Minister of Finance Nirmala Sitharaman holds the budget’s iconic red cloth folder in 2021. Image: Gov’t of India Press Bureau.

The Indian government’s decision to classify grid-scale energy storage as infrastructure addresses the industry’s “biggest concerns” by making investments easier to facilitate, Energy-Storage.news has heard. 

As part of the Union Budget 2022-2023 speech and announcements yesterday by Minister of Finance Nirmala Sitharaman, energy storage and data centres were awarded the status. Minister Sitharaman said that this will “facilitate credit availability for digital infrastructure and clean energy storage”.

India’s banks and financial institutions have a standard, government-identified list to follow when it comes to choosing what qualifies for infrastructure loans, Ulka Kelkar, director of the climate programme at non-profit research group WRI India, told Energy-Storage.news. 

“This list includes five types of infrastructure, which are more in the nature of public goods than private goods,” Kelkar said, from energy, transport, communications, water & sanitation to social and commercial infrastructure. 

“Specifically adding grid-scale energy storage to this list should make it easier to access infrastructure credit.”

Kelkar explained that this showed the range of policy instruments a government can deploy is much wider than budgetary allocations and fiscal incentives like taxes or subsidies, but includes other forms of de-risking, from mandates and standards to procurement, aggregation, credit aggregations and more. 

The budget also included direct support for the upstream end of the clean energy value chain. As reported yesterday by our sister site PV Tech, an allocation of funding for solar PV manufacturing within the country through a scheme called the Production Linked Incentive (PLI) was quadrupled with an addition of Rs19,500 crore (US$2.6 billion).

There was also a commitment to establishing battery recycling and battery swap programmes for electric vehicles (EVs), while a separate Production Linked Incentive programme already in place for advanced chemistry battery cell manufacturing is ongoing, aimed at supporting 50GWh of domestic production capacity. 

India Energy Storage Alliance welcomes ‘progressive budget’

The India Energy Storage Alliance (IESA) told Energy-Storage.news it welcomed the “progressive budget,” which it said addressed many key requests from the industry and would make faster adoption of energy storage and e-mobility in India possible. 

“Infrastructure status for energy storage sector will address the biggest concerns of industry related to ease of financing,” IEAS president Dr Rahul Walawalkar said. 

“IESA believes that over the past decade energy storage technologies have made tremendous advancements in improving performance and reducing capital cost, so availability of financing was identified as the key hurdle for rapid adoption.”

Infrastructure status for energy storage had been among requests IESA had made to the Ministry of Finance, covering both manufacturing and deployment and Dr Walawalkar said.

“We are glad our submission was considered positively,” he said.

“As the Harmonised Master List of Infrastructure sub-sectors already includes Electricity Generation and Electricity Transmission, the inclusion of Energy Storage will help cover all the important segments of energy under the Infrastructure Status.” 

IESA also welcomed that increase in funding for solar PV manufacturing as a close ally sector of energy storage. According to Walawalkar, the Ministry of Finance can be expected to also consider increasing the 50GWh allocation for advanced chemistry cell (ACC) manufacturing support in the coming months. 

Applications for the ACC incentive had been oversubscribed, with a total of 130GWh of competing bids received and the Ministry may increase the targeted capacity “to ensure India can keep up with the global increase in advanced cell manufacturing,” the IESA president said. 

WRI India’s Kelkar said the PLI funding increase for solar could have a positive impact on energy storage adoption.  

The allocation specifically related to “manufacture of high efficiency modules, with priority to fully integrated manufacturing units from polysilicon to solar PV modules”.

However, Kelkar said, it might help reduce the combined cost of solar and storage for each unit of electricity generated, even though the scheme itself may not directly affect storage.

“With such schemes, the focus seems to be on nurturing the indigenous manufacturing industry, creating jobs, and driving down costs,” Kelkar told Energy-Storage.news. 

IESA also welcomed other measures announced, or referred to as under consideration by the government, that could have a positive impact on India’s energy storage manufacturing and supply chain.

For example, while the budget broadly emphasised support for domestically-made goods and included duties on imported products, reforms on customs and duties rates for raw materials that are being discussed could ease supply chain constraints and support domestic makers, Dr Walawalkar said. 

