Month: February 2018

The outlook for Energy Storage in New York is bright – here’s why

2018 promises to be an exciting year for energy storage in New York State. The year began with a major announcement by Governor Andrew Cuomo who, in his annual State of the State address, announced a new energy storage initiative and set an unprecedented 1.5GW target for energy storage deployment in the state by 2025. Governor Cuomo also announced the investment of more than US$260 million in funding to accelerate the growth of the industry. The initiative is intended to spur the widespread deployment of energy storage systems in the state and grow 30,000 jobs in the state’s energy storage industry.

Governor Cuomo’s announcement came on the heels of his approval of energy storage deployment legislation at the end of 2017. The new law, which requires the Public Service Commission to establish an energy storage goal and deployment policy for 2030, was passed unanimously, with bi-partisan support, by the NYS Legislature.

These combined actions are a clear signal that New York is serious about energy storage.

Mapping the way forward

The key question however, is how New York will achieve the level of energy storage called for by the Governor. For the answers, the industry is looking primarily to the soon-to-be released New York State Energy Storage Roadmap. In March 2017, the NYS Public Service Commission required the New York State Energy Research and Development Authority (NYSERDA) and the NYS Department of Public Service staff to develop an Energy Storage Roadmap to identify current and anticipated electric system needs that storage is uniquely suited to address and the levels of energy storage that will provide net benefits to ratepayers in New York State. The Roadmap must also include “market-backed” policy and regulatory recommendations, that are consistent with the State’s Reforming the Energy Vision (REV) initiative, to spur energy storage deployment in New York.

The Draft Roadmap is expected to be submitted to the NYS Public Service Commission in the second quarter of 2018 and, at that time, it will become the subject of extensive public review and comment. Final action on the Roadmap by the Public Service Commission is expected in late 2018.

While there undoubtedly will be considerable and justifiable attention given to the levels of storage called for the Roadmap, the policy and regulatory mechanisms proposed to achieve the target levels will also receive a great deal of scrutiny and are essential to the success of the energy storage initiative.

A collective effort is required

NY-BEST and our members have long actively advocated for policy and regulatory changes, as part of New York’s on-going REV process, to monetise the benefits that energy storage provides to the electric grid. From providing flexible resources to enable widespread deployment of renewable energy resources, to improving grid resiliency and efficiency, to shifting peak loads and reducing harmful emissions, storage brings a multitude of benefits to the grid that are not being fully valued in our electric system today. NY-BEST has been coordinating industry input into the Roadmap and a range of policy and regulatory options have been raised by our, including: long term contracting mechanisms, new tariff and rate structures, financial incentives as well as other innovative ideas, such as a clean peak standard.

The Energy Storage Roadmap process being undertaken in New York presents a significant opportunity for the storage industry to help craft and implement new mechanisms that will provide value for the services energy storage provides. As it is often said, “the devil is in the details,” and in the case of New York’s Energy Storage Roadmap, the details of the policy recommendations will be critically important for the energy storage industry.

NY-BEST and our members look forward to continuing to participate in this important process and we invite the energy storage industry to join us. 

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NextEra sues US treasury over ‘missing’ US$135 million in grants

NextEra Energy is suing the US Treasury Department for more than US$135 million claiming that it miscalculated grants owed to it for the Silver State Solar project in Nevada.

Owners of the 250MW plant, completed in mid-2016, applied for grants under the 1603 Treasury Program, introduced as part of a broader 2009 stimulus package. It provides energy infrastructure investors with cash grants in lieu of tax credits. NextEra requested US$289.1 million but received US$152.4 million.

According to the court filing, the Treasury reduced its valuation of the asset but failed to explain how it had arrived at the new figure following its own 15-month review. After an adjustment to US budgets, the award was reduced to US$141.9 million.

“This review process consisted of a series of ad hoc communications, questions, and commentary from Treasury. However, Treasury did not provide any written explanation of its position or how it ultimately determined its award amounts,” the NextEra complaint states.

