Month: March 2018

ENGIE’s commercial battery project drive $100k annual wedge into California’s water-energy nexus

California’s recent droughts and ongoing need to economise water use have inspired more commercial energy storage at a local water board, with ENGIE Storage delivering a project for the San Diego Water Authority.

The new battery energy storage project is expected to save the Authority (SDWA) US$100,000 per year on its energy costs. The batteries will be used to store low-cost solar energy for use during peak times and times of low solar generation. SDWA and ENGIE Storage, which was formerly known as Green Charge prior to its acquisition by the European utility, struck up a deal for the project in May 2017.

The batteries are being delivered under one of ENGIE Storage’s storage ‘as-a-service’ business models – they are being installed at no front cost to SDWA. Sited at Twin Oaks Valley Water Treatment Plant, they are coupled with 4,800 PV panels, already in place, that generate around 1.75 million kWh of power annually.

Andrea Altmann, senior management analyst at SDWA’s Energy Program, told Energy-Storage.News that the battery energy storage is a 1,000kW system which can store 2,000kWh per day. Altmann confirmed that the Water Authority “will be evaluating opportunities for more battery storage in the future,” in addition to exploring the construction of a possible 500MW pumped hydro facility and a handful of other initiatives.

The system is worth around US$2 million, with ENGIE Storage and SDWA striking up an agreement that the storage provider will own and operate it for 10 years. After this first decade, SDWA can consider purchasing the system, extending the existing agreement, or remove the project altogether from the site if desired. US$1 million in funding was available to the project through California’s SGIP (Self-Generation Incentive Program) which incentivises solar, and energy storage installed with solar.

It’s the latest project in California from the water sector. A project from fellow C&I energy storage market leader Advanced Microgrid Solutions (AMS) for Long Beach Water Department to build a 500kW / 3,000kWh energy storage system was expected to save the Department around US$150,000 a year when it was announced in late December 2017. Meanwhile, Los Angeles Department of Water and Power (LADWP) contracted Doosan GridTech to build a 20MW lithium-ion battery energy storage system (BESS), aimed at reducing LADWP’s reliance on natural gas. 

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GTM: US could smash 1GWh deployment in 2018

While research published this week demonstrates that the US as a whole is embracing energy storage technology, with regulator FERC’s recent wholesale market ruling likely to have a “significant impact”, the picture varies greatly when looking from state-to-state, an analyst has said.

GTM Research found that in four years between 2013 and 2017, the US deployed over a gigawatt-hour (1,080MWh) of grid-connected energy storage. While the last quarter of 2017 was relatively down on the corresponding period a year before – around 77MWh to about 230MWh in Q4 of 2016 – this was due to the impact of long duration lithium-ion projects expedited in California in response to the Aliso Canyon gas leak.

Interestingly, despite the higher megawatt-hour capacities of those Q4 2016 (and Q1 2017) projects, installations in megawatts were slightly less down in Q4 2017, partly because of the growth of behind-the-meter projects, which took a 55% share of the total megawatts deployed. Behind-the-meter grew 79% year-over-year, while GTM senior analyst Dan Finn-Foley told Energy-Storage.News that the research group expects BTM to overtake grid-level projects for deployments by 2022.

Either way, despite the US only just crossing the first GWh threshold, GTM, which featured the findings in its quarterly Energy Storage Monitor’s annual review edition, predicts the country could replicate that feat four years in the making during 2018 alone, with 1,233MWh of deployments forecast for this calendar year. This would compare favourably with 2017, which saw 431MWh installed, nonetheless an increase of 27% on the year before that.

FTM opportunities quickly snapped up, regional outlook varies

At last week’s Energy Storage Summit held in London, England, several commentators spoke about how, in their view, market opportunities for front-of-meter grid services, especially frequency response will always remain limited and while an exciting first move for battery technologies, a quickly-saturated opportunity.

GTM’s Dan Finn-Foley agreed that this was the case in the US too, to some degree, albeit while acknowledging that future drivers of such a market are not fully known yet.

“This is indeed the case in the frequency regulation market, which is by its very nature a small market when compared to overall generation,” Finn-Foley told Energy-Storage.News.

“In PJM the market saturated, and we are seeing that in Texas now, where we are seeing installed capacity reach the 65MW cap in the ERCOT fast-responding signal market. With capacity applications, transmission and deferral projects, and renewable integration, it is more difficult to define a “cap”, so there is more headroom for the industry here.”

On one of the biggest recent stories to come out of the US regarding energy storage, FERC’s decision to evaluate the possible role and values of energy storage in wholesale markets, Finn-Foley said it could be a transformative move when regional transmission organisations’ (RTOs) responses to FERC have been collected and the market opens up.

It will take a year before the “tariffs are defined” and a further two years before full implementation, the analyst said, “but the effects will be significant”.

“Leveling the playing field for energy storage will allow it to compete in favorable markets (such as frequency regulation in some markets where it has limited paths for eligibility) but also give certainty for companies to create innovative business models involving participation in multiple markets,” Finn-Foley said, adding that GTM expected the proceeding to add some upside to forecasting, but that proceedings at regional level by independent system operators (ISOs), which “mirror the priorities of the FERC Order”, were taken into account already.