A concessional 15% tax rate for newly incorporated domestic manufacturers has been extended by a year from 31 March 2023 to 31 March 2024, which will help facilitate investments required in the next two years to get PLI-backed companies —as well as potential component suppliers — up and running. 

IESA also warmly welcomed measures to support start-ups, green energy sector job opportunities for young people and skills training in digital and other industry sectors and e-mobility. The group also said support for grid-connected microgrids was a positive step, helping boost agribusiness in remote areas.

The group did say, however, that a reduction in the General Sales Tax for EV batteries to 5% that is suggested had not been included in the budget, which IESA asked the Ministry of Finance to reconsider. 

The green hydrogen sector is also “missing in the budget,” Dr Walawalkar said. IESA has suggested the creation of a special fund for green hydrogen and PLI support for green hydrogen electrolyser manufacturing.

Nonetheless, the budget appears to have been well received. It follows the announcement a few days ago that India’s Ministry of Power has clarified the role and status of energy storage within the power sector, which again could accelerate adoption. 

The country already has over 150GW of renewable energy capacity installed and to reach its 2030 target of 500GW, will need about 28GW/108GWh of energy storage, the Central Electricity Authority has forecasted. 

Previous budget announcements covered by Energy-Storage.news in 2020 and 2021 were welcomed by IESA for their broad support of renewable energy and the green economy, but yesterday’s announcement appears to be the first instance of specific, directly supportive policy announcements pertaining to energy storage by Minister Sitharam. 

Additional reporting by Sean Rai-Roche.

Continue reading

Hyperion will invest more than $297 million in the new facility in Columbus, Ohio, where it will manufacture its next-generation hydrogen fuel cell, which will power its new line of stationary and mobile energy storage products, including its XP-1 hypercar. February 1, 2022 Anne Fischer

Continue reading

Altus Power committed to a multi-year supply agreement with tier 1 North American PV module manufacturer Heliene, and invested $5 million in the company’s growth. February 1, 2022 Ryan KennedyAltus Power announced it signed an agreement with Heliene to purchase up to 250MW of solar modules for use in construction projects across the US. The deal includes a commitment by Altus Power to invest up to $5 million in Heliene in anticipation of the company’s initial public capital raise. Heliene is set to perform a reverse take-over transaction with Buzz Capital 2 Ltd. and join the TSX Venture Exchange.The Heliene 36 Cell Monocrystalline half-cut cell module. Image: Heliene Heliene manufactures its modules with monocrystalline PERC cells, which it said have a half-cut design to reduce cell-to-module losses. The panels have use cases in utility-scale, commercial & industrial, and residential markets.“Many U.S. solar developers are currently facing supply and trade volatility risks, causing potential project delays. We are pleased to partner with our customer Altus Power to help them develop the projects in their pipeline with confidence,” said Martin Pochtaruk, Heliene CEO.The modules are planned to be produced in Mountain Iron, Minnesota, where Heliene recently expanded its operations. Three production facility locations in the US and Canada are expected to achieve a total manufacturing capacity of 900MW in operations by Q3 2022. Heliene, founded in 2010, has facilities in Minnesota, Ontario, and Florida.“Domestic made equipment and materials are becoming an increasingly important component of our procurement efforts and this supply certainty will be significant to our total module requirements,” said Tony Savino, Co-Founder and Chief Construction Officer of Altus Power. Savino said Altus Power is the only public, vertically integrated commercial and industrial focused clean electrification company in the US. He said that having a reliable, steady supply of solar modules is critical to the company’s growth strategy. Based in Stamford, Connecticut, Altus Power owns and operates locally sited solar PV, energy storage, and EV charging infrastructure across 18 states.ManufacturingUS and North American solar manufacturing have potential to rise significantly as both Sen. Jon Ossoff’s Solar Energy Manufacturing for America Act and the Biden Administration’s Build Back Better (BBB) Act, which has $550 billion in climate provisions, work their way through the legislature. An earlier proposal of BBB had significant provisions for US manufacturing. Included in the bill were incentives for the manufacture of thin film PV or crystalline PV cells. The incentive would pay $0.04 per watt DC capacity of the cell. PV wafers would be offered $12 per square meter, and solar-grade polysilicon is offered $3 per kilogram US-made solar modules are offered an incentive of $0.07 per watt. Senator Joe Manchin (D-VA) shut down the earlier proposal of BBB, and said he intends to start “from scratch,” but it is likely that US manufacturing would continue to receive focus in the Act.This content is protected by copyright and may not be reused. If you want to cooperate with us and would like to reuse some of our content, please contact: editors@pv-magazine.com.

