California regulators want to direct $100 million in state energy storage incentives to a new class of disadvantaged customers: those living in parts of the state at the highest risk of deadly wildfires.

The California Public Utilities Commission issued a proposed decision last week on the “equity budget” within the Self-Generation Incentive Program, the state’s main incentive program for behind-the-meter batteries.

The proposed decision would direct $100 million from SGIP’s equity budget — a set-aside aimed at low-income, medically compromised or otherwise disadvantaged residents — to vulnerable households, critical services facilities, and low-income solar program customers in Tier 3 high-fire-threat districts.

These types of customers are far more likely to find value in multihour batteries attached to their rooftop solar system than the typical low-income or elderly California resident who would qualify for the equity budget. That, along with the potential to supply critical infrastructure with solar-storage systems, is likely to make for an attractive target market for solar and energy storage developers like Sunrun and Tesla.

The proposed decision could be voted on by the CPUC as early as next month. Last year, California’s legislature extended the SGIP for five more years and provided about $830 million in total funding.

SGIP’s equity budget offers higher incentives than the mainstream program for behind-the-meter battery installations, from 35 cents to up to 50 cents per watt-hour.

While the new proposal would only cover next year’s SGIP budget at present, the CPUC plans to consider collecting up to $100 million annually to keep the program going.

California faces a years-long public policy challenge to tackle its increasingly deadly wildfires, fueled by expanding human development, hotter and drier conditions caused by climate change, and in some cases utility power lines such as the Pacific Gas & Electric transmission line that started November’s Camp Fire, which killed 85 people and caused an estimated $12 billion in damage.

The article “Fire at Arizona Energy Storage Battery Draws Scrutiny” (ENR 7/8-15 p. 18) illuminated the potential hazards associated with energy storage systems and lithium-ion batteries and accurately noted that the technology “now make[s] up 98% to 99% of all new battery-type storage systems.”

Near-ubiquitous use of these devices makes it critically important to recognize risks they present to people and property. In particular, first responders, who may encounter hazmat issues, thermal runaway concerns, battery explosion and reignition and off-gassing may find themselves in dangerous situations.

To that point, it was surprising to see that the article downplayed the impact of the April 19 energy storage system (ESS) explosion at the Arizona Public Service Co., stating that injuries sustained by eight firefighters and a police officer were “non-life threatening.” Of the firefighters injured, three required an extended hospital stay. The most serious injuries included a firefighter who had a “nose fracture, skull fracture, collapsed lung, rib fractures, broken tibia and fibula and an artery cut in his left leg.” Others sustained multiple fractures, burns and concussions.

The article also seems to minimize inherent ESS hazards, stating, “What we’re learning over time is that it’s not necessarily always a battery problem.” The hazard lies with the battery chemistry; thus, trying to direct attention away from that aspect can be dangerous.

As with so many new and emerging issues, it is important to develop corresponding information to better educate audiences about risks and about measures needed to ensure that systems are designed properly and are safely handled in the event of a fire or other emergency.

The National Fire Protection Association is set to release NFPA 855, Standard for the Installation of Stationary Energy Storage Systems, in early September. It provides requirements based on technology used in energy storage systems, the setting where the technology is being installed, the size and separation of ESS installations and fire suppression and control systems that are in place.

NFPA also has added ESS resources, including online training for the fire service, key research that is educating a broad range of stakeholders and other related content that can be found on our website at nfpa.org/ess.

NEC Energy Solutions (NEC ES) recently announced six additional energy storage projects of more than 20 MW at municipal power plants throughout New England including Madison, Maine, and Ashburnham, Templeton, Wakefield, Middleton and Taunton, Massachusetts. The new projects follow the model of the Sterling Municipal Light Department installed two years ago that has saved ratepayers more than $1 million on their utility bills. These energy storage systems reduce costs for transmission and capacity charges.

NEC’s most recently contracted project with the Taunton Municipal Lighting Plant (3 MW/6 MWh) will be one of the largest in New England to date. TMLP plans to operate the GSS Grid Storage Solution from their Cleary-Flood Generating Station, where system conditions are monitored 24/7. Through reducing transmission and capacity costs during peak demand times, the project will provide savings to TMLP ratepayers for years to come.

