Kansas state Sen. Mike Thompson (R) is supporting new bills that may slow the rate of renewable energy growth in the state. February 3, 2022 Ryan KennedySen. Mike Thompson of Kansas (R) introduced new laws that would require solar and wind facilities to be built only on lands zoned for industrial use. About half the state’s 105 counties are rural and unzoned, so the bill could effectively freeze renewable energy growth in the state. Kansas already uses a fair amount of renewable energy when compared to other states, and the Energy Information Association reports renewables powered 44% of Kansas’ operation in 2020. “It would be sending a message…that, well perhaps Oklahoma, or Missouri, or Nebraska, or Texas or Iowa would be a better and more stable state in which to invest dollars,” said Kimberly Svaty, public policy consultant for the Kansas Power Alliance, which represents the state’s clean energy industry. “In the case of the next generation energy economy, renewable wind is really the beginning,” Svaty added. “It’s wind, it’s solar, it’s battery storage, it’s dealing with nitrogen replacements among many other things, all of which Kansas is standing to be really well positioned to see unprecedented investment from the economic standpoint.” Kansas had the nation’s second highest wind energy generation in 2020. State Senator Mike Thompson, Republican. Image: KS Legislature Thompson said the bill is not about slowing renewables, but about transparency. “All I’m trying to do is make it so that (wind and solar developers) have to file something so that neighbors can kind of see what’s going on and understand it,” Thompson said. “Because obviously if you have a 500 or 600-foot turbine that’s going to be placed on your neighbor’s property but it’s 1,500 feet away from your house, which was happening quite a bit, there are health and safety concerns that you want a say over.” Industry advocates say the bill is an example of government overreach, forcing zoning upon counties that have chosen not to be zoned. Thompson said he is working to revise the bill to consider other options than tackling zoning, but has not yet commented on whether it would be removed. 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

The company is projected to do $1 billion in residential solar project originations this year. February 3, 2022 Ryan KennedyCommonBond, best known for its student financing business, announced it now offers solar financing. The company did a soft launch of its solar loans in Q3 2021, and is now on pace to perform $1 billion in residential solar project originations this year.CommonBond offers customer facing API-based point of sale operations and app and web-based point of sale portals for installers. The software can be integrated with leading solar proposal generation tools,“We believe that cost and awareness are two major obstacles to residential solar adoption,” said Robb Granado, president of CommonBond.  “CommonBond has built a unique set of capabilities for solar installers and homeowners to address those obstacles.” Image: SolarReviews Solar loans are common way to own a PV system. SolarReviews said secured loans such as HELOC run between 3-8.5% APR, depending on credit score. The rate of PACE loans tends to be higher, with APRs between 6.5-8.5%. Unsecured loans have higher APRs, and generally vary widely in their APRs. In general, they range 6-30%, and having a good credit score helps keep rates low. Many solar loans are zero-down, but where down payments are required, they typically range between $0-$300o. You can find a solar loan as short as three years or as long as 30, but typically they range from 10-20 years, said SolarReviews.A Zillow study found solar raises a homes property value by 4.1% on average. On a $500,000 home, that is an increase of $21,500 in value.SolarReviews recommends two different strategies to consider: one would be structuring the loan to have a day-one positive cash flow value, and money back in your pocket month-to-month. The other method would be to shorten the loan, maximizing savings and enjoying several years of clean, free energy for years.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