Continue reading

Addressing the threat posed by climate change will mean using massive amounts of clean energy resources like solar to both decarbonize and electrify the economy. While projects hundreds of megawatts in capacity and breakthrough battery tech steal a lot of the headlines, small-scale, distributed energy resources (DER) will be one of the pillars holding up the energy transition.Distributed generation and storage can help to keep communities powered during storms and outages, keep electricity costs low, and ensure the benefits of renewables reach all the members of a community. Community microgrids are increasingly being viewed as a necessity for future energy resiliency.Founded in 2019, Franklin Whole Home (FranklinWH) has been making waves to start 2022, with the company announcing the launch of its first residential storage system. The FranklinWH system integrates its lithium iron phosphate “aPower” battery with adaptive learning, which is part of the included aGate smart control system. Image: FranklinWH The 13.6KWh battery is compatible with any PV inverter technology, the company reports, and it can connect with existing solar systems while scaling up to 15 units for a total of 204KWh of capacity. In the event of a power failure, its black start feature creates a micro-grid for the home.One of the main points the company focused on in development of the system was ensuring ease of operating for the customer; breaking down the barrier many customers perceive to exist between them, and understanding and getting the most out of their home storage system.At Intersolar North America 2022, pv magazine was able to sit down with FranklinWH Chief Sales Officer Cheung “Gary” Lam to discuss the development process for his company’s first commercialized product, and FranklinWH’s vision for the future of distributed storage in the US.As Lam sees it, utilities currently value distributed storage only in aggregate use cases, like for demand response or peak demand shaving programs. He sees opportunity to shift this perspective, presenting the individual value of storage assets to both the consumer and the utilities at large.“What we are trying to do is make decentralized storage capable of working in a truly decentralized way, like in its own way.” Lam told pv magazine. “If [the system] is disconnected from the grid, we still have the safety and functionality to guarantee that someone’s home is  delivering power not only safely, but in a way that still allows them to live comfortably.”Value for the customerOn the customer side, the FranklinWH pitch, at first, is similar to many other residential storage solutions: the system provides backup power in the case of grid failure or weather-related outages, while also providing significant bill savings in typical, day-to-day operations. Where FranklinWH has developed the system to excel is in its ease of use and management.Within the system’s dedicated aGate smart control system, customers can configure their battery to automatically maximize their bill savings, by using electricity from the grid when it is cheapest and using stored or self-generated electricity when prices are higher. The system also includes weather forecasting, and can focus on charging the battery from a PV system before a storm rolls in.In outages, aGate’s adaptive-learning technology allows it to manage complex load scenarios, and the user can integrate three additional large loads such as HVAC, pool heating, or electric vehicle charging.According to Lam, the biggest impediment holding back the vast potential of distributed storage, is how difficult it can be to retrofit storage onto an existing PV system, a process made harder the older that the system in question is.This impediment was the second major focus when developing FranklinWH’s storage system.“Currently, it’s very complicated, most of the solutions out there are for DC coupling, and they have to tie [the battery] into your solar system.” Lam explained. “Compatibility then becomes a big issue. If you installed a system five years ago, you might have to rip up your entire system and re-install a new solar system just to be compatible with the battery you chose.”By using an AC architecture, FranklinWH was able to develop a standard 240 volt split-phase system that he attests any electrician could add to a home energy supply with no previous solar or storage installation experience.Getting utilities on boardTo anyone familiar with DERs the issue Lam sees as the biggest impediment to widespread DER adoption from a utility perspective is a tale as old as time: our grids aren’t capable of handling high-density DER penetration.Lam shares that, as well all know, the grids we still rely on, especially on the coasts, were developed over 100 years ago, designed with much lower power demands in mind. With the advent of HVAC systems and air conditioning becoming standard in almost every home, and the increasing proliferation of electric vehicles and their charging hardware, the grid is being stressed to the point of fault across the country.As would be expected of anybody in the DER space, Lam sees self-generation and self-consumption as the solution. If you take assets off the grid, or have them interact with each other independent of the grid, you relieve significant stress.And while utilities have, in general, been opposed to the widespread proliferation of DERs, due to the adverse effect those systems have on the utility’s traditional business model, widespread transmission and distribution grid upgrades are far more costly than the revenue lost by self-generation. Moreover, self-supply and stress reduction are not the only features of DER, and the full suite of grid-strengthening attributes the resources present has never been given a hard value.“Self-consumption will be the most effective way to go against this kind of challenge,” said Lam. Any energy you store is generated, stored, and consumed locally. You don’t occupy any transmission capacity, and the transmission utility is more like an ultimate backup for you. If anything fails, you still have your grid with you. And that’s like the ultimate safety.”This content is protected by copyright and may not be reused. If you want to cooperate with us and would like to reuse some of our content, please contact: editors@pv-magazine.com.