The Treasury reduced what it considered to be eligible costs of the project from US$963,677,683 to US$508,008,767. The project uses First Solar modules and single-axis trackers. It was built in eight blocks, the first of which was completed in October 2015.

Separately, the accounting of a US$32 million EPC deal is in dispute, with NextEra seeking a further US$9 million in grants related to the costs embedded in that contract.

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AES and KIUC break ground on Hawaii’s largest solar-plus-storage system

AES Distributed Energy (AES DE), a subsidiary of AES Corporation, and nonprofit transmission firm Kauai Island Utility Cooperative (KIUC) have broken ground on a 28MW solar and 100MWh five-hour duration battery energy storage system in Kauai, Hawaii.

The Lāwa’i Solar and Energy Storage Project, the largest hybrid solar and storage project in Hawaii, will be located on former sugar land between Lāwaʻi and Kōloa, on Kauai’s south shore. It will provide 11% of KIUC’s generation capacity and increase the portion of renewables in its mix to 60%.

The price will be US$0.11/kWh, which is significantly below the cost of diesel generation, said KIUC’s president and chief executive, David Bissell.

“This will not only provide downward pressure on rates, but also helps us avoid the use of 3.7 million gallons of diesel each year,” he added.

Last October, AES announced it would be using SunPower’s scalable Oasis Power Plant platform for the solar plant.

The battery system will also improve the island’s grid resiliency, providing dispatchable energy from the solar system, with the ability to deliver consistent peak power output for up to five hours outside of daytime hours, alongside power production going straight to the grid during daytime hours.

Woody Rubin, president of AES DE, said: “AES has had a presence in Hawaii for more than 25 years, and this first-of-its-kind project demonstrates our continued commitment to the state’s vision of a cleaner energy future. This innovative project will help reduce Kauai’s reliance on fossil fuels while generating clean, reliable and affordable energy.”

Hawaii has a goal of reaching 100% renewable energy by 2045 and solar and storage combinations have been a major focus already. The Hawai‘i Public Utilities Commission last year approved two new programmes expanding its customers’ abilities to install rooftop PV and energy storage systems. Similarly, in 2016, SolarCity chose Tesla, which later acquired SolarCity, to supply a 52MWh utility-scale energy storage system, which will make the output of a solar farm in Hawaii dispatchable.

Meanwhile, the US Navy is building a 44MW solar power plant with energy storage, also on Kaua’i, while ‘intelligent’ commercial storage provider Stem is aggregating customer systems into a 1MW ‘virtual power plant’ on another island, O’ahu.

Scale of such projects is consistently growing. For example, this week Australia also saw its first large-scale, grid-connected solar-plus-storage system come online, having been built by Conergy.

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ROUNDUP: Redflow ‘large scale battery’, KACO new inverter, PetersenDean picks SolarEdge/LG Chem

Redflow creates 450kWh systems from smaller units

21 February 2018: Australian flow battery manufacturer Redflow, which has just begun implementing mass production techniques at its factory in Thailand, has now created a ‘large-scale battery’ (LSB) with a capacity of 450kWh.

The company is known for its 10kWh ZBM2 zinc bromide flow batteries, which it mostly sells to commercial and industrial (C&I) customers, touting advantages including cheap and recyclable plastic parts which it claims will lower the cost of both production and purchase.

Redflow said that company founder and former CEO Simon Hackett has installed a Redflow LSB at property he owns in Adelaide, underneath a 50kW solar array, linked to another 20kW solar installation.

The LSB uses 45 separate ZBM2 batteries, along with six 12kW Victron Quattro 48/15000 battery inverter/chargers in what Redflow described as both a “simplification” and the addition of ‘plug and play’ capabilities to the product’s installation process.

“Although we initially purchased a large industrial AC inverter with the LSB, it lacked the monitoring, logging or control systems to let it interact with our on-site solar. While we could charge and discharge our large battery ‘manually’, we couldn’t integrate it with the building, without an expensive consulting project to develop a bespoke third-party control system,” Hackett said, before Redflow settled on combining the system with a Victron Energy CCGX controller unit.  

