It’s not enough to just store energy — system operators have to find a way to balance supply and demand instantaneously, generating every kilowatt that is demanded by customers who expect power the moment they flip a switch.
(TNS) -- In a fast-developing industry teeming with technologies that promise to be the next big thing, energy storage appears to be the biggest.
Its supporters not only sing its praises but also tout what they say is its inevitability.
“We’re going to have 10 times as much energy storage on the grid by the end of this decade and that is going to impact every facet of the energy industry,” said Matt Roberts, executive director of the Energy Storage Association, an industry trade group.
But the electrical grid is a harsh taskmaster.
As far back as the 1880s, Thomas Edison wrestled with a way to effectively take surplus energy, save it and then use it at a later date.
It’s not enough to just store energy — system operators have to find a way to balance supply and demand instantaneously, generating every kilowatt that is demanded by customers who expect their lighting/heating/air conditioning to come on the moment they flip a switch.
“There’s a whole bunch of different, new storage technologies, but we get ones that seem to be cheaper but they fail on the density problem,” said Stephen Brick, senior fellow on climate and energy for the Chicago Council on Global Affairs. “We get ones that seem to improve on the energy density and they fail on the cost side.”
Energy storage technology takes on a lot of different forms.
The most prominent is pumped hydro, in which water is pumped uphill behind dams and then released, with the ensuing rush of water generating power.
Pumped hydro is the biggest source of energy storage in the U.S., accounting for 96 percent of the industry’s total storage capacity.
But chemical storage — as in batteries — may be the source people are most familiar with, especially given the media attention that inevitably accompanies any announcement by billionaire entrepreneur Elon Musk.
Last year, Musk unveiled the Powerwall, a rechargeable lithium-ion battery for homes and the PowerPack, a 100 kilowatt-hour utility-scale battery.
And the $2 billion Tesla “giga-factory” outside Reno, Nev., promises to produce enough lithium-ion batteries for 500,000 cars a year.
Then there is thermal storage, such as concentrated solar power plants, like the sprawling 392-megawatt Ivanpah facility in the Mojave Desert.
Other energy storage technologies include compressed air, which is stored under pressure in underground caverns, and flywheels, discs spun at high rates of speed.
For all of the attention energy storage has recently received, it represents a tiny portion of the mammoth electricity and power industry — 21,000 megawatts (21 gigawatts) of capacity, a little under 2 percent of the nation’s peak demand, according to the Energy Storage Association.
But energy storage is taking on a greater role as the power grid — especially in California — integrates more renewable energy sources such as solar and wind energy.
Solar has grown from 0.3 percent of the state’s power mix in 2010 to 6 percent in 2015, the most recent year for data by the California Energy Commission.
Wind has a larger share, nearly doubling from 4.7 percent in 2010 to 8.2 percent in 2015.
While solar and wind can produce plenty of energy, they have a big problem with intermittency. When the sun isn’t shining, solar production slumps and when the wind isn’t blowing, wind power wanes.
The trick is trying to find a way to fill in the gaps.
Stored-up energy can help do the job when wind and solar production sputters and can “smooth out” the grid when excess amounts of power are being generated.
While Roberts said, “Energy storage isn’t here to save renewables,” its point is to provide a balancing act. “It can balance supply and demand in microseconds, in milliseconds.”
Faith in the nascent storage industry was one of the reasons Pacific Gas & Electric announced plans to shut down the Diablo Canyon nuclear facility near San Luis Obispo by 2025.
Three years ago, the California Public Utilities Commission approved a mandate requiring the state’s three investor-owned utilities procure 1,325 megawatts of energy storage — roughly the equivalent of two to three combined-cycle natural gas power plants — by 2020.
PG&E and Southern California Edison have to find 580 megawatts each and San Diego Gas & Electric has to come up with 165 megawatts.
Utility customers would pick up the tab, with rough estimates for meeting the 2020 targets running between $1 billion to $3 billion.
That’s a wide range that analysts say is largely due to the variety of bidders proffering their technologies and the anticipation that costs will come down with each succeeding year.
Storage can come from sources that are connected to transmission or distribution lines — what’s called “in front of the meter” — as well as energy on the premises of a utility customer, such as rooftop systems, referred to as “behind the meter.”
There were some doubts about whether those targets could be met, but storage proponents cheered when SCE not only met its initial tranche of 50 megawatts but exceeded it by more than five times — 264 megawatts, putting it well ahead of schedule.
PG&E and SDG&E officials say they are on track to meet their allotments.
“It’s a huge amount of progress,” Ehren Seybert, energy adviser to CPUC commissioner Carla Peterman, said at an ESA conference in San Francisco earlier this month.
The growth of the residential rooftop solar market is also helping drive the energy storage industry.
The number of solar installations in the U.S. reached the 1 million mark earlier this year, with rooftop installations making up a huge chunk. California installed 3,266 megawatts of photo-voltaic solar in 2015, more than any other state in the U.S.
Combining solar power with energy storage — what’s called “solar-plus-storage” — has also been picking up strength.
The prospect of homeowners, many of them generating excess power from their photovoltaic systems, discovering a reliable way to store surplus energy and use it at a later time, would have profound implications for the energy grid.
“I don’t think everyone’s going to live off the grid,” Roberts said. “That just doesn’t make sense for most of us, especially for anyone who lives in a city. Being off the grid is nearly impossible. But I do think people are going to have more energy independence.”