Continue reading

US-based solid-state battery start-up Sparks opened a pilot plant for its patented lithium battery technology based on zero cobalt cathodes. The company wants to challenge China’s dominance in next-gen battery development. February 1, 2022 Marija MaischThe scramble for new battery storage solutions is picking up the pace with news coming from both established players and new entrants. The latest such move has seen US-based start-up Sparkz announce a pilot plant in Livermore, northern California, where it plans to begin construction of a pilot manufacturing facility for its patented solid-state battery technology.The company’s move to establish its first pilot production was spurred by support from the California Energy Commission (CEC). Last year, Sparkz won a $2.6 million grant from the CEC to extend its development into solid-state batteries as the company takes steps to shift its second product line from development to commercialization.“The California Energy Commission’s funding and continued support of Sparkz was an important step towards securing this facility,” said Sparkz CEO Sanjiv Malhotra. “The CEC understands that to challenge China’s domination of next-gen battery production, and reach America’s clean energy potential, we need to build sustainable battery facilities in the US Sparkz is quickly approaching this goal and putting Americans to work.”Founded in late 2019, Sparkz has recently completed the transfer of six patents from the U.S. Department of Energy’s Oak Ridge National Laboratory, which continues to be the company’s R&D partner.Sparks’ lithium-ion batteries are said to offer double the energy density compared to other zero cobalt chemistries, that is lithium iron phosphate (LFP) batteries that are predominantly made in China. Its initial research shows the ability to reduce the cost of cell manufacturing by about 40%, while maintaining energy density and lifecycles comparable to chemistries that utilize cobalt.Sparks’ high-density lithium battery design uses novel cathode and anode compositions, including early transition metal-stabilized high capacity oxidatively stable cathodes. This innovation improves on lithium-ion cathodes by replacing early transition metals, namely cobalt, at relevant sites in cathodes, and by varying the lithium composition.Its other licensed technologies include a nonaqueous electrolyte with lithium bis(fluorosulfonyl)imide salt for fast charging/discharging of lithium-ion batteries, which enables the batteries to perform at a 23% higher capacity during a 12-minute charge than other formulas; as well as a scaling process which enables industrial-scale production of battery materials through a series of chemical processes.Sparkz also operates an R&D and innovation center in Knoxville, Tennessee, and is also exploring new plants in the Appalachia to begin manufacturing its batteries for OEM partners. The company has the exclusive licenses to produce zero cobalt, lithium batteries and is committed to producing them in the U.S.This content is protected by copyright and may not be reused. If you want to cooperate with us and would like to reuse some of our content, please contact: editors@pv-magazine.com.