KACO introduces new battery inverter

21 February 2018: Germany-headquartered solar inverter manufacturer KACO has unveiled a new 50kW device that the company claims is designed with versatility in mind, including compatibility with batteries from a range of providers.

The blueplanet gridsave 50.0 TL3-S is a bi-directional inverter with a claimed efficiency of 98.5%. Aimed at the commercial and industrial (C&I) and utility-scale markets, KACO said it is compatible not only with lithium-ion batteries, but potentially other types as well.

The device can be operated in parallel on the DC side, connecting a high-capacity battery to several inverters. This allows for high system availability – different batteries could perform different tasks, or be scheduled to do so at different times – and high efficiency, the company claimed.

The system can also be installed in parallel on the AC side and safely installed outdoors. It will be officially launched at Energy Storage Europe next month in Germany.

US contractor PetersenDean selects SolarEdge, LG Chem for home energy push

21 February 2018: PetersenDean, a major home improvement contracting company in the US, has selected SolarEdge inverters and LG Chem batteries to create what the company calls “an affordable path to solar ownership and energy storage”.

PetersenDean Roofing & Solar apparently installs approximately 2,000 solar PV systems and roofing solutions each month. The installation subsidiary will offer customers LG Chem’s 9.8kWh Residential Energy Storage Unit (RESU) 10H battery systems, along with a complete inverter solution from Israel-headquartered SolarEdge which includes module-level power electronics, integrated into the company’s StorEdge energy management platform.

LG Chem batteries were among the first to be announced as compatible with SolarEdge technology, along with Tesla’s Powerwall.

“Both of these companies’ commitment to technology, coupled with efficient and high-quality manufacturing processes produces solutions that exhibit the highest levels of safety, performance, and reliability,” PetersenDean Roofing & Solar CEO Jim Petersen said.

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FERC ruling a ‘significant step’ towards wholesale market participation for energy storage

A unanimous vote taken by the US regulator FERC (Federal Energy Regulatory Commission) which would allow energy storage and other distributed energy resources to play into wholesale markets has been hailed as a “significant step” forward.

FERC voted 5-0 in Item E-1, a draft ‘Final Rule on Electric Storage Resource Participation in Markets Operated by Regional Transmission Organisations, or RTOs, and Independent System Operators, or ISOs’. The rule sets out frameworks through which electricity storage can participate in various capacity, energy and ancillary services markets operated by RTOs and ISOs – the operators of the US’ transmission and distribution (T&D) networks.

While the commissioners accepted this entrance of energy storage to be a desirable and perhaps inevitable outcome, there is still one further hoop for the rule making to pass through – a technical conference will be convened in April by FERC to gather information on all of the proposed and potential reforms to the way distributed energy resources can be aggregated on electricity networks.

RTOs and ISOs are asked to establish participation models for storage in the wholesale markets of  their service areas, including technical parameters, minimum resource size requirements and eligibility. The drafted Final Rule also “requires that the sale of electric energy from the RTO or ISO market to an electric storage resource that the resource then resells back to those markets must be at the wholesale locational marginal price”.

Trade groups Advanced Energy Economy, Energy Storage Association quick to applaud FERC

Advanced Energy Economy, a trade group formed by private companies looking to modernise and decarbonise their energy supply and generation, and counting the likes of Apple, AES, Microsoft, Schneider Electric, Siemens, Sunpower, NEXTracker, Facebook, E.On and many others among its members, had already applauded the initiative when first put forward in late 2016 and early 2017.

The group once again stepped forward to commend the FERC rulemaking.

“Through today’s order, FERC has taken a significant step toward removing barriers that keep advanced energy technologies from competing in wholesale electricity markets on the basis of their ability to improve the reliability, resilience, and affordability of our energy system. Energy storage can help reduce costs to consumers and ensure that the lights stay on,” Malcom Woolf, AEE senior vice president for policy, said.

“We firmly believe that aggregated DERs deserve the same opportunity to compete on the basis of price and performance, and   look forward to engaging in a formal process to ensure barriers are removed for these critical energy resources as well.”