Indeed, as with solar PV, breaking the US down into regional or state markets can sometimes be key to understanding the real picture. Part of the rise in FTM deployments in MWh came from a handful of recent North Carolina long duration projects, for example.

As with each edition of the Monitor, GTM provides a look at policy and market developments state-by-state. Some key findings included the Public Utility Commission of Texas moving to study storage ownership by distribution utilities, low bid prices in a recent solicitation by utility Xcel in Colorado, New York’s newly established 1,500MW energy storage target, Arizona’s proposed 3GW target, Maryland’s energy storage tax credit, tax credits for BTM storage in Virginia and New Mexico, and a California Public Utilities Commission order on creating ‘virtual net metering’ programmes for energy storage and considerations of the greenhouse gas emission-reducing potential of energy storage in the ongoing SGIP incentive programme for solar and solar-plus-storage purchases by households and businesses.

Even the FERC Order, applying to about two-thirds of the US covered by RTOs and ISOs, will be subject to great regional variation and of course in several instances grid networks cross over state lines.

“It’s important to note that the FERC order is a federal directive but it is up to each ISO to implement at a local or semi-local basis, so this is a “federal” act that will ultimately be interpreted and implemented differently at the regional level,” Finn-Foley said.

“By this metric almost all storage has been driven at the local level, primarily by mandates and incentive/pilot programs at the state level, with the notable exception of PJM’s frequency regulation market which drove significant growth.”

Finn-Foley did note that on a Federal level, a tax credit for energy storage, already being considered by the House of Representatives, was a rare form of policy which could impact the industry across the whole country and could “drive [federal-level] growth at a similar scale to state efforts”.

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California utility SDG&E seeks 166MW energy storage as public emergency response asset

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.

Crucially, AB2868 requires the PUC to prioritise programmes and investments “that provide distributed energy storage systems to public sector and low-income customers”. Failure to comply with this aspect of the legislature constitutes a crime, the bill reads, making AB2868 a “state-mandated local programme”. 

In late December 2017, another of the California IOUs, Pacific Gas & Electric (PG&E), announced a similarly-sized procurement, 165MW across six projects. Unlike SDG&E’s latest procurement, PG&E’s was intended for each project to address at least one of the following three issues: optimisation of the grid, integration of renewable energy and greenhouse gas reduction. In April last year, SDG&E also signed contracts for 83.5MW of four-hour duration energy storage to provide capacity by 2021, while in February it opened what was at the time the world’s biggest lithium battery energy storage system, a 30MW/120MWh project in Escondido. 

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GTM: Front-of-meter cost declines will slow as industry grows 6x over by 2022

While energy storage system price declines have slowed down in recent times in the US, standardisation of design and engineering will be among the key drivers in bringing down balance-of-system hardware and EPC costs.

A new report from GTM Research, analysing prices for front-of-meter, mostly grid-scale energy storage systems in the US, makes the claims, forecasting that there will be annual price declines of about 8% through to 2022. This is a slower pace than previous declines, lead author and industry sector analyst Mitalee Gupta said.

GTM said it expects front-of-meter energy storage systems, installed at utility or grid-level to benefit the network with services including frequency regulation and, increasingly, capacity, rather than the benefits to end customers such as increased solar self-consumption or peak load shaving which come from behind-the-meter systems, will grow six times in number between 2017 and 2022. 

Timeline for price decline trends in four ‘Phases’

The company also supplied the graph below which highlights some key trends.

It shows that while battery price declines were the initial driver for overall drops in system prices between 2013 and mid-2014, by 2015 reductions in BoS costs, defined by GTM as every component in the energy storage system excluding the battery module or modules, had taken over as the primary driver of price reductions.

From around mid-2016, GTM’s graph shows that increased uptake of advanced lithium battery solutions for stationary storage across various markets, drove down battery prices and BoS costs even further. Production ramp up, growing competition and system design and engineering improvements all converged as factors causing the trend of price reduction to continue.

Looking to the future, Phase 4 of price decline trends as defined by Gupta and her team of energy storage analysts, which is expected to take place from late 2019 to 2022, will see a slowing rate of decline in battery and BOS prices, particularly after 2020. Further improvements will be derived from the collective experience of the industry, GTM predicted.

Software, inverters as critical components

While only one part of an energy storage system, lithium battery costs per kWh have approximately halved in the last 10 years from industry benchmarks of around US$500 per kWh to a range of about US$250 to US$350 per kWh today, according to various other sources. Meanwhile, GTM asserts that at present BOS costs which include inverters and thermal management systems, make up about 40% of a system’s total ‘price stack’.

Storage inverters are more expensive than solar-only devices, as they generally require bi-directionality (the ability to output power or to charge up from the grid), GTM said. However, there is nonetheless industry pressure on the makers of inverters to “decrease the price premium” on storage inverters.

Energy storage software, often identified as an increasingly important piece of the overall system for the management, control and monitoring capabilities it allows, is estimated by GTM to cost US$37 per kW by 2022.

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