Continue reading

Interconnection is a crucial, yet often overlooked, issue for enabling timely deployment of solar and other clean energy projects. Literally every grid-connected project must go through the interconnection process and delays can thus impact projects of every size and type. Across the country, outdated and cumbersome interconnection policies put the brakes on clean energy development, hindering market growth and the rapid climate action needed to avoid the worst impacts of climate change.Interconnection policy improvements will be central to enabling the rapid deployment of DERs (such as solar PV, energy storage, electric vehicle chargers, and more). As discussed in prior articles in this series, rethinking interconnection policies to make them more efficient and ensure they recognize the unique characteristics of energy storage on the grid can help remediate the situation.However, there is also a significant need for greater accountability in the interconnection process.Why? Because utilities have no incentive to create efficient interconnection processes on their own. In many places, utilities continue to see DERs as either direct competition to utility-owned resources, or at best, are generally neutral on whether they thrive. Utilities have an absolute monopoly on grid access in their territories. As a result, the utilities hold all the cards in the interconnection process and there is no competitive pressure for utilities to improve the service they provide to interconnection customers.In contrast, customers and DER developers experience very real impacts when utilities fail to meet interconnection process timelines. These include potential loss of financing, loss of opportunity to receive incentives or limited spots in procurement programs, loss of revenue from production, and the risk of failing to meet timelines in customer contracts or power purchase agreements.All of this means that the role of regulators is essential in providing utility accountability to interconnect projects in a timely fashion.Interconnection Delays in the News Highlight the ProblemDelays in the interconnection process are common and translate to higher costs for developers (and thus customers) and can even result in lost projects. In a dramatic example of how severe these delays can be, Xcel Energy in Minnesota this year made headlines for having over 300 projects waiting for interconnection approval.One Xcel customer was told they would have to wait 15 years for interconnection, and an analysis by the Minnesota Solar Energy Industries Association estimated it would take 260 years to clear the backlog at the utility’s current pace of review.Similar issues with interconnection backlogs were reported in Maine early this year (in addition to significant increases in grid upgrade costs for some developers, though these were later rescinded). Interconnection delays in Massachusetts have also received media attention, with a letter from legislators to the Department of Public Utilities describing anticipated waits of over five years for some projects.Unfortunately, while media attention to cases like these helps shed light on the problem, a dearth of public data on the turnaround times for most clean energy interconnection requests makes it more challenging to quantify the situation and pinpoint solutions.The Need for Better Data and Regulatory Follow-ThroughFew regulators require utilities to keep strong records tracking their performance on interconnection timelines. This makes it harder to understand what’s working, what’s not, and what the best solutions are.Commissions who regulate utilities need information to make decisions. Without tracking, it can be both difficult to determine the actual pain points in the process and there can be no accountability for failure to comply with the processes adopted by the regulator.The need for interconnection timeline accountability has two parts: The need for better data on utility interconnection timelines, and follow-through from regulators to require compliance with reasonable turnaround times.Better Data is Essential for AccountabilityIf regulators do want to hold utilities accountable for a fair and efficient interconnection process, then having data on how that process is actually going is essential. Unfortunately, many Commissions do not even have basic requirements for collection and retention of interconnection related data, let alone regular reporting requirements.A recent experience in California illustrates the consequences of failing to adopt clear requirements for the collection and reporting of interconnection data. The California Public Utilities Commission (CPUC) commissioned an outside consultant to conduct an independent evaluation of utility practice in adherence to the state’s interconnection rules, including current performance, successes, and challenges.CPUC BuildingImage: Creative Commons via WikipediaWhat the resulting report found was glaring gaps, disorganization, and inconsistencies in the records of California investor-owned utilities on interconnection. In some cases, records were so bad that it was impossible for the consultant to assess the utility’s compliance. Each of the utilities had different methods for tracking data in place, at times the data that was tracked did not actually comport with the steps required in the interconnection rules, and often certain steps or information were not recorded at all.The California experience illustrates that efforts to understand how the interconnection process is going and whether utilities are in compliance with the processes established in interconnection rules are not always possible if data has not been collected or organized in an accessible fashion. As this case highlights, regulatory commissions need to take seriously the need to clearly define requirements for data collection, organization, and