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Summary:

California regulators approved an ambitious plan to install a large amount of energy storage projects by 2020 to help the state meet its renewable energy mandate. The decision should be a boon for battery and other technology developers.

Solar Grid Storage

California energy regulator on Thursday approved what is the country’s first and very ambitious mandate for using storage technology to complement the growing amount of renewable energy flowing into the grid. The California Public Utilities Commission voted five to zero to approve the mandate, and it’s a big deal because it will rev up a new market for various technologies for banking electricity.

There are a wide variety of technologies just in the battery sector alone, and some are venture-backed startups that have been waiting for California to set the mandate. Here is what you should know about the new program and why you should care:

1). What is new? The mandate requires California’s three investor-owned utilities, Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric, to collectively buy 1,325 MW of energy storage by 2020. On top of that, municipal utilities and utility districts will have to procure energy storage that equals to 1 percent of their projected 2020 peak electricity demand and do so by 2020. All the energy storage projects that are under contract under this mandate will have until the end of 2024 to complete their installations.

2). Why do we need it? California wants 33 percent of its power supply to come from renewable sources, such as wind, solar and geothermal, by 2020. The problem is wind and solar projects don’t produce electricity steadily around the clock, so the state’s electric grid will get intermittent infusions and drop-offs of renewable electricity. That’s bad for the grid, which needs to maintain a balance of supply and demand to avoid blackouts and other problems.

By storing electricity utilities could have greater control of the amount and rate of power that flows through their transmission and distribution networks.

The electricity to be banked by energy storage equipment doesn’t have to be solar, wind or other renewable energy. Storage projects could soak up power from fossil fuel power plants when demand is low and sending it to the grid when demand spikes. This way, utilities could avoid building more power plants and investing in expensive grid upgrades over time as the population and energy use grows. They also could draw power from storage to maintain certain characteristics of the grid, such as its frequency, instead of turning to natural gas power plants like they usually do.

3). Who benefits? Storage technology creators and companies that develop and build storage projects will be lining up to win business from utilities. Banks or other investors who are willing to gamble in this new market, which to them also means making bets on unproven technologies, could also be winners.

There will be a lot of tussles among investors, project developers and technology companies over how to structure a project, its financing and expected returns. All the questions and challenges of this new energy storage market could very well mirror what has happened in the solar market.

Five years ago, many solar power projects designed for serving utilities were proposed by solar technology companies or newly formed project development companies. And they all had a really tough time lining up money to finance their projects. Since then, we have seen a growing number of  traditional power companies investing in solar power plants. We also have seen a rise in rooftop solar generation that gives consumers the ability to produce their own power and leaves utilities wondering what changes they will have to make in their business plans to stay profitable.

4). Concerns: The mandate is the baby of the newest member of the commission, Carla Peterman, who was able to line up support from all her fellow commissioners to set this mandate in place. But two commissioners, Michael Peevey and Mark Ferron, on Thursday pointed out some potential issues and solutions that they said would help to reduce friction in the program’s rollout.

They emphasized the need to give utilities flexibility to meet the mandate at ” a reasonable cost” and standardize the bidding and contracting processes to make it less costly for smaller project developers. The exclusion of large-scale pumped storage — pumping water to a reservoir and using that water for electricity generation later — also takes away a cheaper and proven way of storing energy for ratepayers. Peevey added that the rules aren’t clear on how energy storage being installed at homes and businesses could help utilities meet their mandate.

Peterman pointed out the vote on Thursday only kickstarted the mandate and doesn’t prevent what will surely be many more efforts by the commission to modify the program as they learn lessons about how to make the program work. The exclusion of large-scale pumped hydro projects is meant to help promote the use of newer — and often more expensive — storage technologies. The majority of the pumped storage projects are 500 MW and over. Smaller pumped hydro projects that are less than 50 MW would qualify to meet the mandate.

5). What’s next: The utilities commission’s vote on Thursday starts the clocking running for utilities to begin the process of buying energy storage capacities. First, the three big utilities will have until March 1 next year to come up with their own plans on how they will comply with the mandate. The plans will be a blueprint for energy storage developers to draw up projects and submit their bids.

The first bidding process will start by the end of 2014 and continue every two years. The commission has interim targets for the utilities to meet from 2014 to 2020. For example, the three utilities will look at buying a total of 200 MW of energy storage for their first set of purchases. The utilities will be able to defer their purchases under certain conditions.

  1. Energy storage is measured in MWh, not in MW which is a unit of power.

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    1. Mike, utilities and grid operators look for both MW and MWh when they want to buy energy storage services. It all depends on what types of services they want. Read this post I wrote on this subject: http://gigaom.com/2012/01/04/how-to-compare-energy-storage-projects/

      Also my video interview with an energy storage project developer: http://www.renewableenergyworld.com/rea/news/article/2012/04/xtreme-power-guns-for-electric-car-neighborhood-energy-storage-markets

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  2. Mike is still right on that point. Energy is not measured in watts so speaking of energy storage in MW makes as much sense as describing the height of a building in gallons. Utilities may well want their storage to have a certain power rating but the power rating does not indicate the amount of energy stored.

    The article would be excellent if this were fixed.

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    1. There is nothing to fix, Nathan. Both metrics are commonly used. A solar power plant produces electricity that’s measured in MWh, but the utility’s procurement process uses MW. So power purchase agreements that are announced and to be considered before the commission contain the MW. Sometimes utilities/grid operators want to pay for a capacity reserve that’s measured in MW. And, check out this daily renewable energy supply/demand data from California ISO (in MW): http://www.caiso.com/Pages/TodaysOutlook.aspx

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  3. Mike + Nathan: I understand your point about power v. energy, but the story here is not a lesson in distinguishing the two. The story is about a policy that uses MW as the metric. The story also is about how utilities could use storage to manage their grids, and they will use both power and energy in making their purchase and operational decisions. Lastly, the story is for readers who love tech but who might not be experts in the electric power industry. People often use “power” and “energy” interchangeably in conversations. So I’ll make the distinction only when the story calls for it. Thanks for your comments, though.

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    1. I get your point above, but it’s very frustrating as someone reading trying to work out how useful this actual project is, both power output and energy storage (or time that power can be delivered for) are needed to work out that out.

      So yes, I think this does need fixing, like Mike and Nathan say, the subject is interesting, but without the relevant info it loses a lot of meaning and impact.

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      1. To illustrate what I mean:

        http://www.inference.phy.cam.ac.uk/withouthotair/c26/page_187.shtml

        Shows fluctuations in wind power production in Ireland, how big a blip in production could this system cover? What’s it designed to cover?

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        1. Horza, as I mentioned, I’ll make the distinction when needed. My story is about a policy that uses MW to frame its procurement targets. Exactly how much MWh will be needed will depend on the need of individual utility — when they need it and for what. That will be worked out later. The procurement process hasn’t even started yet. So what “useful project” are you talking about? There is no project.

          And, the link you included uses MW in the text, and it uses “power” and “energy” interchangeably. I rest my case.

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          1. Yes, of course it does, because it’s talking about peak power and variability in power production.

            I read that last summer, it doesn’t use them interchangeably (if you think he does, than you really haven’t done more than scan read). He’s pretty damned tidy with his units, and uses them specifically for separate things, and in that section is trying to give an estimate for how many MWh of storage would be needed in the UK to smooth out generation.

            MW rating tells you how deep a dip a system is designed to protect against, whereas MWh will then tell you how wide a blip. Power companies know there systems best, but some way to go. Is important, I agree there.

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