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From Germany to Orange County, cost-effective grid batteries will require adaptability.
Controlling and optimizing grid-tied and behind-the-meter batteries is already a complicated business. But it’s going to get a lot more complicated in the years to come, both for utility-facing storage integrators like S&C Electric Company, AES Energy Storage and NEC/A123, and for customer-facing behind-the-meter storage providers like Stem, Green Charge Networks or Solar City and Tesla.
All are aimed at managing a similar set of imperatives: making sure that energy storage systems, individually and in aggregate, can earn their maximum return on investment over their effective lifespans. These money-making functions range in timescales from split-second frequency regulation to multi-hour load shifting, and in frequency of use from daily peak-shaving, to once-in-a-blue-moon emergency backup power.
Certain applications, like helping utilities defer upgrades to congested substations and circuits, or managing demand charges in buildings, can be economically viable today. Others, such as storing rooftop solar power to help reduce its potential for grid disruptions, or wheeling power from one utility service area to another, are still waiting for state regulations and energy market constructs to change to allow them to become money-making opportunities.
Well-managed batteries ought to last long enough to be around when these opportunities start to emerge. And that puts a premium on control systems and business models that can adapt to change. From the recent news, here are two examples — one featuring behind-the-meter batteries in Germany and another involving a grid-tied system in Southern California — that highlight the flexibility imperative.
Sonnenbatterie turns solar home energy storage into aggregated energy arbitrage
Since 2008, German startup Sonnenbatterie has been integrating solar panels, lithium-ion batteries and home energy management systems via its software platform. Its target market is German homeowners with an interest in energy independence and some money to spend — the startup’s systems cost from about $13,000 for 4.5 kilowatt-hours of storage to about $21,000 for 10 kilowatt-hours of storage.
Germany’s homes tend to consume less power than their U.S. equivalents, allowing this amount of storage to keep a home grid-independent for days at a time, if the sun is shining, rather than merely serving as emergency backup, as U.S. solar-backed storage systems from the likes of OutBack Power and SolarCity are doing. And with Germany’s feed-in tariffs for solar now dropping below retail power prices, it’s worth storing solar energy for home use, in direct contrast to almost every U.S. electricity market.
But with about 8,000 systems sold in Germany and production running at about 100 to 150 systems per week, “we are extending our business model away from only selling hardware, and towards energy services,” CEO Christoph Ostermann said in an interview in San Francisco last month. About 30 percent of its systems are already white-labeled by partners including utility RWE and solar manufacturer SolarWorld, he said.
Another partner, green energy retailer Lichtblick, has been offering its customers 1,100 kilowatt-hours of free power and a 100-euro bonus payment to allow their batteries to become part of a virtual power plant, dubbed a “SwarmBattery,” to take advantage of Germany’s volatile energy market.
Under this program, Sonnenbatterie monitors available capacity for its “fleet” of batteries to keep them available to absorb grid energy when prices drop to close to zero, or even go negative, said Boris von Bormann, Sonnenbatterie’s U.S. manager. That’s something that happens when solar production, plus baseload fossil fuel and nuclear power plants, are generating more power than the grid needs.
In other words, “they get paid to take energy, and the customer gets free electricity,” he said. “We’re working with other utilities right now” on similar programs, which could involve utilities sharing costs with customers to install even larger batteries for homes to manage that grid arbitrage function, he said. Lichtblick has been offering a similar product since 2008, only using small-scale combined heat and power (CHP) systems instead of batteries.
In the U.S., this would be a much harder business plan to execute, relying on an extremely rare combination of deregulated market structure and highly volatile hour-to-hour energy pricing. Sonnenbatterie is targeting the U.S. market, Ostermann noted — but it’s looking at providing demand charge management for commercial buildings, as startups like Stem, Green Charge Networks and Coda Energy are doing, rather than home batteries.
There could be ways for Sonnenbatterie’s SwarmBattery concept to serve the needs of U.S. utilities as well, by providing a flexible resource that’s a lot cheaper than building a new natural gas-fired peaker plant, or refurbishing distribution grid wires and transformers, von Bormann said. As states like California, New York and Hawaii start to adopt new regulations to allow distributed energy to play these kinds of roles, solar-storage system from companies like SolarCity, Sunverge and Stem (and possibly Tesla) will be lining up to take part.
Southern California Edison sees potential market role for distribution-supporting batteries
California’s three big investor-owned utilities are under mandate to procure 1.3 gigawatts of energy storage by 2022 — and they’re looking at multiple ways to make them worth their while. That’s going to require some flexibility, both on the part of the software controlling them, and the regulators telling them what’s fair an not fair.
Last month, Southern California Edison unveiled its latest addition to its growing energy storage fleet designed to bolster its distribution grid. Built with A123 lithium-ion batteries and managed by A123’s new owner, Japan’s NEC, the trailer-sized array is one of the first to be sited on a customer’s property, but remain under control of the utility.
SCE is planning to use the battery system, capable of providing 2.5 megawatts of power for about an hour and a half, to bolster a substation serving four circuits in Orange County. It’s a fairly heavily loaded set of circuits at present, and would need to be upgraded in the not-too-distant future, without the battery to back it up, said Mark Irwin, a director in SCE’s advanced technology department.
“This gives us flexibility, and allows us to relieve potential overloads,” he said. In utility parlance, that’s called “distribution deferral,” because it defers the cost of upgrades, which serves as the primary financial benefit to justify its cost. By summer, the partners want to have NEC’s battery control system integrated into SCE’s distribution management system (DMS), so that it will be ready to help manage the summer’s peak power demands, he said.
But at some point, it’s going to be important to figure out how to allow distribution deferral-based projects to do more than that one function, for a pretty simple reason: it’s not going to be able to defer those costs forever. At some point in the future, the substations or circuits it’s supporting will have to be upgraded, leaving the battery with years of useful life but bereft of a financial purpose.
That’s why SCE would like to look at bidding its battery system’s capabilities into the ancillary services markets run by California’s grid operator, CAISO, he said. The catch here is that, generally speaking, utilities aren’t allowed to use assets paid for by ratepayers to compete in grid markets against independent power generators — or independent energy storage project owners, for that matter.
The California Public Utilities Commission order that created the state’s 1.3-gigawatt mandate requires that utilities own no more than half of the storage to be deployed. But it has left many more details on the program to be worked out over time, including how the state’s utilities, third-party energy storage owners, and storage-enabled customers will share opportunities to make money across the dozens of value streams potentially open to grid-tied batteries.
The likely approach will involve returning the market values realized by ratepayer-funded storage projects back to the ratepayers somehow, he said. “If you have an asset that the customers are paying for on the circuit, how do you look at those market values coming back? We expect the primary outcome will be, if the primary purpose is distribution deferral, that any net market revenues would go back to paying those who paid for it, which are the bundled customers.”
Just how this payback mechanism works is less clear. What’s more, independent parties may cry foul, as utilities can get much cheaper capital to fund these projects and then flood the market with products that undercut the independent competitors.
However these issues end up being resolved, California’s decisions could end up having a strong influence on how the rest of the world takes on these new challenges.
Originally published on Greentech Media.
By Jeff St. John 2015
This article was written by Greentech Media from Breaking Energy and was legally licensed through the NewsCred publisher network.