Meanwhile, the US Energy Storage Association’s CEO, Kelly Speakes-Backman, called FERC’s latest action, “the culmination of a concentrated and holistic review of the framework needed to support participation of vital electric storage technologies in the wholesale markets”.

“Since the rulemaking was initiated in November 2016, the Energy Storage Association – driven by the tireless efforts of its Vice President of Policy, Jason Burwen – has advocated for establishing transparent, standardised RTO and ISO policies regarding the participation and integration of electric storage,” Speakes-Backman said.

“Electric storage technologies already fulfill crucial functions in the bulk power system to provide reliable power and a more resilient grid.  With this morning’s unequivocal action, the FERC signaled both a recognition of the value provided by storage today, and more importantly, a clear vision of the role electric storage can play, given a clear pathway to wholesale market participation.”  

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FPL deploys the US’ first DC-coupled grid-scale battery at Florida solar farm

Utility Florida Power & Light claims that a just-completed battery addition will increase output from a large-scale solar farm in its home state, thought to be the first time a DC-coupled solution has been used at this scale in the US.

Some residential energy storage battery systems available in the States and elsewhere already utilise DC-coupling, but the configuration is new for utility-scale plants. FPL’s newly unveiled solar-plus-storage system will be able to integrate into the network surplus energy that would otherwise be ‘clipped’ from an AC-coupled solution during peak generation periods when the sun beats down the hardest.

As with a few other recent projects co-locating batteries with wind or solar, the overall idea behind the project is to create a clean dispatchable energy resource. Using batteries to increase generation yield and to add predictability to the power plant’s output means it will be easier to co-ordinate with the balancing of other assets on the grid network, FPL said.

FPL, part of the NextEra group of companies, will deploy a 4,000kW / 16,000kWh (4MW / 16MWh) battery storage system at FPL Citrus Solar, a 74.5MW PV plant completed in 2016 and one of three of the same capacity developed in Florida’s DeSoto County by the utility.

FPL said NextEra Energy companies have been researching and testing battery storage tech to assess the potential benefits for “several years”, with around 130MW / 100MWh of battery storage systems under their operation. This included a few pilot projects. Following a rate agreement ruling with the regulator, Florida Public Service Commission, FPL plans to develop 50MW of battery storage in an undetermined timeframe – the utility said in the “next few years” in a release. Parent company NextEra has recently unveiled plans for battery projects in Arizona.

FPL president and CEO Eric Silagy said the firm had “set a standard” for low-cost solar development and was now “looking at the next level” – adding batteries.

“By harnessing more solar energy from the same power plant, this has the potential to further reduce our fossil fuel consumption and save our customers even more money on their electric bills,” Silagy said.

FPL has added 520MW of PV capacity in the past two years and will have completed a further 300MW by the end of February. The utility touted the ability of solar to improve FPL’s carbon emissions profile and keep customer rates low for the long term.

Meanwhile, development of an energy storage market for Florida has lagged behind other leading states in the US, with few project announcements emerging. However, a recently proposed piece of legislation called for the establishment of a pilot programme within Florida’s Department of Agriculture and Consumer Services to investigate and correctly value the use of solar-plus-storage systems in preventing or coming back from energy supply and delivery problems stemming from natural disasters and other causes.

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First Solar partners with Arizona utility for peak dispatch solar-plus-storage project

Vertically-integrated solar energy company First Solar will be involved in the first megawatt-scale battery system announced in Arizona since it was revealed the state could put a 3,000MW energy storage deployment target in place.

US-headquartered First Solar, which makes and deploys thin-film solar PV panels at utility-scale projects, made an investment a while back into grid-scale and commercial system integrator and provider Younicos but had yet to make a move into a project.

A 50MW battery – MWh rating was not revealed – will be charged with the output from a 65MW solar field to deliver energy to customers during peak demand periods in a project being undertaken by First Solar and utility Arizona Public Service (APS).