IHS, a respected international consulting firm, projects the global energy storage market will grow from just 340 megawatts in 2013 to 6 gigawatts in 2017 to more than 40 gigawatts by 2022.
The industry’s biggest obstacle is expense.
The U.S. Energy Information Administration, generally relied on by analysts as the authority for reliable data, does not compile authoritative cost estimates for electricity storage because the sector is too small.
Industry numbers vary.
The generally accepted figure for chemical, or battery, storage is $500 per kilowatt-hour while some academic papers have listed the break-even capital cost for large-scale storage systems at $100 per kilowatt-hour.
That’s much higher than the cost of conventional electricity sources, but Roberts is quick to say such comparisons are unfair because energy storage does not produce electricity. Rather, it’s a way to deliver energy.
Lazard, an investment bank that raises money for renewable power developers, came out with a study last November that proved to be a mixed bag.
In a levelized series of cost comparisons, few of the storage sources came in with costs at or near natural gas peaker plants.
And in a “behind the meter” comparison with a conventional diesel-powered generator, every storage source came in with higher costs, with lithium-ion batteries costing 5 to 7 times more and lead-acid batteries 5 to 11 times higher.
On the other hand, the study’s authors said storage’s efficiencies are improving and its prices are coming down — a trend Lazard expects to continue.
Brick, of the Chicago Council on Global Affairs, says he’s not convinced the picture for energy storage is as bright and sunny as its proponents say.
“There’s a role for storage but it doesn’t deal with the seasonal problems” of wind and solar, he said.
Brick and colleague Samuel Thernstrom wrote a paper published in the April edition of the Electricity Journal declaring, “The dynamics of storage are trickier than might first appear.”
Due to the variability of wind and solar, they argue that a storage system designed to capture surplus electricity would not be used often enough to be economically smart — even if storage costs were cut in half.
“If I live in Sacramento, the difference in solar output between January and June is a factor of three,” said Brick.
“So the same unit on my house will make three times the electricity in a typical June than in a typical January. If I’m a facility owner, the problem I have is, if I want to make sure I generate my needs in January, I’m going to overbuild my system relative to what I need in June.”
Applying pumped hydro storage to fix the surplus problem, said Brick, who once worked for a subsidiary of PG&E, would require California building more than 200 more facilities.
Bloomberg New Energy Finance’s 2016 outlook for renewables projected battery costs declining 60 percent by 2030. The Electric Power Research Institute (EPRI) issued a forecast that lithium-ion battery packs will drop to one-quarter of their current price by 2022.
But some critics say the technology has yet to make the dramatic changes necessary to revolutionize the grid.
“Sure, there are improvements that happen with batteries but those improvements need to be massive to actually be cost-effective,” said Dan Simmons, vice president for policy at the Institute for Energy Research, a conservative think tank based in Washington, D.C., that calls for free market solutions to energy issues.
“When the cost of existing nuclear is essentially one-tenth the cost of some of these (storage) technologies, it has a long way to fall before it makes any economic sense.”
It’s been estimated that wholesale power from Diablo Canyon costs an average of 4 cents per kilowatt-hour.
By itself, Diablo’s 2,160 megawatts of electricity accounts for about 9 percent of the state’s power mix.
By the time both generators at Diablo are scheduled to go down in 2025, PG&E officials expect to replace the lost power with a combination of increased renewable sources, better energy efficiency, changes in the grid and bigger contributions from energy storage.
That, PG&E officials say, means they don’t have to replace the power from Diablo on a 1-to-1 basis.
“With enough planning we’ll be able to get the right resources in place,” said Todd Strauss, PG&E’s senior director of energy policy, planning and analysis. “It’s a very different energy world going forward.”
However, in an interview in June with the San Diego Union-Tribune, Strauss said the projected costs for storage leading up to PG&E’s decision to close Diablo Canyon are confidential.
“I would love to have really cheap storage,” said Michael Shellenberger, president of Environmental Progress, a pro-nuclear group based in Berkeley.
“But until that day arrives, why would we be taking down our largest source of clean power out of some absolute faith … that we’re going to have these magic batteries in seven or eight years? It’s just silly.”
The future of energy storage figures to go through California. A number of other states — including Oregon and, most recently, Massachusetts — have adopted storage procurement mandates mimicking those adopted by the Golden State.
“We’re building the rails (for energy storage) right now,” Praveen Kathpal, vice president of AES, an energy storage company based in Arlington, Va., said earlier this month. “And that railroad started in California.”
The massive leak at the Aliso Canyon natural gas facility in Los Angeles County is used as a cautionary tale about the need for greater energy diversity and the accompanying clean-energy attributes of storage.
The leak that spewed methane over the Porter Ranch development, displacing some 8,000 households, has kept the facility offline for 10 months now, jeopardizing the reliability of the power system in Southern California.
That, backers of storage say, highlights the need to develop new technologies.
They also point to their own studies indicating storage technology has developed enough to put natural gas-powered “peaker” plants out to pasture.
Operated by utilities to meet surges in energy demand in cases such as upswings in air conditioning usage, peaker plants can be built relatively inexpensively but their running costs are high because they are often used only about 5 percent of the time. California has 71 peaker plants.
Jim Robo, the CEO of NextEra Energy, a Fortune 500 clean energy company based in Florida, recently predicted peaker plants won’t be seen in the U.S. after 2020.
“I think it’s a foregone conclusion that we’ve come to the end of the usefulness of the peaker plant,” Roberts said.
©2016 The San Diego Union-Tribune Distributed by Tribune Content Agency, LLC.