The company’s 2022 IRP includes plans to retire all coal units by 2035; add nearly 2,400MW of natural gas and 6,000MW of renewable capacity, as well as 1,000MW of energy storage in that same time; and begin distributed energy resource and income-qualified community solar pilot programs. February 3, 2022 Tim SylviaGeorgia Power, the largest electric subsidiary of Southern Company and the power provider for almost all of Georgia, has released its 2022 Integrated Resource Plan (IRP), outlining how the utility plans to provide electricity to its 2.7 million customers over the next 20 years.Headlining the IRP comes the announcement that Georgia Power will retire and decertify all Georgia Power-controlled coal generation units, with the exception of Plant Bowen Units 3 & 4, which will continue to operate no later than 2035. The company’s plan includes retirement of a total of 12 generating units, or more than 3,500MW, by 2028 and, if approved, would begin later this year and continue through 2028.How will this capacity be replaced? Well, first and foremost, Georgia Power is proposing to certify an additional 2,356MW of capacity from natural gas power purchase agreements (PPAs), procured through the company’s 2022-2028 Capacity Request for Proposals (RFP).While the company’s continued commitment to natural gas may be troubling, that isn’t the only resource planned to replace the coal capacity. The utility is also proposing an addition of 6,000MW of renewable capacity by 2035, which includes a request for approval of 2,300MW in the aforementioned IRP, and the bulk of which will likely come from solar.Georgia Power is also requesting approval to own and operate 1,000MW of energy storage by 2030, which includes a specific request for approval to own and operate the 265MW McGrau Ford Battery Facility.Getting away from large-scale generation resources, Georgia Power’s IRP also includes proposals for the creation of distributed energy resource (DER) and income-qualified community solar pilot programs.The DER program would enable participating customers to receive a resiliency service via a company-owned, operated and maintained DER. Participating customers could elect to receive a credit in exchange for the company’s ability to access the DER for the benefit of all customers during a system reliability event, like peak demand reduction or load-shifting. If approved, it would provide system reliability benefits for all customers while supporting commercial and industrial customers with enhanced resiliency needs. This seems to be a pretty standard utility DER response pilot program, though others in the past have opted to allow customers to bring their own battery system, rather than have one provided by the utility, though providing a battery does remove the considerable financial burden of adopting residential storage.the community solar pilot program would provide income-qualified customers access to Community Solar generated energy at discounted prices.  The discount would be made available by participating corporate sponsors who would receive corresponding Renewable Energy Certificates (RECs). Both proposed programs are subject to regulatory approval.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

The new Aurora Sell suite can generate the solar design using proprietary machine learning algorithms, lidar, and imagery data. February 3, 2022 Anne Fischer

Continue reading

The proposal would leave thousands of solar projects in limbo, create dire financial strain among developers, and severely hamper corporate, state, and federal initiatives to support renewable energy. February 3, 2022 Tim SylviaPJM Interconnection, the largest electrical grid operator in the US is proposing a two-year pause on reviewing interconnection requests for its eastern US regional transmission network, as the operator looks to work through its more than 1,200 energy project backlog, with most of these projects being solar.For newly-proposed projects the wait could be much, much longer.The proposal is outlined in PJM’s Interconnection Process Reform Task Force (IPRTF) Update, which was presented on January 24. According to PJM, the increased economic viability of solar energy projects, rapidly-scaling corporate interest in investing in solar, state-level energy policies, and the Biden administration’s continued commitment of expanding the resource have all contributed to a massive influx of new project interconnection requests, and a queue that grows considerably by the day.As outlined by the Interstate Renewable Energy Council’s Gwen Brown and Sky Stanfield in a recent op-ed in pv magazine USA, literally every grid-connected project must go through the interconnection process, a process which is not designed to deliver timely results, nor handle a backlog of such magnitude. Most current interconnection policies handle each request on a project-by-project basis, and were developed prior to the popularization of rooftop solar and other distributed energy resources (DER).And while time can be spent identifying specific shortcomings and necessary improvements of current interconnection standards, the reality of the situation is that PJM’s proposal threatens to stall or lead to the cancellation of thousands of projects, leave developers in dire financial straits, and damage the efficacy of state and federal commitments to transitioning this country to a renewably-powered grid.3/6 To achieve President Biden’s goal of 80% clean by 2030 and 100% by 2035, we have to install roughly 100 GW/year of clean energy. We simply cannot afford to have such a lengthy delay for the country’s largest grid operator if there’s any chance of meeting this goal. Period.— Robbie Orvis (@robbieorvis) February 2, 2022In terms of a real-life outlook, PJM released an outline of pathways it could take to achieving 50% renewable energy across its grid by 2035, a far cry from the Biden Administration’s call to achieve 100% carbon-fee electricity by the same year.Part of PJM’s issue is the historic operation of the wholesale electricity market that it operates, in a region that spans from parts of Illinois, Michigan, and Indiana, to the mid-Atlantic, as far north as New Jersey and as far south as parts of North Carolina. Within this operational area, renewable energy resources have not long been a major feature in the distribution mix, with wind, solar and hydropower plants making up roughly 6% of that mix.PJM’s map of service territory Image: PJM As states in the market have moved to adopt more solar, specifically New Jersey, Illinois, and Virginia, PJM has had to reconsider how it operates, carefully monitoring how each project plays into overall system reliability, an expectedly slow process.Quite simply, the system is growing at a pace it was not designed to, and no action to remedy that imbalance has yet been taken, leading to the breaking point the nonprofit finds itself at today.The solution that PJM has proposed would scoot the most construction-ready projects — those with financing in place, off-takers secured, and hardware accounted for — to the front of the review queue, with the rest of the queue following in a descending order of how construction-ready or speculative they are deemed to be.What has also been proposed is a plan to implement a two-year delay on about 1,250 projects currently waiting in the queue, while new projects would not be eligible for review until the fourth quarter of 2025 at the earliest, with final decisions on those coming as late as the end of 2027.In their ongoing contributions to pv magazine USA Stanfield and Brown intricately outline the policies that have brought about this interconnection overload, as well as steps that should be taken to immediately alleviate the pressure on interconnection queues across the country (it’s not just PJM). You can read the most recent contribution and find links to the rest of the series here.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

