San Diego Gas & Electric (SDG&E), one of California’s three main investor-owned utilities (IOUs), said this week that it will add resilience and backup capabilities to public sector buildings through the procurement of “up to 166MW” of energy storage.

According to a proposal submitted by the utility to regulator California Public Utilities Commission (CPUC), public sector buildings that serve as emergency facilities during emergency situations, providing safety and security in earthquakes, forest fires and other potential disasters, would be supported by seven energy storage projects.

Fire stations, police stations, evacuation sites and emergency operation centres would host the systems. It appears all seven projects have been proposed and to some extent developed already, with their installation planned in phases leading up to completion by 2024.

The utility is also including in the procurement drive a means for nonprofit care facilities to receive incentives to purchase energy storage systems. The Energy Storage Customer Program Pilot, as it will be known, will enable care homes of various types to receive cash sums towards funding system purchases. Currently, California also has in place the statewide SGIP (Self-generation Incentive Program) which offers residential and business customers incentives on purchases of storage systems, but only if deployed in combination with solar PV.

SDG&E said the filing of the proposal is in line with the terms of California legislature Assembly Bill 2868, which was brought into law by CPUC in late 2016. It instructs the state’s investor-owned utilities, bound by another rule, AB2514, to put in place plans to deploy between them 1.35GW of energy storage in their service areas by 2020, to “file applications for programs and investments to accelerate widespread deployment of distributed energy storage systems”. SDG&E said it expects to deploy more than 330MW of energy storage by 2030.

SAN DIEGO, Feb. 28, 2018 /PRNewswire/ — Today, San Diego Gas & Electric (SDG&E) took another step toward preparing the region for the next major emergency. The company announced plans to add up to 166 megawatts (MW) of energy storage in a proposal submitted to the California Public Utilities Commission (CPUC). If approved, the projects would support public-sector facilities that provide safety, security and emergency services during power grid outages.

The initial projects – seven in total – would be in San Diego County’s rural and urban areas and serve critical public-sector facilities such as fire and police stations, emergency operation centers, and emergency evacuation sites. Providing these public facilities with energy storage systems will help maintain vital operations that serve the public’s well-being. Pending CPUC approval, the plan would be implemented in phases over the next few years with all projects in operation by 2024.

“The innovative projects were developed through close collaboration with local leaders and will significantly increase the resiliency of critical public-sector infrastructure,” said Scott Drury, SDG&E’s president.

SDG&E’s plan also includes an Energy Storage Customer Program Pilot. It would provide incentives for nonprofit care facilities to purchase energy storage systems. Eligible nonprofit low-income care facilities would include, but are not limited to, short or long-term care (hospice, nursing homes, children’s and senior’ homes), group homes for physically or mentally disabled persons, or other nonprofit group living homes.

The proposals are in response to California’s Assembly Bill 2868 which was signed into law in 2016 and allows the company to add distributed energy storage.

Pending CPUC approval, SDG&E would issue a solicitation to identify a third party to administer the Energy Storage Customer Program Pilot. The company expects to launch the program within one year of CPUC approval.

Energy storage is playing a key role in SDG&E’s commitment to deliver clean, safe and reliable energy. By 2030, the company expects to develop or interconnect more than 330 MWs of energy storage. These projects will help deliver more renewables to customers and help strengthen SDG&E’s record as the most reliable utility in the West.

Scientists at the University of California, Irvine; the California Institute of Technology; and the Carnegie Institution for Science have released an analysis of the U.S. electricity grid managing expanding volumes of intermittent generation in the research journal Energy & Environmental Science.

Geophysical constraints on the reliability of solar and wind power in the United States posits that the U.S. electrical grid could be 80% powered by a solar-heavy+wind power combination using just 12 hours of energy storage to smooth out the variability.

The paper also shows that a wind-heavy+solar power electricity grid would require a nationwide high voltage DC (HVDC) network to move electricity from wind energy dense mid-western regions toward the coasts. The solar heavy network wouldn’t need energy storage with an HVDC network.

To reach a 100% wind+solar U.S. electricity grid would require 3 weeks of energy storage. According to lead author Dr. Matthew R. Shaner.

The U.S. currently uses about 3,900,000 terawatt-hours (TWh) per year. A 12 hour chunk of that would be about 5.4 TWh. At a cost of $350 per kilowatt-hour (kWh), that would cost $1.9 trillion. If each of the 110 million single family homes in the U.S. were to install an energy storage system, and split the total volume needed with the electricity utilities, we’d need approximately 24kWh/home.

About equal to a couple of Powerwalls, a little larger than a Sonnen or 1/2 of a Model 3.

Supplemental information was included with the abstract at the journal website. In it were visualizations of various models, some examples below. The models were mixtures of solar, wind, over sizing these two resources and energy storage. One model, with 100% solar plus 50% over capacity paired with 12 hours of energy storage got us to 93% reliability.

SunPower followed up last week’s tough earnings call with more hopeful news.

The veteran solar manufacturer and developer is launching a commercial energy storage business under the Helix commercial solar brand. It will design, install and operate the battery systems with its own software controls to manage demand charges and optimize solar generation.

In doing so, the company hopes to leverage the experience it has installing and overseeing commercial solar to date, which is unique among commercial storage providers.

“SunPower has a decade of experience monitoring nearly 1.7 gigawatts of commercial solar projects to best understand how they perform, giving us a unique advantage when maximizing the value of a complete solar-plus-storage solution,” said Norm Taffe, SunPower executive vice president for products, in a statement.

