What are energy storage projects under federal law? Are they eligible for certain favorable long-term contracts with utilities? Or are they subject to less attractive rules and regulations that apply to solar energy?

That’s the question that Franklin Energy, which develops distributed energy resources, is asking in Idaho, where it has proposed four energy storage facilities, each 25 MW.

In doing so, Franklin Energy is raising fundamental questions about how energy storage, a relative newcomer on the energy scene, fits in with a 40-year-old law known as the Public Utility Regulatory Policies Act, or PURPA.

PURPA requires electric utilities to buy power from other producers, if the cost is less than or equal to the utility’s avoided cost rate to the consumer. Right now, most energy storage projects are developed by utilities, businesses and for pilot projects. However, as prices for energy storage drop, more and more energy companies like Franklin Energy are expected to propose projects and seek contracts with utilities. That’s most likely to happen in areas where energy storage is less expensive than the utility’s avoided costs, or the marginal costs of producing power.

Now before the Federal Energy Regulatory Commission (FERC), the issue involves four energy storage facilities, each owned by a different entity. They meet the standards for being qualifying facilities (QF) that, under PURPA, are eligible to seek contracts with utilities.  The question is: Should they receive Idaho Power’s more attractive long-term contracts and rates?

The precedent-setting case raises interesting questions about the definition of energy storage projects as qualifying facilities, said Richardson.

“This is the only PURPA battery storage project in the country that I could find,” he said. All the other battery projects he could identify are utility-owned, developed for companies’ own use, or pilot projects.

Franklin Energy knew it was taking a risk when it proposed the projects as qualifying facilities and waded into unknown territory, he said.

“We’re making this a shotgun wedding under PURPA. We knew what we were getting into,” Richardson said.

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Over the last few weeks, the state of Puerto Rico’s electrical grid has been on everyone’s mind in the power industry. Getting Puerto Rico back online has been the Puerto Rico Electric Power Authority’s (PREPA) top priority, and rightfully so. The devastated country’s grid was knocked almost entirely offline.

Efforts now are focused on getting everyone’s lights back on as soon as possible – not necessarily building out an impressive, ground-breaking new electrical system in the process. Utilities and suppliers across the United States have come together to help rebuild Puerto Rico, but rebuilding should just be the first step. We also need to look to solve Puerto Rico’s long-term power needs.

Once Puerto Rico is back on solid ground, with power running across the country, then the time will come to discuss what to do next.

This U.S. island commonwealth is at great risk for similar destruction the next time a large tropical storm or hurricane rolls through. There is no simple solution to harden the island’s grid, but recent events prove that change needs to happen to address future events.

Even before Hurricane Maria hit, Puerto Rico did not have the most reliable grid. While it is difficult to think about long-term solutions when so much needs to be rebuilt, improving grid reliability and resiliency should be a priority. With that in mind, what if the utility moved to an underground distribution system (at least in part) instead of an entirely overhead distribution system?

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Duke University brain science researchers are hoping to use electronics they developed for non-invasive brain stimulation to revolutionize energy storage technology, making batteries safer, more efficient and less expensive.

The idea to apply brain science technologies to battery technology came from Stefan Goetz, an assistant professor of psychiatry and behavioral science, electrical engineering and neurosurgery, along with a colleague, Angel Peterchev, associate professor in psychiatry and behavioral sciences.

For more than a decade Goetz has been creating electronics for non-invasive brain stimulation that allow signals from outside the brain to be processed and acted on inside the brain, he explained.

However, he also had some experience with cars. “I started my Ph.D with an advisor who was a power engineer who worked on drives for vehicles,” he said. “I knew a little about it and recognized the problems with batteries. It appeared to me they could be solved if you modified some of the circuits.”

He and his colleagues started looking for funding. They received funding from Duke University’s Energy Research Seed Fund for developing a prototype battery and conversion system, $500,000 from the National Science Foundation for developing, along with other researchers, control systems to optimize use of the battery system, plus car-part donations from Toyota and BMW, said Goetz.

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Stacking energy storage values — capturing many value streams — can lead to profitable projects, even at current storage costs, according to a new report from economists at The Brattle Group.