Organic Valley, the largest farmer-owned organic cooperative in the US, is teaming up with SunCommon to help Vermont farmers go solar with zero up-front costs. February 3, 2022 Anne FischerSunCommon, headquartered in Waterbury, Vermont, launched a program that offers to help Organic Valley farmers go solar with zero upfront costs. Organic Valley is the largest farmer-owned organic cooperative in the US with a footprint of 100+ Vermont farms. The program provides Organic Valley farmer-members with financing for solar and other renewable energy projects. Farmers benefit from a fully-funded solar installation with no upfront costs, and they save on their energy bill.While SunCommon has offered zero upfront solar to schools and municipalities, this is the first time the company has offered this financing to farms. “They are usually hard to finance, with their capital needs high on the farm operations and low ability to use solar tax incentives on their own,” said Mike McCarthy, commercial solar project consultant at SunCommon.Early participants in this program include Vermont dairy farmers and Organic Valley farmer-members Guy and Matt Choiniere. Now their 500-acre, fourth-generation farm has two recently completed solar projects on the rooftops of two existing barns that will produce an estimated 115,500 kWh annually with a projected annual cost savings totalling more than $20,000. The larger (72kW) project, which has 197 Talesun 365W modules, is expected to offset close to all of their electricity costs. The smaller (32kW) project with 88 Talesun 365W modules, is offsetting power costs for the Bouchard Family Farm up the road.“What I love is that this revives a barn that was losing value and that we were planning to retire,” said Guy Choiniere. “Now, with new solar panels on the roof, we have revitalized this space such that there is a new milking parlor on the inside producing value and energy production on top, also producing value. And, it was all so easy to do. SunCommon managed the entire process, including labor, materials, and all the nitty gritty details. We were able to carry on with our daily farm operations without a hitch.”To date, SunCommon has worked with 75 farmers in Vermont and New York on solar energy projects.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

Invinity grid-scale flow battery units at a site in England, UK. Image: Invinity Energy Systems.

Invinity Energy Systems will supply vanadium redox flow battery (VRFB) technology to a solar-plus-storage project in Alberta, Canada.

The project, Chappice Lake Solar + Storage, will combine a 21MWp solar array with a 2.8MW/8.4MWh battery storage system, Anglo-American flow battery company Invinity said today, together with the project’s developer, owner and operator, Elemental Energy.  

Alberta is largely synonymous with fossil fuels; it hosts crude oil production from sites including its northern tar sands, produces a large portion of Canada’s natural gas and is largely reliant on the country’s largest coal fleet for electricity. 

One of the province’s key climate and pollution pledges is now the phasing out emissions equivalent to 50% of that coal fleet by 2030. 

The Chappice Lake project was one of a number of ‘shovel-ready’ projects awarded funding late last year through the provincial government’s Emissions Reduction Alberta (ERA) scheme. 

