DIY ESS Update:
- Savings went past 320 EUR (over a year and 2 months)
Screenshots from http://wattson.energyhive.com/dashboard/diyesskit :
Showing posts with label grid storage. Show all posts
Showing posts with label grid storage. Show all posts
Friday, August 7, 2015
Saturday, November 29, 2014
When batteries beat traditional power
Battery storage is usually seen as being a handy adjunct to help renewable energy square up to traditional power plants. But on frequency regulation, at least, it seems batteries may actually be better than the generation sources they are helping to supplant.
That, at least, is the consensus emerging from early operating experience at Europe’s largest commercial battery power plant, the 5MWh lithium-ion facility that WEMAG has commissioned from Younicos in Schwerin, Germany.
“Whereas coal-fired and other thermal plants typically take up to 30 seconds to adjust production up or down, and then just hit the neighbourhood of where they are supposed to be, batteries react within milliseconds,” explains Philip Hiersemenzel of Younicos.
The fact that batteries might beat traditional power plants for frequency regulation has long been touted as a big selling point for battery storage and has already helped sell projects in the US.
Now the performance of WEMAG’s installation is strengthening that business case.
As well as being able to respond to frequency shifts more quickly and accurately, says Hiersemenzel: “The second reason batteries are better suited is that they don’t require CO2 emissions to adjust the frequency.”
No must-run capacity
Furthermore, he says, batteries do not create any ‘must-run’ capacity. In other words, they don’t need to remain operational when not being used for frequency regulation, reducing overall power generation.
This can have a significant impact on carbon emissions. Younicos says most thermal power plants need to run at around 70% of total capacity just in order to provide decent frequency regulation, and in German coal-fired plants the level is about 90%.
“This creates an overall must-run capacity of 25GW in Germany alone,” Hiersemenzel states; “25GW of coal and nuclear power must be fed into the grid at all times.”
Natural gas plants are more flexible and can provide frequency response while running at as little as 40% of capacity. “But they’re also more expensive than coal,” says Hiersemenzel.
“Since we’re already competitive against the marginal cost of a completely written-down coal plant, imagine how competitive we are against a new gas plant.”
At the WEMAG plant’s grid-connecting ceremony a fortnight ago, Younicos’s chief technology officer Clemens Triebel pointed out that the facility was essentially providing the same level of frequency control as a 50MW conventional turbine.
Avoiding economic impact
“Coal-fired power plants can only use a fraction of their output for control power,” he said. “This blocks space in the grid, increasingly forcing wind and solar generation to be taken offline. Our battery park avoids this economic impact.”
The WEMAG battery plant features Samsung SDI lithium-ion cells and serves a grid area where 80% of power already comes from wind and solar generation.
It was backed by EUR€1.3m from the German Environment Ministry’s innovation programme and will compete on the primary frequency regulation market, Younicos says.
Younicos expects this capability alone will provide a positive return on investment for the plant. But the facility is also due to earn its keep in other ways. One is by replacing WEMAG’s current ‘black-start’ generators.
“Like all regional grid operators, WEMAG keeps diesel gensets solely for the purpose of black-starting the grid after a power cut,” says Hiersemenzel.
“Such cuts typically happen not so much because of electrical problems in the grid, or even renewable generation, but for much more profane reasons: a car hitting a power line, say.”
“Coal-fired power plants can only use a fraction of their output for control power,” he said. “This blocks space in the grid, increasingly forcing wind and solar generation to be taken offline. Our battery park avoids this economic impact.”
The WEMAG battery plant features Samsung SDI lithium-ion cells and serves a grid area where 80% of power already comes from wind and solar generation.
It was backed by EUR€1.3m from the German Environment Ministry’s innovation programme and will compete on the primary frequency regulation market, Younicos says.
Younicos expects this capability alone will provide a positive return on investment for the plant. But the facility is also due to earn its keep in other ways. One is by replacing WEMAG’s current ‘black-start’ generators.
“Like all regional grid operators, WEMAG keeps diesel gensets solely for the purpose of black-starting the grid after a power cut,” says Hiersemenzel.
“Such cuts typically happen not so much because of electrical problems in the grid, or even renewable generation, but for much more profane reasons: a car hitting a power line, say.”
