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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There’s a difference between knowing why energy storage is so useful to integrating wind and solar power into the grid, and being able to prove it to a banker. They’re going to want to know all the details in between, such as: Has anyone ever been paid for performing these tasks? If so, how much? And can we get that price in a 10-year contract? 

To be sure, we’ve seen hundreds of megawatts of energy storage bankrolled through utility contracts, as in California, or to serve once-lucrative frequency regulation services, as in the territory of mid-Atlantic grid operator PJM. 

But the structures aren’t quite there yet for energy storage to provide the bankable revenue streams that wind and solar project financial backers need to make deals — even if the desire for them is peaking. 

“The reality is that storage hasn’t been widely financed yet, and we’re still several years away,” Ravina Advani, managing director of BNP Paribas’ power and infrastructure project finance group, said during a webinar on merchant power trends held Wednesday by the American Council on Renewable Energy (ACORE) and Bloomberg New Energy Finance. “Financing with a renewal asset,” on the other hand, “I think is something the market hasn’t yet seen — but it’s an up-and-coming trend.”

Wednesday’s storage discussion came during a broader overview of merchant power industry trends, from the latest BNEF data on global clean energy investments, to forecasts on solar industry impacts from the Suniva trade case.

But for renewables, the key long-term market trends are the shift from state renewable portfolio standards, power-purchase agreements and renewable energy credits as key drivers, to a world in which corporate investors, community choice aggregators and the Public Utility Regulatory Policies Act (PURPA) are playing a larger role, said Steve Doyon, CEO of Novatus Energy. Energy storage “could help renewables transition to that type of market.”

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In the second quarter of 2017, 443 residential and commercial energy systems were deployed across the United States, representing 32 megawatt-hours of capacity.

According to GTM Research and the Energy Storage Association’s (ESA) U.S. Energy Storage Monitor, this is the most grid-interactive behind-the-meter energy storage ever deployed in a single quarter.

Danish company Vestas Wind Systems is one of the biggest makers of wind turbines in the world, recently surpassing GE’s market share in the US. But as the wind industry becomes more competitive, Vestas appears to be looking for ways to solidify its lead by offering something different. Now, the company says it’s looking into building wind turbines with battery storage onsite.

According to a Bloomberg report, Vestas is working on 10 projects that will add storage to wind installations, and Tesla is collaborating on at least one of those projects. Vestas says the cooperation between the two companies isn’t a formal partnership, and Tesla hasn’t commented on the nature of its work with Vestas. But the efforts to combine wind turbines with battery storage offer a glimpse into how the wind industry might change in the future.

The news about Vestas is just one datapoint in a summer of news about wind and storage projects. In August, offshore wind developer Deepwater Wind announced that it would pair a 144MW offshore wind farm planned for the coast of New Bedford, Massachusetts, with a 40MWh battery storage system from Tesla. Construction on that project is set to end sometime in 2022. According to GreenTechMedia, Spanish wind power company Acciona recently connected two Samsung lithium-ion batteries to a 3-megawatt turbine in Spain, Dong installed a battery on the UK coastline in June to store some offshore wind energy, and Statoil will include a 1MWh lithium-ion battery in its designs for a floating offshore wind farm that will be completed in late 2018.

The idea of onsite batteries isn’t new—GE’s renewables arm introduced short-term batteries integrated with wind turbines in 2013, and Vestas itself experimented with tying storage to wind turbines in 2012. But turbine manufacturers seem to be more willing to branch out of their wheelhouse lately and contact battery specialists instead of pushing to build batteries on their own.

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In early August, I spent three days at the Energy Storage North America (ESNA) conference in San Diego. One key take-away was from the keynote delivered by Ronald Nichols, President of Southern California Electric. At one point he flatly asserted that for every utility represented by an attendee in the crowd, there is a viable and cost-effective storage opportunity somewhere on their grid today. That is a revolutionary statement, and something that would have surprised most industry observers just a few years ago.