In that round of funding, reported by Energy-Storage.news in November 2021, a 400MW closed-loop pumped hydro project called Canyon Creek was picked out for support too. Also benefiting were a number of projects seeking to reduce the emissions and increase the efficiency of some of the region’s fossil fuel extraction and refining activities. 

At the time, ERA said it would administer the award of CA$10 million (US$7.89 million) of the total expected cost of Chappice Lake, just over CA$40 million. 

Invinity’s flow battery will be directly DC-coupled with the solar array, improving the project’s efficiency, operational flexibility and costs. Charging from the solar PV modules, it will store and send out low-carbon, low-cost energy. 

Being able to deliver power on demand will also help alleviate constraints to deploying more renewable energy on the grid, eliminating bottlenecks in power flow, Invinity said. 

The project is expected to go into service later this year.

Developer Elemental Energy is also partnering with local indigenous group Cold Lake First Nations, which will hold an equity interest in the Chappice Lake project and the community will also benefit from the new electricity capacity addition as well as employment opportunities the clean energy industry can bring to the area, Elemental claimed. 

“Alberta has a long history of leadership in energy; the fact that this shovel- ready project will expand that leadership in new directions while creating great new jobs is a testament to how Alberta can innovate and build,” Invinity Energy Systems’ chief commercial officer Matt Harper said.

“Clean energy on demand is becoming an increasingly valuable commodity; in delivering solar and storage together at Chappice Lake, we will prove that solar generation plus Invinity’s utility-grade vanadium flow batteries can make Alberta a powerhouse for the North American grid.”

Vanadium flow batteries have been touted as a long-duration, long-life energy infrastructure asset. Capable of being scaled up in energy capacity by increasing the size of their electrolyte tanks, the systems are expected to last decades in services without degradation or fading of battery capacity. 

In December, Lockheed Martin announced that the first megawatt-scale pilot for its own flow battery technology — for which the aerospace and defence giant has not revealed the battery chemistry publicly — will also be in Alberta. 

Lockheed Martin claimed that a 6.5MW/52MWh unit of its GridStar Flow battery energy storage system (BESS) technology will be paired with a 102.5MW solar farm in development by infrastructure company TC Energy. Lockheed will invest about US$9 million into the Saddlebrook Solar + Storage Project, with an expectation that funding will also come from ERA.

On a broader note, Energy-Storage.news has reported on a number of other Alberta-based energy storage projects in the past couple of years. The province’s first grid-scale battery storage system, a 10MW/20MWh Tesla lithium-ion BESS called WindCharger, went online in late 2020, paired with a local wind farm. 

TransAlta, the Canadian company behind that project, has just applied to Alberta regulators for approval for WaterCharger, a 180MW BESS paired with hydroelectric generation facilities. 

Alberta’s grid operator AESO is also piloting the use of energy storage resources for fast frequency regulation. 

Continue reading

Solar PV paired with battery storage at another mining site in Australia. Image: Aggreko.

Construction has started on BHP’s “first off-grid large-scale renewable energy project”, totalling 38 MW of solar power and a 10.1MW/5.4 MWh battery energy storage system (BESS), at two nickel mines in Western Australia which supply Tesla for use in electric vehicle (EV) batteries.

The Northern Goldfields Solar Project will comprise a 27.4 MW solar farm at Mt Keith and a 10.7 MW solar farm with the BESS at nearby Leinster. It will help replace power currently supplied by diesel and gas and reduce scope 2 emissions at the two mines by 12%, or 54,000 tonnes of CO2e, and will start generating solar power in November. 

This will bolster BHP’s journey to becoming net zero but also shore up the energy-intensive mines’ energy supply and reduce costs for transporting and burning diesel, and the group is one of many mining firms launching such projects in Australia and elsewhere. 

BHP is investing AU$73m (US$52m) in the project which is being built and operated by global renewables group TransAlta Renewables, which has contracted German company Juwi for engineering, procurement and construction (EPC) duties. 

The sites will supply electricity to BHP’s mines under a power purchase agreement (PPA) with TransAlta which runs to 2038, and the two parties have agreed to identify potential sites for 40-50 MW of wind generation which would further reduce scope 2 emissions at the mines by 30%. 