Using batteries instead of gensets
When this happens, the grid operator has to coax its power stations back online using smaller genset units. Only WEMAG should now be able to rely on its battery plant instead, and save the expense of maintaining gensets.
The facility, which has been praised by the German Vice-Chancellor and Energy Minister Sigmar Gabriel, and Mecklenburg-Western Pomerania’s Minister-President Erwin Sellering, could also be used for other auxiliary services, such as voltage control.
In fact, for another Younicos project, the 6MW, 10MWh Smarter Network Storage plant being built for UK Power Networks in Leighton Buzzard, UK, batteries will be used for at least six different functions, including peak shaving, and possibly all at once.
Trying to squeeze that much functionality out of a single battery plant will probably cut the lifetime of the batteries, Hiersemenzel points out.
But it is the operator’s choice whether to try to stretch the lifespan of their investment or get the most value possible out of it over a shorter period.
For now, what the WEMAG plant and other early grid-connected battery facilities are showing is that energy storage is no longer about making renewable-laden grids as good as traditional ones; it is about making them better.
Written by Jason Deign
Source: Energy Storage Report
When this happens, the grid operator has to coax its power stations back online using smaller genset units. Only WEMAG should now be able to rely on its battery plant instead, and save the expense of maintaining gensets.
The facility, which has been praised by the German Vice-Chancellor and Energy Minister Sigmar Gabriel, and Mecklenburg-Western Pomerania’s Minister-President Erwin Sellering, could also be used for other auxiliary services, such as voltage control.
In fact, for another Younicos project, the 6MW, 10MWh Smarter Network Storage plant being built for UK Power Networks in Leighton Buzzard, UK, batteries will be used for at least six different functions, including peak shaving, and possibly all at once.
Trying to squeeze that much functionality out of a single battery plant will probably cut the lifetime of the batteries, Hiersemenzel points out.
But it is the operator’s choice whether to try to stretch the lifespan of their investment or get the most value possible out of it over a shorter period.
For now, what the WEMAG plant and other early grid-connected battery facilities are showing is that energy storage is no longer about making renewable-laden grids as good as traditional ones; it is about making them better.
Written by Jason Deign
Source: Energy Storage Report
Sunday, March 30, 2014
Listen Up: Let's Talk Solar Grid Storage
To many of us old timers, the battery storage industry looks a lot like the solar industry did ten years ago. Energy storage on the grid depends on future battery cost reductions, requires sophisticated management electronics, tricky packaging, favorable government policies, coordination with utility rates and appropriate financing. Not surprisingly, we're seeing successful solar entrepreneurs from the last decade applying their finely-honed skills and tactics to build new energy storage businesses.
The synergies between solar and battery storage are obvious, but problems still exist in getting the economics to pencil out for customers. As in the solar industry, clever system designs and financing strategies can go a long way to improve customer economics and generate real sales. Although we'd like to see a solar array on every residential roof and two battery stacks in every garage, what is more likely to happen is that commercial customers will be the early adopters of combined solar and energy storage systems.
Tom Leyden, CEO of Solar Grid Storage, is building a business at the nexus of solar and battery storage. They have developed an elegantly packaged combination of battery storage, inverters and rooftop solar. Just as importantly, they offer flexible financing packages that effectively combine storage and solar as a service — with the economic benefits accruing both from grid support services as well as customer peak shaving and backup power. Please join me on this week's Energy Show on Renewable Energy World as Tom Leyden explains the current opportunities and customer demand for combined solar and grid storage systems.
Find more episodes of The Energy Show here.
About The Energy Show
As energy costs consume more and more of our hard-earned dollars, we as consumers really start to pay attention. But we don't have to resign ourselves to $5/gallon gas prices, $200/month electric bills and $500 heating bills. There are literally hundreds of products, tricks and techniques that we can use to dramatically reduce these costs — very affordably.
The Energy Show on Renewable Energy World is a weekly 20-minute podcast that provides tips and advice to reduce your home and business energy consumption. Every week we'll cover topics that will help cut your energy bill, explain new products and technologies in plain English, and cut through the hype so that you can make smart and cost-effective energy choices.