In other words, the solar-plus-storage system will be configured to dispatch large amounts of energy between 3pm and 8pm each day, delivering “clean power to Arizonans on hot summer days”, First Solar said. During those time periods, solar PV generation is starting to ramp down as energy use rises, for example as domestic customers arrive home from work and start up their household appliances in the early evening.

APS had issued a request for peaking capacity resources, to which First Solar responded and was awarded the contract to build and operate the facility. Going forward, APS has a plan in place to deploy 500MW of energy storage over the coming 15 years.

The project follows closely on the heels of Andy Tobin, a director at Arizona’s regulator, the Corporation Commission, presenting a plan at the end of January to generate 80% of Arizona’s power from renewable sources by 2050, establish a so-called ‘Clean Peak’ standard and instruct utilities to install 3,000MW of energy storage by 2030.

Energy storage deployments are already under way in the state. Another of the main utilities, Tucson Electric Power (TEP), announced a 100MW solar PV array coupled with a 30MW/120MWh energy storage system, which would sell its output to TEP at less than three cents per kilowatt-hour from the combined installation for a 20-year period – a “historically low price”.

Other developments include the announcement that APS will save itself from building miles of expensive transmission and distribution (T&D) infrastructure with the strategic deployment of two 8MWh energy storage systems, which Energy-Storage.News reported in August last year. In a recent technical paper, Alex Eller of Navigant Research discussed the topic of energy storage as an alternative to T&D spending.

Dynamics of rooftop PV versus utility-scale add nuance to discussion

The spread of solar has been a contentious issue in Arizona, with controversies over rooftop solar in particular and accusations that utilities are less than keen to accommodate the technology. However utility solar has not suffered similar difficulties and continues to grow apace.

Lon Huber, vice president and head of consulting at Stratagen Consulting told Energy-Storage.News that: “There have been some issues with rooftop solar and the utilities in the past”.

“APS came to a settlement, TEP’s case is still ongoing, it hasn’t been a smooth relationship necessarily but this plan is pretty co-ordinated and it’s pretty comprehensive so every resource will have its role to play,” Huber said of the 3,000MW target and overall plan put forward by the Corporation Commission.

“The price of [utility-scale] solar in Arizona is at or below wholesale prices. Just think about that – it’s not in 20 years, it’s today, at or below wholesale. When you can get a PPA for 2.5-3 cents per kWh, fixed for more than 20 years, that’s really hard to beat!

“Utility solar has a higher capacity value. And so if somebody says to you, just from a cost-efficiency standpoint, would you like to do 2.5 cents solar with a high capacity value or 10 cent rooftop solar with a lower capacity value, which would you pick?

“The distribution system in Arizona is not like in New York or California, there’s not huge constrained load pockets that you can’t get wires into and so there’s no way a distribution system can make up for a seven cent gap or whatever it is. So I think it’s important to note that Arizona is a different animal in terms of distributed versus utility-scale. We have huge amounts of cheap land and great sun which makes utility-scale prices just unbelievably affordable.

“That’s at the heart of this policy, it recognises that and says, great, now that we have this super-cheap fuel, let’s use it to meet our peak demand, instead of just taking it whenever it produces.”

First Solar CEO Mark Widmar said the company was “excited to partner with APS to demonstrate the capabilities of solar coupled with large-scale battery storage”.

“Together, these technologies highlight the significant role for solar in providing reliable, cost-effective energy.”

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Distributed energy technologies challenge conventional thinking around grid planning, Part 2.

In part 2 of a technical paper first published in PV Tech Power Vol.13, Alex Eller of Navigant Research continues his look at how one of the most significant expenses for electric utilities, maintaining and upgrading transmission and distribution (T&D) networks, could be undercut using non-wires alternatives – including energy storage.