The energy storage systems include NEC’s GSS end-to-end grid storage solution and its AEROS controls system, which is NEC’s proprietary energy storage control software platform. The storage systems are dispatched to reduce the municipal power plants heaviest electric loads each month. These peak periods determine their yearly capacity costs and monthly transmission costs.

Three of Massachusetts municipal power plants including Ashburnham, Templeton and Wakefield are partnering with Massachusetts Municipal Wholesale Electric Company (“MMWEC”). The Wakefield, Ashburnham and Templeton projects use MMWEC’s peak load forecasting system and remote dispatch program. MMWEC staff predicts the best time to dispatch the batteries based on its forecasts of increased electricity demand, and the batteries are then remotely dispatched from MMWEC’s 24/7 operations center in Ludlow, Mass.

Several of the projects were made possible through grants from the Advancing Commonwealth Energy Storage (ACES) program, including Wakefield, Ashburnham and Taunton. The ACES program, a partnership between the Massachusetts Clean Energy Center (MassCEC) and the state Department of Energy Resources (DOER), is a competitive grant initiative to pilot innovative, broadly-replicable energy storage projects that advance energy storage technologies in Massachusetts.

Energy Storage Solutions (E22) and Alencon Systems have partnered to offer a unique, turnkey DC-coupled solar-plus-storage solution. The integrated solution offered by E22 is called the DC POWER OPTIMISER.

The DC POWER OPTIMISER consists of a DC-to-DC bidirectional converter, Alencon’s Bi-Directional Optimizer for Storage Systems — the BOSS, connected to a battery, packaged in a single containerized package. This container includes control and communication equipment, a battery management system and cooling and safety systems as well as Alencon’s BOSS. The unit is compliant with UL1741 and designed to UL9540A. These distributed systems can connect with string inverters sized up to 150 kW and 1,500 VDC. The system is controlled via E22’s ETER software, a proprietary energy management and system control software platform developed by E22.

Alencon’s BOSS bi-directional DC-DC optimizer along with E22’s solutions will be on display in Alencon Booth #2629 at SPI.

E22’s DC POWER OPTIMISER offers a turnkey DC-coupled solar-plus-storage solution which provides users a number of powerful benefits over traditional AC-coupled systems while eliminating the system configuration challenges and deployment limitations of other DC-coupled solutions. The DC POWER OPTIMISER offers greater round-trip efficiency, while firming intermittent solar output to both extend solar production and turn solar into a truly dispatchable energy resource. By DC-coupling the battery to the solar, the DC POWER OPTIMISER also captures solar energy that would otherwise be clipped during times of overproduction. DC-coupling solar and storage with the DC POWER OPTIMISER also allows for favorable IRS tax treatment of the system, further improving the economics offered by E22’s solution.

Including Alencon’s BOSS galvanically isolated, rack-level DC-DC converter in this container provides a myriad of benefits to project owners. The DC POWER OPTIMISER can be easily connected to the grid via a string inverter, the first DC-coupled system to offer such a feature. This will allow PV plant owners to easily integrate storage into existing PV plants using string inverters. The inclusion of the BOSS also allows for superior system safety and maximum battery rack utilization by isolating each battery rack. By controlling the charge of the system at the rack level, the BOSS assures maximum utilization of each battery rack while at the same time improving system safety by minimizing the risk of fault currents and other safety risks. The battery rack level charge approach provided by the BOSS also greatly simplifies battery rack augmentation that will invariably need to occur over the life of a solar-plus-storage project.

A report out today on the causes of the UK’s recent blackout, where electricity supply to 5% of National Grid’s customers was cut off “to protect the other 95%”, highlighted that 475MW of batteries were used to help bring the network back online.

A timeline of events produced by National Grid ESO, based on interim findings conducted by the Electricity System Operator and submitted to regulator Ofgem on Friday evening, shows that a lightning strike the previous Friday evening had triggered events that led to loss of power for around 1.1 million customers and reportedly causing chaos on transport networks.