About Your Host
Barry Cinnamon is a long-time advocate of renewable energy and is a widely recognized solar power expert. In 2001 he founded Akeena Solar — which grew to become the largest national residential solar installer by the middle of the last decade with over 10,000 rooftop customers coast to coast. He partnered with Westinghouse to create Westinghouse Solar in 2010, and sold the company in 2012.
His pioneering work on reducing costs of rooftop solar power systems include Andalay, the first solar panel with integrated racking, grounding and wiring; the first UL listed AC solar panel; and the first fully “plug and play” AC solar panel. His current efforts are focused on reducing the soft costs for solar power systems, which cause system prices in the U.S. to be double those of Germany.
Although Barry may be known for his outspoken work in the solar industry, he has hands-on experience with a wide range of energy saving technologies. He's been doing residential energy audits since the punch card days, developed one of the first ground-source heat pumps in the early ‘80s, and always abides by the Laws of Thermodynamics.
Source: Renewable Energy World
His pioneering work on reducing costs of rooftop solar power systems include Andalay, the first solar panel with integrated racking, grounding and wiring; the first UL listed AC solar panel; and the first fully “plug and play” AC solar panel. His current efforts are focused on reducing the soft costs for solar power systems, which cause system prices in the U.S. to be double those of Germany.
Although Barry may be known for his outspoken work in the solar industry, he has hands-on experience with a wide range of energy saving technologies. He's been doing residential energy audits since the punch card days, developed one of the first ground-source heat pumps in the early ‘80s, and always abides by the Laws of Thermodynamics.
Source: Renewable Energy World
Saturday, February 1, 2014
Elon Musk and JB Straubel in Amsterdam - Tesla talk, PV, Energy Storage
Elon Musk and JB Straubel were in Amsterdam yesterday for a meeting with the Dutch Tesla Club
A lot of Q&A with the crowd from NL, Belgium, etc
And also some talk about Energy Storage
Tuesday, September 10, 2013
How Energy Storage is transforming the Electric Power System
Already commonplace in the consumer electronics and transportation industries, energy storage has taken years to evolve on the electric grid – but now, it’s at a turning point. This suite of technologies is seeing massive growth that will benefit markets and electric grids alike.
A number of analysts have forecasted multi-fold increases in the energy storage market size, with global annual figures over $100 billion in 2020[1]. This is unprecedented growth – reflecting the cusp of an energy revolution.
Here are a few reasons why energy storage is transforming the electric system – and why it will keep doing so for years to come.
1: Better system efficiency
The electric system is a tricky beast. At any given time, supply needs to match demand, and the system itself has many interacting parts. Unfortunately, these factors and more have combined to create a very inefficient electric system.
Among other things, we’ve built enough generators and transmission lines to meet the peak demand on the hottest summer day – but those resources largely sit idle and are expensive and incredibly polluting.
Energy storage fixes this conundrum and more by charging up at periods of low demand and discharging during periods of high demand. And because storage is an incredibly diverse technology class, it can be installed anywhere in the electric power system and address a multitude of location-specific challenges. Whether it is substituting for dirty “peaker” plants, smoothing renewables’ output, integrating micro-grids, increasing efficiency of conventional generation, or alleviating local transmission congestion, energy storage enables greater system efficiency across the entire grid.
2: Technological Innovation
Commercially available energy storage projects are being deployed on the grid by the hundreds, ranging from kW-sized projects sited behind customers’ meters to greater-than-100 MW utility scale plants[2]. Investments in these projects, technologies, and creative new business models are being made by governments, entrepreneurs, and developers excited about energy storage’s economic and technical capabilities.
Due to expanding grid storage installations, increasing electric vehicle sales, technological improvements and economies of scale, installed costs of grid storage are dropping dramatically. In 2010, the US Department of Energy projected lithium-ion battery costs to fall from $1800/kWh in 2012 to under $250/kWh in 2020, and well-established thermal energy storage technologies now have installed costs under $500/kw. These massive cost reductions are making energy storage increasingly competitive in a growing array of grid applications.
3: Superior performance
As compared to many fossil-based status quo grid solutions, energy storage demonstrates superior performance and widespread benefits.