reporting on utility performance in the interconnection process as a first step towards establishing accountability.Multiple Paths to Timeline AccountabilityThe second part of this process is to define the metrics and carrots and/or sticks that can be used to actually hold utilities accountable for a fair and efficient interconnection process. There are multiple different types of metrics that can be used.The most obvious method is to measure compliance with each utility timeline in the interconnection process. This is achievable if high quality reporting requirements are in place, but there are a few aspects of this that regulators will want to consider as they think about timeline tracking.Interconnection procedures are growing in complexity and may have many different timelines that need to be tracked in order to capture the entire process. However, paying attention to only a small segment of the timelines is not likely to reveal whether the process as a whole is working and may even incentivize utilities to use shortcuts in some steps that they then make up for with delays elsewhere.For example, if a Commission applies a metric to “completeness review”, but does not track when a utility puts an application “on hold” while it requests more information from an applicant later in the process, the utility could be incented to expedite the initial completeness review because they know they can just ask for more information later (which essentially slows down the process).Keeping this in mind, for the most part interconnection customers are primarily concerned with how long it takes for the project to be approved to operate and may not care as much about whether Step A goes slowly if Step B makes up the difference. Tracking the total time it takes for a project to go from application to an interconnection agreement or to obtain “Permission to Operate” will provide the greatest insight, but there are also many customer steps in this process that need to be taken into account.In short, regulators will need to be creative in the ways they choose to establish metrics and be aware of the big picture as they do so.Another approach that could be considered for interconnection accountability, either in addition to or instead of timeline tracking, is to think about establishing customer service-based metrics.A recent decision by the Minnesota Public Utilities Commission recently took that approach and in January, the MNPUC fined Xcel Energy $1 million for exceeding a maximum number of customer complaints filed, the majority of which were about interconnection delays.The ruling emphasized that clean energy customers are indeed part of the utility’s customer base and failure to deliver reasonable interconnection times is a failure to deliver satisfactory service.Commissions in other states could take a more expansive view of utility interconnection timelines as a form of customer service and employ similar requirements for satisfactory service as an alternative or additional means of requiring compliance with reasonable interconnection timelines. Such an approach would also give renewable energy customers an avenue of recourse when faced with unacceptable interconnection delays.Ultimately, it is likely that a combination of different metrics may be the most effective way of encouraging utilities to prioritize their role in ensuring DERs are interconnected efficiently.Once the metrics are established, regulators can then decide whether to tie them to financial penalties or other forms of incentives and process changes. The Minnesota Commission’s decision to actually fine the utility for failure to perform certainly had the effect of bringing attention to the issue, but whether it will be enough to really result in a substantial shift in behavior remains to be seen. Regulators may need to consider other methods beyond simple financial carrots and sticks in order to keep the interconnection process flowing smoothly.A Multifaceted IssueData on and enforcement of interconnection timelines is one key element of the interconnection reforms that will be needed to enable efficient deployment of distributed clean energy projects. But there are many others.The first article in this four-part series discussed why a significant rethinking of how interconnection reviews are conducted will be needed to make the process more streamlined and efficient as the number of solar and other distributed energy interconnection requests grows rapidly. The second explored how interconnection policies need to evolve to effectively deal with energy storage interconnection requests and unlock the full potential of storage on the grid.The final article in this series will explore how improved data transparency on grid conditions will also be imperative to improving the interconnection process. Such data can help developers select optimal locations for new clean energy projects and tailor their operation to grid conditions.While there are a number of aspects of meaningful interconnection reform, there are established solutions for each that regulators can draw from. The key will be for regulators to be proactive in tackling these issues so that interconnection does not bottleneck—and can enable—clean energy growth.Gwen Brown is communications director at the Interstate Renewable Energy Council.  Sky Stanfield is an attorney for IREC and partner at Shute, Mihaly & Weinberger. This article is the third in a four-part series on interconnection reform. In the next article, we will explore the need for increased data access and transparency.The views and opinions expressed in this article are the author’s own, and do not necessarily reflect those held by pv magazine.This content is protected by copyright and may not be reused. If you want to cooperate with us and would like to reuse some of our content, please contact: editors@pv-magazine.com.