Our sister site Current± reported today that lightning hit a transmission circuit – the Eaton Socon – Wymondley Main. But while the grid’s protection systems operated normally and cleared the lightning within 0.1 seconds, shortly after there was a near simultaneous loss of load from both the Little Barford CCGT power station and Hornsea One offshore wind farm.

Those trips, National Grid ESO has concluded, were entirely independent of each other – dispelling a previous theory that a trip at one plant caused the other to de-load – but both were connected to the lightning strike. The lightning strike also caused some losses from embedded generators in the area of the lightning strike, equivalent to around 500MW, after the Loss of Mains protection system kicked in. All in all, close to 1.4GW of load was lost from the system, which is prepared for the loss of capacity equivalent to its biggest generator, a 1.2GW nuclear reactor, Sizewell B.

What National Grid described as an “extremely rare” event – the ESO deals with more than 1,000 lightning strikes a year – then occurred as frequency continued to fall even as 1,000MW of backup power was called on, including 475MW of battery energy storage.

Customers on the distribution network had to be automatically disconnected to “ensure the safety of the network in a controlled way and in line with parameters pre-set by the UK’s distribution network operators (DNOs), which feed power from the grid into peoples’ homes and businesses.

GlidePath Power Solutions has acquired eight wind projects in North Texas with a total capacity of 149MW.

The portfolio, purchased from Exelon Generation, will be optimised by GlidePath while it plans how best to add energy storage on-site at each project. The projects are all north of Amarillo and sell into the Southwest Power Pool (SPP).

Chris McKissack, Chief Operating Officer for GlidePath told Energy-Storage.News:

“We believe there’s an opportunity to build out storage facilities up to the nameplate capacity of the wind farms in the portfolio. There’s great potential for storage to reduce transmission congestion and improve the economics of wind farms in SPP and other markets.”

According to GlidePath, they will be the first battery storage projects in the SPP.

“The high penetration of wind energy in North Texas offers us an excellent opportunity to pair these facilities with the latest battery storage technology,” said David Braun, president, GlidePath Asset Management. “We look forward to managing these wind assets in a way that will hopefully strengthen the reliability of supply in the local electric grid and deliver benefits for Texas power consumers.”

In June, SPP revealed that it would launch the Western Energy Imbalance Service market (WEIS) with settlements every five minutes. The previous balancing market run by SPP was launched in 2007 and paid out US$103 million in its first year.

GlidePath has a 1GW battery storage development portfolio, including a 10MW /10MWh project in Texas announced in April this year.

It is often difficult to evaluate the benefits, effectiveness and costs of energy storage technologies. These benefits are dependent on how one uses storage and which technology is used for what purpose. The cost of using an energy storage asset also depends on the initial material and installation costs, as well as how well it is maintained during its service life.

These aspects are interconnected and, until now, customers have not been able to easily access this information with a simple test.

The new Levelized Cost of Using Storage (LCUS) method combines acquisition costs, operations and maintenance (O&M), expected use, and service life data into a single meaningful metric to compare different energy storage technologies.

When used properly, LCUS will allow users to make informed decisions when selecting the right energy storage technology for their specific application(s) more simply and effectively than any other method. LCUS is useful in three practical ways:

It compares the cost among different energy storage technology choices — whether they consist of different technologies, formats, designs or manufacturers.

It compares the costs of different applications of a particular energy storage technology or product.

It helps shed light on how certain operating modes affect the total cost of ownership.

True-to-Life Considerations
LCUS calculates the cost of the storage with respect to how much storage is really used, and not the size of the storage asset. It can compare the full cost of using different storage technologies and using the storage in different applications. It can also assess the trade-offs and limitations of different system designs, operating modes, application duties and service regimes.

North Carolina’s draft Clean Energy Plan was published last week, including the retirement of 4GW of coal and putting in place measures to drive renewable energy and EV adoption in the US state.

Governor Roy Cooper gave an executive order in October of last year which made a commitment to “address climate change and transition to a clean energy economy”. Cooper’s order, Executive Order 80, stated that by 2025 North Carolina “will strive to accomplish” three key aims: reduce greenhouse gas (GHG) emissions to 40% below 2005 levels, to increase the adoption of electric vehicles (specifically, zero-emission vehicles) to “at least 80,000” and to reduce energy consumption in state-owned buildings by at least 40% from 2002 – 2003 baseline figures.