Many storage resources provide better precision compared to conventional generation. Where a state-of-the-art gas turbine takes 10 minutes to “ramp” to full power, many storage technologies can do so in less than one second. In a system where supply must always equal demand, this flexibility and accuracy are extremely valuable.
Energy storage systems also have 4 times the flexible range of equivalent capacity gas peakers (for example, a 100MW gas plant typically must generate at least 50MW, providing 50MW of flexible range, whereas 100MW of storage can charge at 100MW or discharge at 100MW, providing 200 MW of flexible range). Storage likewise has much higher utilization rates: gas peakers only run 20-40% of the year, whereas fast-responding storage resources have utilization factors over 95%. Energy storage co-located with relatively cleaner combined cycle gas turbines (CCGT) can even improve CCGT utilization factors and reduce reliance on dirtier plants. And the list goes on, from faster project development to reduced carbon emissions.
People in industry and government are recognizing these benefits every day. New system models are showing that energy storage is cost-effective when its full range of services and benefits are fairly accounted for. The reason for this is that energy storage delivers multiple benefits from one resource (e.g. reducing peak demand and providing grid support for frequency regulation). This is accelerating energy storage’s growth – and that acceleration is poised to keep on going.
4: Supportive Policies
Policies supporting energy storage, from financial support to procurement targets, are appearing worldwide, and the United States is at the forefront of that policy development.
In October 2011, the Federal Energy Regulatory Commission (FERC) issued “pay-for-performance” rules that reward accuracy in response times (FERC order 755). This increases competitiveness of fast-acting storage.
Policy support is also growing at the state level. California’s AB 2514 (Skinner) directed the California Public Utilities Commission (CPUC) to set procurement targets for the state’s investor-owned utilities for cost-effective energy storage. A landmark June 10 preliminary recommendation by Commissioner Carla Peterman set that number at an impressive 1.325 GW by 2020 and a final decision is anticipated in early October 2013.
In February 2013, CPUC directed Southern California Edison (SCE) to procure at least 50 MW of energy storage resource capacity in the Los Angeles basin to meet long-term local capacity requirements by 2021. Up to an additional total of 600MW of capacity is required to be procured from preferred resources and/or energy storage resources.
Finally, forward thinking utilities are moving forward with storage on their own. In May 2013, the CPUC granted San Diego Gas & Electric (SDG&E) the ability to rate-base $26 million toward the integration of energy storage resources for distribution support applications as part of their most recent general rate case.
All of these policies are giving investors confidence in both technology development and on-the-ground projects. They are key to market growth, and combined they are kick starting the transformation of our electric power sector.
Energy storage has been called the “holy grail of the electricity system,” half because of its amazing potential and half because it was seemingly unattainable. Now, we are entering an age where it has become attainable – and will improve the electric system for years to come.
[1] http://www.renewableenergyworld.com/rea/news/article/2012/04/grid-scale-energy-storage-lux-predicts-113-5-billion-in-global-demand-by-2017
[2] Project examples available at the Department of Energy’s International Energy Storage Database. http://sandia.gov/ess/database.
Source: Renew Economy
2: Technological Innovation
Commercially available energy storage projects are being deployed on the grid by the hundreds, ranging from kW-sized projects sited behind customers’ meters to greater-than-100 MW utility scale plants[2]. Investments in these projects, technologies, and creative new business models are being made by governments, entrepreneurs, and developers excited about energy storage’s economic and technical capabilities.
Due to expanding grid storage installations, increasing electric vehicle sales, technological improvements and economies of scale, installed costs of grid storage are dropping dramatically. In 2010, the US Department of Energy projected lithium-ion battery costs to fall from $1800/kWh in 2012 to under $250/kWh in 2020, and well-established thermal energy storage technologies now have installed costs under $500/kw. These massive cost reductions are making energy storage increasingly competitive in a growing array of grid applications.
3: Superior performance
As compared to many fossil-based status quo grid solutions, energy storage demonstrates superior performance and widespread benefits.
Many storage resources provide better precision compared to conventional generation. Where a state-of-the-art gas turbine takes 10 minutes to “ramp” to full power, many storage technologies can do so in less than one second. In a system where supply must always equal demand, this flexibility and accuracy are extremely valuable.