Risk aversion hinders widespread adoption

Despite the advantages and growing popularity of NWA (non-wires alternatives) programmes, significant barriers remain to more widespread adoption. As with many new electrical grid technologies, the level of confidence utilities have in the new programmes is crucial. Although early results have been promising, many utilities do not yet have enough faith in NWA programmes to overcome the traditional preference and expertise with T&D investments. This lack of faith is the result of both an institutional resistance to change within many organisations and the fact that prevailing rate recovery mechanisms for utilities typically do not encourage alternatives and innovation. If there is no regulatory pressure in place, there are few reasons why a utility would pursue an NWA. There is a higher perceived risk associated with these types of short measure life projects compared to a traditional equipment upgrade that is built to last 20 years or more. In addition, a T&D upgrade aligns with the historical experience of a utility. Thus, they may be more comfortable implementing a poles and wires upgrade.

Much of the hesitation to embrace NWAs stems from the challenges with engaging customers and being able to effectively guarantee a necessary amount of load reduction. Investments in energy efficiency, DR and solar PV have proven effective at reducing load in select areas; however, they do not guarantee the level of reliability and control that utilities demand. Although customers may typically respond to a DR signal to reduce demand, they often can override that signal and continue their normal operations. Due to this inherent unreliability, new technologies such as distributed generation and energy storage have emerged as more expensive but advantageous components of an NWA portfolio.

The increasing popularity of energy storage in NWA programmes and as a single-technology alternative to conventional T&D investments stems from the reliability and flexibility of storage systems on the grid. Utilities prefer direct control over critical assets that are used to serve peak demand and ensure the capacity of grid infrastructure is not exceeded. As a result, energy storage is typically seen as a more reliable form of load reduction compared to NWAs composed of customer-side DER. Centralised, utility-scale energy storage systems (ESSs) in particular fit more with traditional utility investment models and technical expertise. ESSs provide added flexibility with the variety of services they can provide when not needed to support T&D infrastructure, including frequency regulation, voltage support, spinning reserves, outage mitigation and effectively integrating renewable generation.

Another advantage of energy storage is that the technology can be sized appropriately to meet grid needs and can be sited in numerous locations to deliver maximum benefits—either in front of customers’ meters on the T&D grid or behind-the-meter (BTM).

Transmission-level ESSs designed to relieve congestion have been relatively rare to date due to the large storage capacity required to alleviate these issues. Distribution-level ESSs have been the most common type of T&D deferral projects to date. These systems are frequently built at substations or specific points of congestion on the distribution grid to defer investments and improve reliability by isolating outages. Many distribution-level systems have been relatively small pilot projects initially, but utilise modular designs allowing for storage capacity to be expanded over time.

BTM energy storage to defer T&D investments is more complex and dynamic than transmission or distribution-level systems, although it has the potential to be far more disruptive to the industry. BTM energy storage for T&D deferral includes systems located in both C&I and residential buildings that utilise advanced software and virtual aggregation to provide targeted congestion relief for grid operators. The primary advantages of BTM storage providing T&D deferral are potentially lower costs to utilities and the ability to offer more visibility and control at the edges of the grid.

BTM storage for these applications is currently a nascent market, with several key challenges including:

•           Relatively high upfront costs for customer acquisition in some situations

•           Small amount of storage capacity per system

•           Concerns regarding the reliability of load reduction with customer or third-party owned systems.

Momentum evident, despite barriers

As with NWA programmes in general, there are several barriers standing in the way of energy storage being widely used to defer T&D investments. Despite recent advances, the technology and market remain quite new and immature, resulting in a conservative approach from often risk-averse utilities. Fully understanding and analysing the value of these energy storage projects is also challenging as the complex nature of the technology –including its ability to provide multiple services at different times – is not captured in many grid modelling and simulation systems. Furthermore, there is a major variation in the costs to upgrade T&D infrastructure. Energy storage and NWAs are typically only a cost-effective alternative when T&D projects face high costs due to challenging terrain, population density, real estate costs, weather constraints and other issues.

While barriers to widespread growth remain, both NWAs and storage-specific projects to defer T&D investments are gaining significant momentum with a variety of new projects being developed around the world. In addition to the NWA projects already discussed, energy storage projects for T&D deferral are growing in popularity and have recently been announced in Arizona, California, Massachusetts and Australia. These new projects are utilising several different business models to match the necessary technical and financial solutions with a customer’s needs and available resources. The innovations happening in this market are helping drive the overall transition to a more intelligent, dynamic and distributed energy system the promises to improve efficiency, empower customers, and reduce environmental impact.