As instructed by Executive Order No.80, the North Carolina Department of Environmental Quality’s State Energy Office has now published a draft plan which supports those aims, open to a brief period of public comment until 9 September. The policy and recommended actions document looks at short term, medium term and long term objectives and measures.

For short term implementation – i.e. within two months of the plan’s introduction, the office recommended the creation of a revised state Clean Energy Standard should include specific targets for 2030, as well as creating new incentives and targets, which could consider newer technologies such as energy storage which have not previously been included. Better mechanisms to reward energy efficiency need to be considered.

There is also the question of retiring and replacing fossil fuel plants, particularly coal and the document calls for retirement dates to be given for North Carolina’s coal plants that are shown be rapidly becoming uneconomical to operate. The same goes for “uneconomical peaking power plants”, with cooperatives and municipalities to be given more power to replace those peaking gas plants with low or zero emissions sources that can provide the same services.

Managing demand on the power grid continues to grow increasingly more complex. Along with the urgent need to reduce carbon-based energy generation, consumer demand for energy is growing and shifting hourly, daily, monthly, and seasonally. New distributed energy resources are being developed and integrated at a faster rate every day and renewable generation and its variability are being brought online faster than predicted. All these factors make it more challenging for all utilities to meet demand when and where it is needed.

As more aggressive goals are set to transition the electrical system away from fossil fuels, energy storage is poised to be the economical solution to address the rapid growth and variability of distributed renewable generation. Energy storage growth is market-driven as power can be worth less than zero at times in some regions and power providers look for ways to avoid investing in costly new generation assets. But this growth is also being incentivized and regulated by federal and an increasing number of state governments.

In early 2018, the Federal Energy Regulatory Commission (FERC) created Order 841 directing Regional Transmission Organizations and Independent System Operators to remove barriers to the participation of electric storage in wholesale markets. The U.S. Department of Energy announced a $30 million project to fund long duration research projects. And as of June 2019, 15 states led by California, Massachusetts, and New York have developed energy storage policies designed to meet aggressive carbon-reduction goals by encouraging further development and integration of new energy storage technologies.

Different energy storage technologies have different capabilities. Two metrics used by the U.S. Energy Information Administration to describe energy storage are power capacity and energy capacity. Power capacity is the maximum amount of power output available at any one instant and is measured in megawatts (MW). The energy capacity is the total amount of energy that a storage system can store or discharge and is measured in megawatt hours (MWh). Energy capacity is a factor of both the amount of power and the length of time that power can be discharged. A battery system that can discharge power for 4 hours or more is referred to as long duration energy storage. A Navigant Research report explains that, “Interest in long duration energy storage is rising as the rapid growth of variable output renewables continues and issues with grid stability and efficiency become more tangible for grid operators.”

August 19 (Renewables Now) – Japan’s NEC Corp (TYO:6701) today said its subsidiary NEC Energy Solutions (NEC ES) has secured contracts to install more than 20 MW of energy storage systems across New England.

The capacity will be added at municipal power plants at six sites in the states of Main and Massachusetts. One of those is a 3-MW/6-MWh facility for Massachusetts utility Taunton Municipal Lighting Plant, which will be among the largest in New England once completed.

The energy storage systems will use NEC’s GSS end-to-end grid storage solution and AEROS software control platform. The goal will be to lower the municipal power plants’ electric loads during peak periods and in turn trim capacity and power transmission costs, NEC explained.

Some of the projects, such as those in Wakefield, Ashburnham and Taunton, were realised with grants from the Advancing Commonwealth Energy Storage (ACES) programme. ACES represents a partnership between the Massachusetts Clean Energy Center (MassCEC) and the state Department of Energy Resources (DOER) that aims to support innovative “broadly-replicable” energy storage projects in Massachusetts.

Steve Fludder, CEO of NEC Energy Solutions, noted that the company has installed more than 750 MW of energy storage systems globally.