Energy storage systems also have 4 times the flexible range of equivalent capacity gas peakers (for example, a 100MW gas plant typically must generate at least 50MW, providing 50MW of flexible range, whereas 100MW of storage can charge at 100MW or discharge at 100MW, providing 200 MW of flexible range). Storage likewise has much higher utilization rates: gas peakers only run 20-40% of the year, whereas fast-responding storage resources have utilization factors over 95%. Energy storage co-located with relatively cleaner combined cycle gas turbines (CCGT) can even improve CCGT utilization factors and reduce reliance on dirtier plants. And the list goes on, from faster project development to reduced carbon emissions.
People in industry and government are recognizing these benefits every day. New system models are showing that energy storage is cost-effective when its full range of services and benefits are fairly accounted for. The reason for this is that energy storage delivers multiple benefits from one resource (e.g. reducing peak demand and providing grid support for frequency regulation). This is accelerating energy storage’s growth – and that acceleration is poised to keep on going.
4: Supportive Policies
Policies supporting energy storage, from financial support to procurement targets, are appearing worldwide, and the United States is at the forefront of that policy development.
In October 2011, the Federal Energy Regulatory Commission (FERC) issued “pay-for-performance” rules that reward accuracy in response times (FERC order 755). This increases competitiveness of fast-acting storage.
Policy support is also growing at the state level. California’s AB 2514 (Skinner) directed the California Public Utilities Commission (CPUC) to set procurement targets for the state’s investor-owned utilities for cost-effective energy storage. A landmark June 10 preliminary recommendation by Commissioner Carla Peterman set that number at an impressive 1.325 GW by 2020 and a final decision is anticipated in early October 2013.
In February 2013, CPUC directed Southern California Edison (SCE) to procure at least 50 MW of energy storage resource capacity in the Los Angeles basin to meet long-term local capacity requirements by 2021. Up to an additional total of 600MW of capacity is required to be procured from preferred resources and/or energy storage resources.
Finally, forward thinking utilities are moving forward with storage on their own. In May 2013, the CPUC granted San Diego Gas & Electric (SDG&E) the ability to rate-base $26 million toward the integration of energy storage resources for distribution support applications as part of their most recent general rate case.
All of these policies are giving investors confidence in both technology development and on-the-ground projects. They are key to market growth, and combined they are kick starting the transformation of our electric power sector.
Energy storage has been called the “holy grail of the electricity system,” half because of its amazing potential and half because it was seemingly unattainable. Now, we are entering an age where it has become attainable – and will improve the electric system for years to come.
[1] http://www.renewableenergyworld.com/rea/news/article/2012/04/grid-scale-energy-storage-lux-predicts-113-5-billion-in-global-demand-by-2017
[2] Project examples available at the Department of Energy’s International Energy Storage Database. http://sandia.gov/ess/database.
Source: Renew Economy
Wednesday, August 28, 2013
Japan contracts two massive Battery Storage Systems to balance Wind, Solar PV load
Japan's Ministry of Economy, Trade and Industry (METI) has chosen three companies to install two large-scale battery systems in the northern part of the nation to support the expansion of wind and solar on Japan's electric grid.
Through the Large-scale Storage Battery System Demonstration Project, Hokkaido Electric Power Inc. (Sapporo, Japan) and Sumitomo Electric Industries Ltd. (Osaka, Japan) will jointly install a 60 MWh redox-flow battery on the island of Hokkaido. Additionally, Tohoku Electric Power Co. Ltd. (Sendai, Japan) will install a 20 MWh lithium-ion battery in the Tōhoku region.
“This project is Japan’s first effort to introduce large-scale storage batteries in electricity grids, and METI aims to rapidly acquire the necessary technology and know-how so as to utilize such batteries in electricity grids in a specific manner,” declares METI in a press statement.
Projects to study frequency variation, supply/demand balance
The two projects were chosen via a public solicitation held in April 2013. Tohoku Electric Power's lithium ion project was chosen to address the issue of frequency variation, and Sumitomo's redox flow battery has been chosen to look at the technology's ability to balance supply and demand at times when demand falls.