SunPower’s focus on a hybrid solar and storage product sets it apart from commercial storage developers like Stem and AMS, which specialize in standalone batteries that reduce customer demand charges and dispatch to serve broader grid needs.

Still, the company’s turn to commercial storage hints at the desperate times that last week’s earnings report detailed.

The U.S. commercial storage market has sustained around 50 projects per quarter lately, almost entirely confined to California, where they rely on the Self-Generation Incentive Program to make deals pencil out.

The ebbs and flows of SGIP disbursements drive wild swings in deployment from quarter to quarter. The U.S. commercial storage market saw a record 13.9 megawatts deployed in Q2 last year, only to plunge 51 percent to 6.8 MW in Q3, according to GTM Research.

But the solar market isn’t looking too balmy either.

Stem, the global provider of artificial intelligence (AI)-driven energy storage services, is deploying a 2.5-MWh energy storage system in St. Mary’s, Ontario at INOAC Interior Systems. INOAC, a supplier to the automotive industry. The system will save money and help reduce the expensive electricity peaks that impact all electricity consumers in the province.

With Stem, INOAC aims to reduce their Global Adjustment and energy costs automatically—without changing plant operations or making a capital investment.

Based in Japan, INOAC is a diversified manufacturing company established in 1926, with over 100 facilities operating in 20 countries and over 20,000 employees.

“As an environment-friendly manufacturer, INOAC has strong environmental policies that guide our corporate operations. The opportunity to leverage an emissions-free resource while improving cost efficiency were the driving factors in our decision,” said Roger Dawes, President of INOAC Interior Systems Inc. “Stem’s AI-driven platform and execution experience enables an automated way to reduce energy costs with no interference in our operations.”

Each year, the Independent Electricity System Operator (IESO) determines Ontario’s five highest hours of net energy demand for the previous 12 months. Class A eligible customers that participate in the Industrial Conservation Initiative pay Global Adjustment based on their percentage contribution to the top five peak demand hours.

“Unleashing the benefits of energy storage technology is a key focus of Ontario’s 2017 Long-Term Energy Plan and an important part of our continued commitment to improve energy affordability for our province’s job creators,” said Glenn Thibeault, Minister of Energy. “Through our Industrial Conservation Initiative (ICI) program, we’re also providing incentives for large electricity consumers, like INOAC Interior Systems, to reduce their consumption during peak hours and lower their electricity costs. This program is benefiting both families and businesses, and the electricity system as a whole by deferring the longer-term need for investments in new peaking generation.”

A key advisory panel to the Department of Energy wants to move ahead on a biennial assessment required by law of how the agency is doing in its support of the U.S. energy storage technology.

But the committee is waiting to hear back from DOE on its response to recommendations in its last report from 2016 before it can move ahead in earnest, said Ramteen Sioshansi, a professor at Ohio State University and the chairman of the Energy Storage Subcommittee of DOE’s Electricity Advisory Committee (EAC).

“My strong preference would be to have a response to the ’16 assessment before doing the ’18 assessment,” Sioshansi said. While waiting, his panel will “do a little bit of preliminary ground work on the ’18 assessment,” he said.

The storage subcommittee submitted its 2016 assessment in September of that year. The report made recommendations in 15 areas, ranging from program goals, demonstration projects and funding to the economics of energy storage and its interplay with current electricity market designs.

Typically, DOE has responded to such reports from the EAC or its subcommittees in a matter of months, accepting or rejecting recommendations.

“There was a lengthy transition period so I can understand some things may be taking a little longer to get out of the department, so that’s understandable from my perspective,” said Sioshansi. “I understand there are a bunch of eyes looking at [the response],” he added. “They want to put out a response that they’re happy with.”

The biennial assessment on energy storage is required by the Energy Independence and Security Act of 2007. It is supposed to evaluate how DOE is meeting the goals of a five-year plan to support energy storage industry efforts in electric drive vehicles, electricity transmission, and distribution and stationary applications.

At the meeting of the EAC in Arlington, Va., last week, during a segment on regulatory reforms, members of the committee were presented with a list of options, among which were doing away with the five-year plan and the assessments every two years.

Researchers at Korea’s Advanced Institute of Science and Technology (KAIST) have developed a new type of aqueous energy storage device that they claim can be charged in less than half a minute.

Employing aqueous electrolytes instead of flammable organic solvents, the device is claimed to enable a boosting charge with high energy density, potentially making it suitable for a range of portable electronic devices.

According to the group, which was headed up by Prof Jeung Ku Kang from the Graduate School of Energy, Environment, Water, and Sustainability the system owes its performance to a design that assembles fibre-like polymer chain anodes and sub-nanoscale metal oxide cathodes on graphene.

Conventional aqueous electrolyte-based energy storage devices have a limitation for boosting charges and high energy density due to low driving voltage and a shortage of anode materials.

Energy storage device capacity is determined by the two electrodes, and the balance between cathode and anode leads to high stability. In general, two electrodes show differences in electrical properties and differ in ion storage mechanism processes, resulting in poor storage and stability from the imbalance.

The research team came up with new structures and materials to facilitate rapid speed in energy exchange on the surfaces of the electrodes and minimise the energy loss between the two electrodes.

The team made anodes with graphene-based polymer chain materials. The web-like structure of graphene leads to a high surface area, thereby allowing higher capacitance.

For cathode materials, the team used metal oxide in sub-nanoscale structures to elevate atom-by-ion redox reactions. This method realised higher energy density and faster energy exchange while minimising energy loss.

The device can be charged within 20 to 30 seconds using a low-power charging system, such as a USB switching charger or a flexible photovoltaic cell.