The report, “Stacked Benefits: Comprehensively Valuing Battery Storage in California,” focuses on California, but its conclusions apply generally to the entire U.S., said Ryan Hledik, principal with Brattle.

Brattle conducted models and simulations using a 1-MW battery — which provides four hours of storage — and estimated the comprehensive savings associated with “stacking” battery storage uses, or operating batteries to capture the benefits from a number of value streams. Energy storage advocates say stacking is critical to take advantage of battery benefits.

The economists identified costs for utilities and others to acquire certain services, including energy, capacity and frequency regulation, and concluded that using batteries for these services could save $280/kW annually. That amount could be captured through utility bill reductions, by avoiding retail rates, or through a third party (an aggregator, for example) selling demand response into the market, said Hledik.

“We calculated the total system-level value that could be captured and divided it up among parties, depending on the situation,” said Roger Lueken, associate with The Brattle Group.

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While the devastation of Hurricane Harvey and the West’s wildfires are fresh in our minds, it’s critical to start focusing on grid resiliency — and how distributed energy can contribute to it.

Utilities and state regulators right now focus more on grid reliability than grid resiliency, said Kelly Speakes-Backman, CEO of the Energy Storage Association (ESA). But the two are very different.

“Reliability is about normal operations and the grid being able to run with scheduled down times of generation and scheduled operations and maintenance — to be able to count on it when you’ve scheduled it,” she said.

Resilience is all about being able to withstand or recover from the unplanned

Resilience, on the other hand, is all about being able to withstand or recover from the unplanned—the hurricanes, storms and wildfires we’re experiencing more often and with more intensity right now. “Everything that is non-planned has to do with resilience,” she said. Surprise disturbances also include cyber and other attacks on the grid, she said.

Resilience is needed during these “extraordinary and hazardous catastrophes utterly unlike the blue sky days during which utilities typically operate,” said a 2014 report by the National Association of Regulatory Utility Commissioners, “Resilience for Black Sky Days.” The report suggests that state regulators consider investments in resilience.

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Microgrids and energy storage improve electric reliability. So it was perplexing to see how little attention they received in a major study on grid reliability issued this week by the U.S. Department of Energy.

Businesses, communities and institutions across the country have stepped up installation of microgrids in recent years to ensure power supply when the central grid fails. Since Superstorm Sandy, states have dedicated at least $200 million for microgrid installations. And in 2016, alone, utilities put up at least $1.2 billion to pursue microgrids and related distributed energy.

Yet the federal government mentioned microgrids only twice – and briefly – in its 181-page”Staff Report to the Secretary on Electricity Markets and Reliability.” Energy storage did a bit better with three paragraphs and a chart.

“This is supposed to be a reliability report, but it focuses on generation and transmission,” said Steve Pullins, vice president for energy solutions at Hitachi America. “With 90 percent of the events that lead to a customer outage initiating in the distribution network, only 10 percent of those events have anything to do with generation and transmission. So why does the report focus > 90 percent of its attention on the 10 percent problem?”

He added: “As far as I am concerned, this report is only 10 percent relevant to reliability. I am greatly disappointed. This will be in my book on ‘Missing the Point.’”

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If you’ve heard that energy storage can reduce what you pay in demand charges, and you’re wondering if it would work for your operation, check out a paper issued today by the National Renewable Energy Laboratory (NREL) and Clean Energy Group (CEG).

The paper finds that 25 percent of commercial customers in the U.S. – five million – pay demand charge rates of more than $15/kW, a threshold that may justify investment in energy storage.

“With this analysis, we have identified the areas where customers have the greatest potential to benefit from investments in battery storage. Utilities know where these opportunities exist, and now the rest of us have that information too,” said Seth Mullendore, co-author of “Identifying Potential Markets for Behind-the-Meter Battery Energy Storage: A Survey of U.S. Demand Charges,” and a CEG project director.

The report notes that many customers do not fully understand how demand is measured and billed — despite the fact that demand charges often represent from 30–70 percent of a commercial electric bill.

Defining demand charges

Demand charges are a somewhat murky and daunting. Applied to commercial and industrial customers (not usually homeowners), they are typically calculated based on the point in time when wholesale prices are highest. If a company can pinpoint that 15 minutes or so and reduce its consumption, it can lower its energy bills for the billing cycle.  To do so, the company must predict correctly when the grid will reach that period of peak demand and then act fast.