Continue reading

TransAlta has planned to start construction on the storage facility in March 2023 and to complete it within nine months. The 180MW battery facility is designed to be charged by the existing Ghost Hydroelectric facility when demand is lower. February 1, 2022 Emiliano BelliniCanada-based power provider TransAlta Corporation recently submitted an approval request to the Alberta Utilities Commission (AUC) for its WaterCharger battery storage project, which would connect 180MW of battery storage capacity to its 51MW Ghost Hydroelectric Dam located at the confluence of the Bow and Ghost Rivers, in the Canadian province of Alberta.In December, TransAlta had published an environmental evaluation, an environmental protection plan, and a noise impact assessment on the project, and the three documents were now added to the approval proceedings. The reports are intended to bring clarity to issues such as the risk of battery fires, the risk of leaching or leaking from the batteries, noise concerns, and the environmental impact of the construction of power lines.“Our initial assessment indicates that no additional power lines are needed and the connection for the facility would be limited to modifications within the existing substation,” the company said in a recent statement to its stakeholders. “However, given TransAlta is not a transmission facility owner in this area, we are currently working with the Alberta Electric System Operator (AESO) to identify, study, and verify feasible transmission voltage connection options to connect WaterCharger to the Alberta Interconnected Electric System at, or adjacent to, the Ghost substation.”In the environmental evaluation, the company specified it wants to use lithium-ion batteries and that a battery sub-chemistry of lithium-iron phosphate (LFP) is currently being considered. ” The project will consider various technical factors when selecting the final battery vendor, including safety, life span, performance, and cost,” the document reads. “The size and number of modular battery units is expected to vary by vendor, with the project expecting up to 220 units to be installed. The final layout and number of battery units will be confirmed once the battery manufacturer is selected.”The storage system will include bi-directional inverters, protection equipment, direct current (DC) and alternating current (AC) circuit breakers, waveform filter equipment, equipment terminals, and a connection cabling system. The modular battery units are each expected to measure 7 x 2 x 2 m and to embed a heating, ventilation, and air conditioning (HVAC) system.TransAlta plans to start construction on the storage facility in March 2023 and to complete it within nine months. The batteries will be remotely operated by TransAlta’s Hydro Control Centre located in Calgary, approximately 50 km east of the hydropower dam, over their 25-year lifecycle. This content is protected by copyright and may not be reused. If you want to cooperate with us and would like to reuse some of our content, please contact: editors@pv-magazine.com.

Continue reading

Also on the rise: Nova Scotia utility proposes net-metering fee. Research into how rooftop PV systems may affect air and building temperature in urban environments vice versa. Vanadium redox flow battery in microgrid project. Important step for Indiana solar: Utility’s net metering calculation overturned in court. Maxeon to offer IBC solar panels in the US.

