U.S. support of grid energy storage charges up

California's new procurement mandate, the emergence of microgrids, and innovative financial models could accelerate new deployments of centralized and distributed grid storage capacity.
Written by Chris Nelder, Contributor

Heads up, renewable energy doubters. Yes, we all know the electrical grid will need storage capacity to accommodate a larger share of power from variable wind and solar generators. But the date for this development is no longer in some distant, hand-wavy future. It's coming, and it's coming fast.

A wide array of power storage technologies is waiting for that moment: from traditional batteries and old-school pumped hydropower (in which water can be pumped up to a reservoir and then allowed to run through turbine generators on demand) to newer systems using compressed air, flywheels, new types of batteries, and thermal approaches like molten salts or even ice. (For an overview of some of these technologies and their relative costs, see my article from last year.) The new $2 billion, 280-megawatt (MW) utility-scale Solana solar project in Arizona, for example, will use molten salts to keep the plant running for up to six hours after the sun sets.

Consider the following developments, all of which happened in just the past two months.

California's energy storage mandate

The California Public Utilities Commission (CPUC) unanimously approved the first U.S. mandate to build grid power storage capacity to support its growing renewable power resources.

California has the most aggressive renewable portfolio standard in the country, with a target of obtaining 33 percent of its electricity supply from renewables by 2020. The state currently gets about 21 percent of its power from renewables; by 2020, it expects to get 47 percent of the renewable portion from solar.

The mandate requires the state's utilities to submit applications by next March to procure enough storage capacity to meet about one percent of projected peak demand in 2020. For the three large investor-owned utilities that amounts to 1,325 MW. Installations must be completed by 2024.

Large pumped-hydro facilities are not eligible, focusing the incentive on newer storage technologies.

Importantly, the storage capacity is agnostic to how the power it stores was generated. Grid operators can recharge it when demand is low and discharge it when it is advantageous to do so: to meet peak demand, support grid frequency and voltage, and smooth out generation across regions. These are key features for supporting large amounts of renewable energy on the grid.

The mandate calls for storage capacity supporting each type of grid connection point: transmission (shipping power over long distances), distribution (distributing power to individual consumers), and "behind the meter" customer-side applications (like a battery backup system for a home solar array). This approach will ensure no one storage application dominates the procurement, and create an incentive for many participants in the new market. It will also create a wide base of storage capacity, giving grid operators flexibility in how they use it.

(Proposed procurement target schedule for the three major utilities. Source.)

Collectively, the new storage capacity that is being mandated for the big three utilities would be greater than the output of a typical 1,000 MW nuclear reactor.

As Edward Randolph, the CPUC energy director, told Renew Economy, “That is a pretty big target. ... We’re maybe contemplating more storage in California than currently exists around the world. But it’s the same theory when we looked at goal of 3,000 MW of solar -- at that time the only two places that were all in on solar -- us and Germany. You have got to make the commitments to drive the market."

Even so, the one percent target is just an initial goal. Like the evolution of net metering that has spurred rooftop solar deployment, it is only the beginning of a long build-up of storage capacity on the California grid. In time, the state will gradually increase the requirements as utilities and customers become more comfortable with the process, and the costs and implementation details are discovered.

What's exciting about the target is that it sets the state on a course to obtain much a larger portion of its power from renewables while phasing out so-called baseload power generators like coal and nuclear plants, as well as old inefficient gas-fired generators. More importantly, it will set an example for the rest of the nation. When I wrote "Why baseload power is doomed" in March 2012, this is precisely the kind of evolution I was talking about.

Microgrids and grid support

My regular readers know that I have long  dreamed about microgrids finally coming into their own. As I wrote in May, microgrids can be a utility's best friend or its worst enemy, but fortunately a few utilities are now taking the friendly route.