The Tōhoku project will coordinate the lithium ion batteries to operate with conventional power generation while utilizing the batteries as much as possible to adjust frequency, suppressing the impact on battery life.
In the Hokkaido project, the companies will not only look at how well the batteries address varying electricity output from wind and PV, but also at developing technology to control and manage the battery system. METI notes that redox-flow batteries can be used to deal with supply/demand balance over a long period of time.
METI aims for the projects to increase the capacity of the supply-demand adjustment function by 10% in each region.
Sumitomo to develop battery based on results of tests
Sumitomo and Hokkaido Electric plan to complete installation of the redox flow battery by the end of 2014, and carry out verification tests over the next three years. The massive battery system will occupy two floors of new building roughly 5,000 square meters in size, with the electrolyte tank on the first floor, and the cell stack and heat exchanger on the second floor.
The battery system will have a storage capacity of 60 MWh, and a rated output of 15 MWh.
The company notes that redox flow batteries can be used for a wide range of applications, including addressing frequency variation. Based on the results of the tests, Sumitomo plans to offer a redox flow battery with improved performance.
Source: Solar Server
2013-08-09 | Courtesy: METI; Image: Sumitomo | solarserver.com © Heindl Server GmbH
Sumitomo's redox-flow battery will occupy
a new 5,000 square meter facility in Hokkaido
Through the Large-scale Storage Battery System Demonstration Project, Hokkaido Electric Power Inc. (Sapporo, Japan) and Sumitomo Electric Industries Ltd. (Osaka, Japan) will jointly install a 60 MWh redox-flow battery on the island of Hokkaido. Additionally, Tohoku Electric Power Co. Ltd. (Sendai, Japan) will install a 20 MWh lithium-ion battery in the Tōhoku region.
“This project is Japan’s first effort to introduce large-scale storage batteries in electricity grids, and METI aims to rapidly acquire the necessary technology and know-how so as to utilize such batteries in electricity grids in a specific manner,” declares METI in a press statement.
Projects to study frequency variation, supply/demand balance
The two projects were chosen via a public solicitation held in April 2013. Tohoku Electric Power's lithium ion project was chosen to address the issue of frequency variation, and Sumitomo's redox flow battery has been chosen to look at the technology's ability to balance supply and demand at times when demand falls.
The Tōhoku project will coordinate the lithium ion batteries to operate with conventional power generation while utilizing the batteries as much as possible to adjust frequency, suppressing the impact on battery life.
In the Hokkaido project, the companies will not only look at how well the batteries address varying electricity output from wind and PV, but also at developing technology to control and manage the battery system. METI notes that redox-flow batteries can be used to deal with supply/demand balance over a long period of time.
METI aims for the projects to increase the capacity of the supply-demand adjustment function by 10% in each region.
Sumitomo to develop battery based on results of tests
Sumitomo and Hokkaido Electric plan to complete installation of the redox flow battery by the end of 2014, and carry out verification tests over the next three years. The massive battery system will occupy two floors of new building roughly 5,000 square meters in size, with the electrolyte tank on the first floor, and the cell stack and heat exchanger on the second floor.
The battery system will have a storage capacity of 60 MWh, and a rated output of 15 MWh.
The company notes that redox flow batteries can be used for a wide range of applications, including addressing frequency variation. Based on the results of the tests, Sumitomo plans to offer a redox flow battery with improved performance.
Source: Solar Server
2013-08-09 | Courtesy: METI; Image: Sumitomo | solarserver.com © Heindl Server GmbH
Friday, July 12, 2013
ESS during 3rd Solar Generation Day
It is working well ! :-)
This Energy distribution pie charts show that, after 2/3rd the days before, Wednesday 3/4 of the Energy used in our home comes from Solar : Directly from the SMA Inverter, then from my ESS, and sometimes from both :-)
I also got a pretty good looking Power graph showing the Net Usage flirting with 0W during all the Solar Generation period and even later in the evening
After 2 days will wrong charts, Wattson Anywhere (beta) is back to normal and showing figures similar to Wattson Professional
Wednesday, February 20, 2013
California Sets 50MW Target for Grid Energy Storage
Moving past “paralysis by analysis,” the CPUC asks Southern California Edison to find 50MW of grid energy storage by 2021
California has just set a big new target for energy storage on the grid -- 50 megawatts of it, to be exact.