However, that statement probably would not have surprised the leaders of AES Energy Storage. Those of us with long memories will recall that AES has been delivering utility-scale storage projects for over a decade, with projects deployed, under construction or in development in seven countries. The company currently boasts the largest lithium-ion battery-based energy storage project in the world (30 megawatts and 120 megawatthours) – built in partnership with San Diego Gas and Electric (SDG&E), to help meet peak electricity demand within its service territory in southern California. AES Energy Storage also indicates it has delivered over four million megawatt-hours of service to date. No other competitor in the battery storage space has a track record remotely close to that.

Given its heft in the market, AES Energy Storage is still surprisingly small, consisting of approximately 70 core team employees who focus on the development of storage solutions platforms. AES sells its Advancion energy storage platform and related services to multiple customers, including utilities and regional business units of the AES Corporation (AES Energy Storage’s parent company) in 17 countries, utilities like SDG&E and Arizona Public Service, and other entities who undertake power project development.

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The secret to switching the global energy system entirely to renewables may lay in the universe’s most abundant substance.

Hydrogen has drawn backing from big energy companies from Royal Dutch Shell Plc to Uniper SE in addition to carmakers BMW AG and Audi AG. They’re supporting research into how the element can be used to store energy for weeks or even months beyond what lithium-ion batteries can manage.

While industry’s investment in hydrogen is small at just $2.5 billion over the last decade, the work offers an answer to the elusive question of how electricity could be kept for use in the future. Batteries increasingly are shifting power from day to night, but they tend to go flat after a few weeks. Hydrogen can be kept indefinitely in tanks. That would allow, for example, voltage collected from solar panels in the summer to be used in winter.

“The years 2020 to 2030 will be for hydrogen what the 1990s were for solar and wind,” said Pierre-Etienne Franc and vice president of advanced business and technologies at the French industrial gas maker Air Liquide SA and initiative secretary of the Hydrogen Council, a trade group promoting the work. “It’s a real strategic shift.”

The technology to use hydrogen as energy storage is well known, although not yet demonstrated in a commercial setting.

Excess power from wind or photovoltaics would drive electrolysis, separating water into its component hydrogen and oxygen elements. The hydrogen captured by that process could, whenever needed, feed natural gas power plants or fuel cells to make electricity. Industrial plants like oil refineries can also use hydrogen for chemical processes.

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Collaboration with NY BEST and DNV GL

California will soon release an updated evaluation of greenhouse gas emissions from storage systems participating in the Self-Generation Incentive Program. Unfortunately, due to incomplete policies and methodology, the state may again reinforce the erroneous narrative that customer-sited storage drives up emissions.

There’s a better approach for customer-sited storage designs and applications to be applied to the greatest benefit of the state, and to prevent storage from being artificially constrained from helping California reach its GHG goals. As it has done with programs, tariffs and incentives to encourage customers to reduce energy consumption or peak demand, or to shift consumption to better utilize resources and reduce costs, the state should apply the same approach to enable storage to maximize GHG emissions reductions.

Customer-sited or behind-the-meter (BTM) storage, sited anywhere on the grid, can enable higher penetrations of renewables, and in doing so, reduce systemwide GHG emissions. Furthermore, when energy storage is charging during the duck belly, it absorbs and shifts power to the ramp “neck,” helping to reduce greenhouse gas emissions by avoiding fossil ramping assets. These benefits should be recognized.

California must develop an accurate methodology based on a GHG signal

The California Public Utilities Commission (CPUC) issued a Decision in 2015 on Self-Generation Incentive Program GHG evaluation approaches (D.15-11-027) that acknowledged the need to improve the storage GHG methodology. Others agree: A Carnegie Mellon December 2016 study criticized the SGIP methodology’s operating assumptions and inattention to retail tariffs and load profiles, and suggested a shift to production cost modeling.  

The CPUC methodology mistakenly assumes all BTM storage charging is done “off-peak,” that 100 percent of off-peak electrons are generated from combined-cycle gas turbines, and that all discharging is “on-peak” to offset combustion turbine peaker plants. Like most related studies, these assumptions are flawed in their failure to understand the economic market signals that determine storage behavior.

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