Continue reading

In the first of a three-part whitepaper series, S-5! and the Metal Construction Association take a look at symbiotic nature of solar systems and metal roofs, exploring it from a system lifespan perspective. February 1, 2022 Tim SylviaS-5!, a manufacturer of metal roof attachment solutions with non-penetrative solutions for attaching solar systems to metal roofs, has joined with members of the Metal Construction Association (MCA), an organization of manufacturers and suppliers looking to promote the use of metal in construction, to release a three-part series of white papers examining the relationship between solar and metal roofs.The papers, which feature contributions from MCA members and S-5! staff, are all available through MCA’s Metal University online learning service, and part one focuses on solar and roof service life compatibility, a topic that the authors perceive to be commonly-overlooked.The paper begins by outlining the idea that a rooftop solar system and the roof housing it are inextricably codependent and must be regarded as a single asset. Because of this codependency, the authors lay out that consideration must be given to the durability, longevity and service-life compatibility aspects of the roof to the PV system, as oversight of this relationship can compromise the PV value proposition and grossly diminish the financial return of the system.What makes the relationship particularly interested is that, with the exception of more specialized and expensive alternatives, metal is the only roof material type that will match or outlive the expected 30-year service lifetime of a solar array. Most metal roofs have a 40-year warranty, and a prior MCA study found that metal roofs can achieve a 70-year lifetime in most non-coastal US environments. This helps to mitigate the higher initial cost that metal roofs present over alternatives, since the PV system will have to be removed and reinstalled entirely once, or multiple times over its lifespan, depending on the age of the roof when solar is installed.Solar installation costs on metal roofs are typically lower than other roof types, even though they require the use of specialized mounting and fastening equipment that doesn’t penetrate the roof. The authors also outline that installation times on metal roofs are generally shorter, and the whole process can improve financial returns on a solar system by 10-15%.The authors present metal roofs and PV systems in a similar light, as both assets present a high initial cost, long expected service life, and economically prudent payback. Payback presents itself in the form of net-metering reimbursement and bill savings for solar systems, and as lower lifetime maintenance and replacement costs for metal roofs.The cost of roof replacement includes the labor and materials cost of the new roof, the labor costs of dismantling and reinstalling the solar PV array, the cost of lost electricity production while the system is down, and the replacement of wiring and any damaged components during the process, which is not a guaranteed cost but is a possibility.The authors claim that aggregated sum of those costs can approach the original cost of the solar system, and installing a new roof on roof types other than metal before solar is mounted, even if the existing roof is only at 50% or less of its useful life, is often recommended. Since this same recommendation would only apply to metal roofs already 10-30 years old, depending on if the customer is focused on roof warranty or total expected life, the study presents maintenance and replacements costs as the greatest lifecycle benefit for installing solar on metal roofs.When taking a look at the full financial value, the report states that the solar system and the roof should be considered as a single asset. Typical financial analysis offered at the point of sale for a solar system presumes the roof will last for the entire life expectancy of the solar system, and the commonly-presented assessment that a system will become cash-positive within the first seven years of operation is founded on this presumption. So are the promises that a system will deliver rates of return in the range of 15-40% over a 30-year period.In the next two installments of the comparison series, S-5! and MCA analyze the common types of PV mounting systems for metal roofs, with a look at associated risks and pros/cons of each, and the critical technical factors for mounting solar PV systems specific on metal roofs.This content is protected by copyright and may not be reused. If you want to cooperate with us and would like to reuse some of our content, please contact: editors@pv-magazine.com.

Continue reading

Sierra Club Canada calls on Nova Scotians to demand energy democracy after the utility proposes to charge a premium on net-metered solar installations. January 31, 2022 Anne FischerNova Scotia Power recently announced a proposal to charge fees to customers who sell renewable power back to the grid. According to a report by The Canadian Press, Nova Scotia Power president and CEO Peter Gregg  said that without the fee, homeowners who generate their own electricity using solar panels are currently being subsidized by other customers. Gregg justifies the fee, saying that it will ensure fairness for all customers.Nova Scotia Power, a subsidiary of Emera Inc., applied to the provincial regulator last week to charge solar customers about $8 per kilowatt of electricity. For a typical 10kW net-metered installation, the fee would amount to $960 per year, essentially doubling the payback period for solar customers who currently take in about $1,800 in annual savings.“Nova Scotia Power is acting like it just found out it has to get off coal, and now they want Nova Scotia residents to foot the bill,” says Tynette Deveaux with Sierra Club Canada Foundation’s Beyond Coal Atlantic campaign. “They’re treating clean renewable energy as a luxury that the company can’t afford—and we know that’s not true.”Nova Scotia’s solar industry is in its early stages, with only about 4,000 installations to date. Opponents of this proposal say it could decimate the industry before it’s even started, and it is not in alignment with the Sustainable Development Act passed in 2019. The Act calls for carbon levels in 2030 that are 53% below what they were in 2005; and net zero by 2050. Since then, the provincial government announced commitments to power all government offices with 100% renewable energy by 2025 and to close coal plants by 2030.“This announcement makes it very clear we need to work together to break Nova Scotia Power’s monopoly and make it possible for municipalities and individual homeowners and businesses to participate in a rapid transition to clean renewable energy—without being penalized,” said Gretchen Fitzgeral, Sierra Club Canada’s National Program Director.In a media release issued on Friday, “Time to Break Up with Nova Scotia Power“, Sierra Club Canada announced its Power to the People campaign, calling on Nova Scotians to demand energy democracy.This content is protected by copyright and may not be reused. If you want to cooperate with us and would like to reuse some of our content, please contact: editors@pv-magazine.com.

Continue reading