That’s how much energy storage capacity the California Public Utilities Commission (CPUC) is asking Southern California Edison to procure over the next eight years, according to a final decision issued Wednesday. It’s not a lot, compared to the total of 1,400 to 1,800 megawatts CPUC is asking the massive Southern California utility to procure between now and 2021 -- but it's still among the first, if not the first, state regulatory rulings that put grid storage at center stage.
The new decision also certifies energy storage as “preferred resources,” alongside energy efficiency, demand response and distributed generation resources, in California's Energy Action Plan, which tells utilities in which order they’re to buy the power and energy resources they need. Wednesday’s decision sets aside an additional 600 megawatts of capacity for SCE to obtain from such preferred resources.
All in all, it’s a “much-needed market signal that energy storage will be considered as a key asset class to help California address its long-term local reliability and environmental quality needs,” according to Janice Lin, executive director of the California Energy Storage Alliance (CESA). CESA’s member list includes some heavyweights in batteries (LG Chem, Panasonic, Saft), as well as two ice-energy air-conditioning storage players that happen to have significant operations in California: Calmac and Ice Energy.
Wednesday’s CPUC ruling comes amidst a years-long process to set energy storage requirements for the state as it grapples with the challenges of its renewable portfolio standard (RPS) ambitions. California wants to grow its share of grid power from renewable resources (mostly intermittent wind and solar, though some baseload geothermal and biomass as well) from about 20 percent today to 33 percent by decade’s end.
That’s going to introduce huge new stability problems for the grid. Energy storage expert Ed Cazalet has predicted that California could need up to 4 gigawatts of energy storagecapacity to help reach the 33 percent RPS, with both centralized, utility-scale wind power and distributed solar power as key factors to manage.
California Assembly Bill 2514, passed in 2010, called for a study of the state’s needs for grid-scale storage, but didn’t set any hard numbers on how much. The CPUC took up the issue last year, and it’s still in process.
Southern California Edison, along with big fellow state investor-owned utilities Pacific Gas & Electric and San Diego Gas & Electric, have opposed specific procurement mandates. SCE wrote in a CPUC filing that mandates “only serve to increase the return on investment of private storage developers,” while distorting the market for energy storage technologies not yet competitive in purer market terms.
There’s no doubt that many forms of energy storage -- batteries, in particular -- remain too expensive to compete against grid power. Where batteries have been deployed is in trouble spots on the grid: far-off distribution substations where batteries are cheaper than putting in new transmission lines to handle rare peak loads, or islanded grids (like Hawaii) facing an influx of on-again, off-again wind and solar power.
Of course, utilities also don’t want to be forced to engage with storage resources they don’t control -- and it’s likely they will need to be forced to open the market to third-party storage projects that work in the context of broader energy markets. Where storage is an intelligent alternative to transmission or generation build-out, and can help integrate renewables, it should be deployed. Of course, cheap natural gas also makes the status-quo approach of using peaker plants a potentially attractive option, though not so much in California, where clean air rules are the toughest in the nation.
CPUC Commissioner Michel Peter Florio, who authored Wednesday’s decision, called it a testament to the state's need to "move beyond paralysis by analysis with respect to energy storage" -- an apparent sign of impatience with the slow approach being taken to AB 2514 implementation. We’ll see if the CPUC applies similar logic to decisions for PG&E and SDG&E.
California is home to several large-scale energy storage project funded by Department of Energy smart grid stimulus grants. PG&E is building a 300-megawatt, 10-hour compressed air energy storage (CAES) system in the Central Valley, and Southern California Edison has been working with A123 Systems on an 8-megawatt, 32 megawatt-hour lithium-ion batterywarehouse of sorts in the Tehachapi mountain range. Both are aimed at stabilizing and integrating the state’s wind power resources into the grid.
We’re also seeing some examples of distributed energy storage emerge, though far smaller in scope and just getting started, with everything from backyard or garage batteries to backup solar installations (Tesla and SolarCity, Silent Power and Hanwha) to substation-scale grid balancing units in the 1-2 megawatt range (Greensmith and SDG&E).