Utility giant Duke Energy is testing several pilot projects that use microgrids and standalone storage systems to buffer wind and solar power as they come and go, and to provide essential grid management services like price arbitrage, reliability support, "reactive power" (don't ask -- seriously, don't!), and other highly technical functions that only engineers understand.

"At Duke Energy, our focus now is not so much looking for the next great battery, but finding out how to create the best value for the grid and our customers," wrote vice president David Mohler. "Better yet, how do we make energy storage tackle a number of tasks for the grid -- instead of being a 'one-trick pony' concentrating on a single area?"

The Duke pilots include a 36-MW advanced lead acid battery system in Notrees, Texas; a Rankin Energy Storage System in Gaston County, North Carolina.; an islandable microgrid in Charlotte, N.C.; and another microgrid at a shopping mall in Carmel, Ind.

The kind of testing that Duke is doing is a critical part of the good grid planning that allowed Germany to accommodate more renewable power than naysayers said was possible. So it's encouraging to see this kind of exploration finally being done in the United States.

In September, another large microgrid was completed in Maryland. Billed as "one of the nation’s first commercial-scale microgrids," the system was installed on real estate company Konterra's corporate headquarters and uses a 402-kilowatt solar system paired with an "advanced energy storage system" that will provide 500 kilowatt-hours of storage, in addition to other aforementioned technical support attributes.

The U.S. Navy is also testing storage at its Navy Yard in Philadelphia, among other locations.

Storage as a service

Another fascinating innovation in storage is coming quickly, but it's not a new technology; it's a business model.

Following the model of third-party solar financing and leasing companies, startup Stem just launched a financing model for power storage in California. Backed by a $5 million investment from Clean Feet Investors, Stem will pay the high up-front cost of installing battery banks and smart energy management systems for large power users like hotels, then lease the systems back to the customers, typically under a 10-year contract.

The systems will save customers money in several ways: by helping them intelligently manage a building's energy consumption; by gathering and analyzing data on a building's energy use to guide optimization and efficiency improvements; and by shifting expensive peak power demand from the grid to the storage system, which can be recharged at night.

Stem has already installed a combined 100 kilowatts of storage at the two Intercontinental hotels in San Francisco and at its company headquarters, and currently has 6 MW of installation under contract. It expects the latest round of funding to be used up next year, after deploying up to 15 MW of capacity.

If the storage-as-a-service business model proves to be a success, Stem and its competitors will certainly be seeing fresh capital injections in the coming years.

Storage as capacity

However, the most exciting -- if wonky -- of all the recent storage news is that the PJM Interconnection, a Regional Transmission Organization (RTO) that governs much of the grid in the Northeast, has agreed to consider new rules that would allow storage to bid in the capacity market.

(This can be a bit technical. For more information on RTOs, see "Why baseload power is doomed." For more on the PJM Interconnection, see "Coming soon: 100% renewable power." For more on capacity markets, see "The Perils of Electricity Capacity Markets.")

As one participant said when I mentioned the PJM news at a recent Ernst & Young retreat for cleantech CEOs, "That's huge."

Essentially, the decision will allow all sorts of smart grid technologies and businesses -- such as demand-response companies, storage providers, even coordinated banks of residential and commercial battery systems that can be dispatched on command by a utility -- to participate in the capacity market. Until now, the capacity market was strictly a "big boys" sandbox where only large generators could play.

By opening that door, PJM could create a massive new market for both distributed and large centralized storage systems, which could lead to a total transformation of the U.S. grid and really level the playing field between distributed renewables, smart grid players, and conventional centralized power generators.

AES Energy Storage, the largest operator of battery-based energy storage resources in North America, just installed a 40-MW storage array on the PJM Interconnection in Ohio to provide fast-response frequency regulation and grid stabilization services. But under the new rules, storage on the PJM could move far beyond that narrow niche and compete head-to-head with baseload generators.

(Photo: AES Energy Storage's Tait battery array in Moraine, Ohio)

This post was originally published on Smartplanet.com

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