BHP Nickel West Asset President Jessica Farrell noted that it is BHP’s “first off-grid large-scale renewable energy project across our global operations,” and it also marks TransAlta’s first renewable energy project in Australia.

Energy company EDL says there is about 2 GW of off-grid energy demand in Australia, and that around $2.5bn of investment will be needed to meet half of this with renewables.

The country has been a hotbed of such projects recently.

Last week IGO Limited announced that solar-plus-storage would be installed at its Nova copper-cobalt-nickel mine at Fraser Range allowing the site to temporarily operate on 100% renewable energy. Rio Tinto announced plans to install a 4MW solar and 4MWh BESS at its Weipa bauxite mine in September, with construction expected to begin later this year. 

The group’s solar solar-wind-storage system totalling 28.25 MW, of which 8.25 MW is storage, at its QMM ilmenite mine in Madagascar is further along with solar operations expected to begin in Q2 2022 and wind by the end of the year. It should eventually provide 60% of the mine’s electricity.

Elsewhere in Africa, equipment manufacturer Caterpillar recently supplied 7.5MW of battery storage to the microgrid powering the Kibali gold mine in the Democratic Republic of the Congo (DRC).

In April last year, an off-grid hybrid energy system at gold mine Fekola, Mali, went online with 30MW of solar PV and a 17MW/15.4MWh BESS. Across the Atlantic, Energy-Storage.news reported last week that technology group Wärtsilä had won a contract to provide the South American nation Suriname’s first-ever utility-scale energy storage system, a 7.8MW/7.8MWh BESS to an unnamed gold mine.

Continue reading

Also on the rise: Phoenix solar market could be brought back to life. Owners of distributed solar and distributed storage may soon earn money from participating in wholesale markets through an aggregator. Hyperlight licenses design of plastic CSP receiver from NREL. Fire at Vistra’s Moss Landing Energy Storage Facility not caused by battery. Mississippi Power issues RFP seeking 200MW of solar. Cybersecurity specialist offers considerations for renewable power plants. Massachusetts community solar to provide electricity bill credits to low-income subscribers

Continue reading

Water will come down into Gouvães reservoir (pictured), from Daivões reservoir 650 metres above it. Image: Iberdrola.

Iberdrola expects its 880MW pumped hydro plant at the Tâmega energy storage complex in northern Portugal to become fully operational in the middle of this year. 

It has just connected the first of four 220-MW turbines at the Gouvães hydroelectric power plant, which will provide 880MW of pumped hydro energy storage (PHES) alongside two run-of-river hydroelectric plants which bring the complex’s total hydoelectric power to 1,158MW. Gouvães and one other will go online in mid-2022 while a third will start in mid-2024. 

The Gouvães plant will increase Portugal’s pumped hydro power by 30% from where it is today. 

The Tâmega energy storage complex is being built on the Tâmega river with €1.5 billion (US$1.69 billion) of investment by Iberdrola, with the help of a €650 million loan from the European Investment Bank (EIB).

It will be able to produce 1,766 GWh per year and will be a hybrid plant with two attached wind farms totalling 300MW. The wind power will partially be used to drive the water back up to the Gouvães reservoir, as well as being fed into the grid. 

The Gouvães plant ranks as one of the larger pumped hydro projects of recent years.

It is the same size as a recently proposed 900MW project in Wyoming, US, and a bit smaller than India’s 1.2GW project in Andra Pradesh. The latter will be combined with 2GW of solar and 400MW of wind power, awarded to developer Greenko through a competitive tender process, recorded as the lowest priced renewables-plus-storage project in the world when it was approved in 2018.

Australia’s first new pumped hydro project in nearly 40 years is 250MW and currently under construction. Elsewhere a 500MW project in California and a 450MW project in Scotland are at different stages of gaining approval. 

Tâmega will provide around half the pumped hydro power of the largest existing pumped hydro plant in Europe, the 1,780MW Cortes-La Muela in Valencia, Spain, which was built in the 80s.

Workers in tunnels at the Tâmega complex. Image: Iberdrola

Continue reading