California has just set a big new target for energy storage on the grid -- 50 megawatts of it, to be exact.
That’s how much energy storage capacity the California Public Utilities Commission (CPUC) is asking Southern California Edison to procure over the next eight years, according to a final decision issued Wednesday. It’s not a lot, compared to the total of 1,400 to 1,800 megawatts CPUC is asking the massive Southern California utility to procure between now and 2021 -- but it's still among the first, if not the first, state regulatory rulings that put grid storage at center stage.
The new decision also certifies energy storage as “preferred resources,” alongside energy efficiency, demand response and distributed generation resources, in California's Energy Action Plan, which tells utilities in which order they’re to buy the power and energy resources they need. Wednesday’s decision sets aside an additional 600 megawatts of capacity for SCE to obtain from such preferred resources.
All in all, it’s a “much-needed market signal that energy storage will be considered as a key asset class to help California address its long-term local reliability and environmental quality needs,” according to Janice Lin, executive director of the California Energy Storage Alliance (CESA). CESA’s member list includes some heavyweights in batteries (LG Chem, Panasonic, Saft), as well as two ice-energy air-conditioning storage players that happen to have significant operations in California: Calmac and Ice Energy.
Wednesday’s CPUC ruling comes amidst a years-long process to set energy storage requirements for the state as it grapples with the challenges of its renewable portfolio standard (RPS) ambitions. California wants to grow its share of grid power from renewable resources (mostly intermittent wind and solar, though some baseload geothermal and biomass as well) from about 20 percent today to 33 percent by decade’s end.
That’s going to introduce huge new stability problems for the grid. Energy storage expert Ed Cazalet has predicted that California could need up to 4 gigawatts of energy storagecapacity to help reach the 33 percent RPS, with both centralized, utility-scale wind power and distributed solar power as key factors to manage.
California Assembly Bill 2514, passed in 2010, called for a study of the state’s needs for grid-scale storage, but didn’t set any hard numbers on how much. The CPUC took up the issue last year, and it’s still in process.
Southern California Edison, along with big fellow state investor-owned utilities Pacific Gas & Electric and San Diego Gas & Electric, have opposed specific procurement mandates. SCE wrote in a CPUC filing that mandates “only serve to increase the return on investment of private storage developers,” while distorting the market for energy storage technologies not yet competitive in purer market terms.
There’s no doubt that many forms of energy storage -- batteries, in particular -- remain too expensive to compete against grid power. Where batteries have been deployed is in trouble spots on the grid: far-off distribution substations where batteries are cheaper than putting in new transmission lines to handle rare peak loads, or islanded grids (like Hawaii) facing an influx of on-again, off-again wind and solar power.
Of course, utilities also don’t want to be forced to engage with storage resources they don’t control -- and it’s likely they will need to be forced to open the market to third-party storage projects that work in the context of broader energy markets. Where storage is an intelligent alternative to transmission or generation build-out, and can help integrate renewables, it should be deployed. Of course, cheap natural gas also makes the status-quo approach of using peaker plants a potentially attractive option, though not so much in California, where clean air rules are the toughest in the nation.
CPUC Commissioner Michel Peter Florio, who authored Wednesday’s decision, called it a testament to the state's need to "move beyond paralysis by analysis with respect to energy storage" -- an apparent sign of impatience with the slow approach being taken to AB 2514 implementation. We’ll see if the CPUC applies similar logic to decisions for PG&E and SDG&E.
California is home to several large-scale energy storage project funded by Department of Energy smart grid stimulus grants. PG&E is building a 300-megawatt, 10-hour compressed air energy storage (CAES) system in the Central Valley, and Southern California Edison has been working with A123 Systems on an 8-megawatt, 32 megawatt-hour lithium-ion batterywarehouse of sorts in the Tehachapi mountain range. Both are aimed at stabilizing and integrating the state’s wind power resources into the grid.
We’re also seeing some examples of distributed energy storage emerge, though far smaller in scope and just getting started, with everything from backyard or garage batteries to backup solar installations (Tesla and SolarCity, Silent Power and Hanwha) to substation-scale grid balancing units in the 1-2 megawatt range (Greensmith and SDG&E).
Source: GreenTech Media
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