Read Part 1. of this technical paper on the site here.

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Tesla’s PV installs continue rapid decline to 87MW in Q4 2017

Tesla reported another major decline in its residential solar installations for the fourth quarter of 2017, while a supply shortage for its residential energy storage system ‘Powerwall 2’ has created a customer backlog of solar and storage installs of more than one year. 

Tesla reported fourth quarter 2017 financial results that highlighted the rapid decline in solar installations. The company reported solar system installations totalling 87MW, a 20% decline from the previous quarter, which had seen a decline of 38% from the second quarter of 2017. The overall decline in installations through 2017 was 42%.

Tesla is unlikely to retain its leadership in the US residential market when rivals such as Sunrun report fourth quarter installations. However, major rivals to Tesla have seen installations flat line in 2017. Tesla will remain the leading residential installer for 2017 as installs remained until the fourth quarter much higher than the others (Sunrun, Vivint Solar, SunPower). 

The declines have been self inflicted as the company moved away from commercial and industrial rooftop installations as these were said to have generated the lowest profit margins, while shifting residential rooftop sales to internal car sales showrooms in the US, compared to direct sales when the company was SolarCity. 

The company has recently changed direction and increased direct sales through plans to establish 800 retail locations within Home Depot stores across the US. 

To read the full version of this story, visit PV Tech.

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As hardware production ceases, S&C Electric’s focus is on system integration

A spokesman for S&C Electric has confirmed the company will no longer be producing its power conversion system (PCS) for energy storage systems but will remain in the market as a system integrator.

Following reports at the end of January that the company, founded in Chicago just over 100 years ago, is exiting the manufacturing side of its energy storage business, Energy-Storage.News asked a company spokesman, Spencer Zirkelbach, for clarification.

“Simply put, S&C is still very much involved with the system-level integration of energy storage for microgrids and grid-reliability systems, but S&C will now source the energy storage hardware for those systems rather than manufacture portions of them,” Zirkelbach said.

According to Zirkelbach and the company, the “primary value” for S&C’s energy storage customers has always been in its “integration expertise”, citing the successful deployment of 189MWh of energy storage by the company over the past 10 years in various different markets as proof.

Perhaps more than other players that have spread themselves across several different market segmentations, S&C Electric has focused more on two core opportunities: microgrids, which are its main area of interest; and utility-scale battery solutions used to balance grids in advanced commercial markets such as PJM Interconnection, one of the US’ earliest and most lucrative markets for frequency regulation.

“S&C is continuing to apply our integration expertise to energy storage projects within microgrids for our customers. However, we have chosen to no longer manufacturer our PureWave line of products, which have been used as the power conversion system (PCS) component in energy storage systems.”

The line includes:

  • S&C’s PureWave SMS Storage Management System
  • PureWave SMS-250 Storage Management System
  • PureWave CES Community Energy Storage System
  • PureWave DSTATCOM Distributed Static Compensator
  • PureWave UPS System
  • PureWave UPS XT Systems

In previous projects the PureWave system had been configured to work with different batteries including lithium-ion and NGK’s sodium sulfur grid devices.

The move follows a recent decision by rival system integrator NEC Energy Solutions to sell off its interest in lithium battery cell and electrode manufacturing to focus more on its system integration role. Energy-Storage.News pinpointed S&C Electric, along with NEC ES, as one of 10 standout system integrators in the global energy storage market in a feature article last year, while recent projects the company has executed include New Zealand’s first grid-scale battery system and a successful ‘islanding test’ on a microgrid in Illinois.  

Spencer Zirkelbach of S&C Electric confirmed these areas would remain of primary strategic interest to the company.

“In the energy storage market, S&C will continue to pursue projects that deploy energy storage in support of microgrids and grid-reliability projects,” Zirklebach said.

Read ‘The big future for microgrids’, an in-depth study of S&C Electric’s ‘showcase’ microgrid for Texas utility Oncor, here.

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