hosted by the Advanced Energy Storage Caucus on Wednesday, industry leaders said they hope to cast energy storage as a resource that “helps everyone,” aiming to avoid the partisan divides that characterize support for renewables or fossil fuels on Capitol Hill. 

“Energy storage as infrastructure is enough of a bipartisan topic,” Ted Ko, vice president for policy at Stem, said about the Franken bill, which would fund storage R&D for grid resilience. “There’s a dozen different critical infrastructures in the U.S. and energy is probably the one the others all depend on, so investing in R&D for that is I think a bipartisan issue that should give that legislation a little more legs.”

Provisions for DOE demonstration projects and technical assistance on storage could help utilities integrate the new technology into their long-term generation planning, said Jason Burwen, policy and advocacy director at the Energy Storage Association.

“There’s a recognition of putting storage into the planning processes of utilities, particularly of smaller utilities and munis and co-ops that may not have human capital and may be resource constrained,” he said. “That’s going to be transformative for those folks to figure out how does this cost-benefit work out … how do we value the resilience aspects and then how do we make this make sense not just for a one-off procurement but part of a long term resource plan?”

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Spikes in solar power during the day can lead to negative power prices and the curtailment of solar power output. In spring 2017, low demand and high solar production routinely pushed spot prices below zero, stressing generator finances. 

CAISO has been exploring ways to deal with that problem. One of the solutions on the table, termed “load consumption,” was to incentivize the consumption of more electricity during periods of high renewable energy generation — “paid to wastefully consume energy,” as CAISO put it.

But CAISO stakeholders such as Tesla, Stem and Green Charge Networks argued in favor of an alternative storage product that would shift peak solar output by absorbing peak energy and storing it for later use.

In a presentation, John Goodin, manager of infrastructure and regulatory policy for CAISO, said a “load shift” product would ensure excess power is “used productively at a different time to the benefit of the economy and environment” and would “avoid increasing the economy’s energy intensity.”

The proposed load-shifting product falls under the third phase of CAISO’s Energy Storage Distributed Energy Resource (ESDER) program. The proposal is still in its early stages and will require several rounds of comment before it is sent for approval by the California Public Utilities Commission and the Federal Energy Regulatory Commission.

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California is a leader in both renewable energy resources and energy storage. The state has one of the highest renewable portfolio standards in the U.S., mandating that 50% of all electric power be sourced from renewable resources by 2030, and the state has the first and some of the most robust incentives for energy storage.

AB 2514 requires the state’s three investor owned utilities to procure 1.3 GW of energy storage by 2020, and AB 2868 requires each IOU to deploy an additional 166 MW of behind-the-meter and/or distribution tied storage.

The IOUs are already well on their way to meet their goals. Southern California Edison has 400 MW of storage in its portfolio toward its 582 MW target. But installing energy storage is one thing, using it to meet other goals is another.

California is a restructured state, so utilities there generally do not own or build power plants. Nor do utilities control the dispatch of those plants. That is the job of the California ISO.

Soaking up solar power during the day and dispatching it in the evening is often cited as a renewable-enabling use for energy storage, but in practice the renewable-enabling potential of storage is often not so simple.

SCE, for instance, does not necessarily make decisions to charge batteries when solar power output is abundant and to discharge them when solar power begins to wane. But the utility still owns some generation assets and is responsible for how it bids those assets into CAISO’s real-time and day-ahead energy markets.

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The fact that California’s three investor-owned utilities were at the top of the Smart Electric Power Alliance’s recent rankings is not surprising, but the presence of utilities in Indiana and Ohio is notable.

California has been a leader in energy storage, with a 2010 law that requires the state’s IOUs to procure 1.3 GW of storage capacity by 2020 and then a 2016 law requiring each IOU to procure another 166 MW of storage.

There has been no similar legislative push in either Indiana or Ohio and yet Indianapolis Power & Light and Duke Energy Ohio were third and fifth, respectively, in SEPA’s rankings of utilities that connected the most energy storage to their systems in 2016. IPL installed 20 MW in 2016, and 16 MW were connected to Duke Energy Ohio last year.

The rankings do not tally how much energy storage a utility built or owns, but how much was connected to their system. So while IPL built and owns the storage facility in its territory, Duke does not own the 16 MW of storage that connected to its system in 2016. Similarly, while California’s utilities are permitted to own some energy storage assets, they do not necessarily own all the storage facilities connected to their systems.

Measured by energy (MWh), IPL ranked fourth with 20 MWh, and Duke Energy Ohio ranked eighth with 6.1 MWh.

Ranked by energy storage watts per customer, IPL and Duke actually beat the California utilities, ranking fifth and sixth with 42 W/customer and 23 W/customer, respectively.

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Lithium-ion batteries have the lion’s share of the stationary battery storage market, giving many manufacturers the opportunity to realize economies of scale, but on the flipside, makes it that much harder for new technologies to gain a foothold in the market.

So far this year, at least two battery manufacturers working on novel technologies have declared bankruptcy.

In March, Aquion Energy filed for bankruptcy. Aquion was known for its aqueous hybrid ion battery technology, which the company touted as a safer and cheaper alternative to li-ion batteries. Aquion emerged from bankruptcy last month, being acquired at auction by Juline-Titans LLC, a company about which little is known except that it has ties to the China Titans Energy Technology Group.

And late last week, Alevo USA and Alevo Manufacturing, both part of Alevo Group, filed for Chapter 11 bankruptcy court protection. At one point, Alevo was seen as a rival to Tesla. In 2014, the company said it planned to invest $1 billion to convert an old Philip Morris cigarette factory in North Caroline to a sleek new facility capable of producing several gigawatts of batteries a year.

Alevo was also trying to gain a market edge with a lithium-iron-phosphate battery chemistry that it claimed would be the first to use an inorganic electrolyte based on sulfur. The company said that chemistry would allow its batteries to cycle more frequently and with less heat and degradation than li-ion batteries.

Alevo had a three-pronged approach to the market. It planned to target state-owned utilities overseas, individual utilities, especially in the United States, and to tap commercial markets such as the market for frequency regulation in the PJM Interconnection region.

Alevo also did not want to limit itself to just selling batteries. It was looking to sell storage as a service. That may have been easier than convincing a developer of the merits of its technology, but it also meant that in addition to competing against established, incumbent li-ion battery manufacturers such as Tesla and Panasonic, Alevo was also taking on companies such as AES Energy Storage, Greensmith and S&C Electric.

The company also shunned government funding, relying instead on private investors, including funding from Russian oligarch Dmitry Rybolovlev.

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The rules for New Mexico’s IRP only state that investor-owned electric and gas utilities’ resource planning processes have to evaluate all feasible “supply side” and “demand side” resources on a “comparable and consistent basis.” The rules were written before energy storage was a commercially feasible alternative to supply-side and demand-side resources.

In the amendment, PRC staff noted that energy storage’s benefits can occur at any stage, from generation of electricity to transmission and distribution.

Staff suggested it would be helpful to the policy development to require utilities to produce a cost/benefit analysis of energy storage options considered, and why they were rejected.

PNM is the only utility in New Mexico with energy storage capability at present. PNM’s Prosperity Energy Storage project includes a 500 kV solar PV facility with a 250kW, 1 MWh energy storage system.

“All of the participants in this rulemaking case, including our three investor-owned utilities, supported this amendment to the IRP rule, a consensus reflecting that energy storage should be considered as a resource in New Mexico’s utilities’ long-term planning,” Commission Vice Chair Cynthia Hall said in a statement.

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