Battery energy storage is a particularly good tool for the task because of its flexibility; it’s relatively easy to discharge the battery so that your facility uses its energy – rather than grid power – at the right moment. On-site solar can be used to reduce demand charges too, but not if the sky is cloudy just then.

Battery software is a key factor here. Advanced platforms use what the report calls “learning algorithms” to gauge when a facility is approaching peak demand. Add solar and the management software can employ a more sophisticated demand management strategy. It may make sense to incorporate microgrid-level intelligence if more forms of distributed energy are added to the system. Or, as the paper points out, a microgrid may be warranted if the facility wants the added ability to island and secure power from its onsite resources during an outage.

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Green Charge Networks, Stem, and Sunverge top a new list published by Navigant of companies that lead in distributed energy storage.

The energy storage leaders are driving growing use of the resource as means to lower costs for customers and for the larger grid. Commercial buildings use energy storage for back-up power during outages and to reduce their utility demand charges. Meanwhile, energy storage also can act as a virtual power plant and provide a capacity resource for the grid.

“Leaders in the distributed-scale ESS sector have built on innovative software platform capabilities to focus on playing multiple roles across the delivery value chain,” says William Tokash, senior research analyst with Navigant Research. “As a result, they can drive down costs, enable financing innovation, and establish customer access advantages relative to their peers.

An executive summary of the report,  Navigant Research Leaderboard Report: Distributed-Scale Energy Storage Systems Integrators, is available on Navigant’s website.

Other energy storage leaders on Navigant’s list are: Johnson Controls, Advanced Microgrid Solutions, Tesla/SolarCity, Sharp, sonnen, Greensmith and Lockheed Martin Energy.

And speaking of energy storage leaders…

Energy industry veteran Kelly Speakes-Backman will become the Energy Storage Association’s first chief executive officer on July 1.  Speakes-Backman joins ESA from the Alliance to Save Energy, where she was senior vice president of policy and research.

As part of the organizational change, Matt Roberts’ role will change from executive director to vice president.

ESA is making the changes to ramp up its push for 35 GW of energy storage by 2025.

Big leadership changes underway in New York too

New moves also are underway at the New York State Energy Research and Development Authority (NYSERDA), where Massachusetts clean energy veteran Alicia Barton is now president and CEO.  Barton takes over from John Rhodes, who became chair of the Public Service Commission. He replaces Audrey Zibelman, who joined the Australian Energy Market Operator.

Barton was most recently at the law firm of Foley Hoag in Boston and previously worked as chief of operations for the Global Utility group at SunEdison. She also served as CEO of the Massachusetts Clean Energy Center (MassCEC), a quasi-public agency.

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Described in a recent report as the “undisputed king” of the energy storage industry, California continues to blaze new trails, now with legislation to boost customer-sited energy storage.

The California Senate recently passed SB 700, which creates incentives for customer-sited energy storage in homes, schools, farms and businesses. Next, the bill moves to the state Assembly.

The 10-year rebate program, called the Energy Storage Initiative, provides up to $1.4 billion and lets the PUC set the total amount, said Laura Gray, energy storage policy advisor with the California Solar Energy Industries Association. It aims to make storage more accessible to consumers.

“California is once again showing its leadership on clean energy. Just as the state revolutionized solar, it has the opportunity to transform the market of customer-sited energy storage,” Gray said. “With this bill California would be the first state to create a market transformational program dedicated to local energy storage.”

Undisputed king for next five years

Separately, GTM Research and the Energy Storage Association (ESA) reported this week that California “will remain the undisputed king of the U.S. storage market over the next five years.”  Arizona, Hawaii, Massachusetts, New York and Texas vie for second place.

California helped drive what proved to be a record-breaking first quarter for energy storage in the United States. GTM and ESA’s latest “U.S. Energy Storage Monitor” reported that 234 MWh of energy storage was deployed, a 944 percent rise over the first quarter last year.

Ravi Manghani, GTM Research’s director of energy storage, attributed the big leap in part to a large battery deployment made to bolster reliability following natural gas leaks at California’s Aliso Canyon.

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