RWE’s Hickory Park solar project in Georgia, which includes 40MW/80MWh of co-located battery storage. Image: RWE.

The US state of Georgia’s Public Service Commission (PSC) has approved state utility Georgia Power’s 2022 Integrated Resource Plan (IRP) that maps out how the company will deploy more renewables and energy storage technology over the next three years as well as strengthen the state’s network of transmission lines and grid infrastructure.

The approved 2022 IRP, which was filed with PSC back in February, will see the company deploy 2,300MW of new renewable energy resources over the next three years, with its long-term plan targeting a total of 6,000MW of additional renewable resources by 2035.

It will also see 500MW of battery storage rolled out. However, in announcing the filing of the plan in January, Georgia Power said it had actually requested the right to own and operate 1,000MW of battery storage by 2030.

In addition to the 500MW of new battery storage, a specific request by Georgia Power for the utility to be allowed to own and operate McGrau Ford Battery facility, a 265MW battery energy storage system (BESS) at a substation in Cherokee County, was also approved.

McGrau Ford will be Georgia Power’s single largest BESS project to date. The company has filed its first request to own and operate BESS assets in its 2019 IRP. Three projects totalling 80MW were approved by the commission from that previous plan.

Progress has already been made on the first and largest in that portfolio, Mossy Branch, a 65MW/260MWh project in Talbot County, which got approval in October last year and a 13MW project with the US Army at Fort Stewart near Savannah.

In June, Hickory Park Solar, a 195.5MW solar PV power plant with 40MW/80MWh battery storage (pictured above) went online, developed by European energy company RWE. Georgia Power has signed a 30-year power purchase agreement (PPA) for that plant, which RWE will continue to own and operate.

More recently, it was revealed that the utility has been in talks with startup Form Energy, developer of a novel iron-based battery chemistry energy storage technology, over a potential 15MW/1,500MWh project.

Georgia Power’s transition away from coal

Also approved from the 2022 IRP was Georgia Power’s proposed a pilot distributed energy resource (DER) scheme for 250MW of generation. The ‘DER Customer Program’ enables participating customers to receive a resiliency service via a company-owned, operated and maintained DER, such as a solar and battery energy storage system, with participants able to elect to receive a credit in exchange for the company’s ability to access the DER.

Moreover, Georgia Power has approved the retirement and decertification of all Georgia Power-controlled coal units by 2028, with the exception of one site, Plant Bowen, although it has approved more than 2,000MW of capacity from natural gas power purchase agreements (PPAs) in the coming years.

The utility said it was “incredibly important” to continue investments in renewables and gird infrastructure by “working constructively with the Georgia Public Service Commission” as it looks to build out its renewable energy resources.

Georgia Power files an IRP with the Georgia PSC every three years to outline how it will provide energy to its 2.7 million customers over the next 20 years.

Additional reporting for Energy-Storage.news by Andy Colthorpe.

This story appeared first in its original form on PV Tech.

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The co-located solar and storage project in Malawi. Image: JCM Power.

The World Bank has provided guarantees for US$24 million of equity and shareholder loan investments into a 20MW solar-plus-storage project in Malawi.

The Multilateral Investment Guarantee Agency (MIGA), an arm of the Bank, has issued the guarantees to JCM Golomoti UK Limited for equity and shareholder loan investments into Golomoti JCM Solar Corporation Limited for the development, construction and operation of a new 20MW solar photovoltaic plant in Malawi.

The project recently entered commercial operations, as reported by Energy-Storage.news, and is the first grid-connected utility-scale co-located project in sub-Saharan Africa and the first utility-scale battery in Malawi. It pairs a 28.5MWp solar farm with a 5MW/10MWh lithium-ion battery energy storage system (BESS), supplied by Sungrow, although it is described by the companies involved as a 20MW project.

The guarantees will extend over 20 years and protect JCM against the risks of transfer restriction and breach of contract. MIGA says it provides guarantees to help investors protect investments against political and non-commercial risks in developing countries.

“MIGA is pleased to support ongoing electrification in Malawi and the first deployment of solar battery storage technology in the country,” said Hiroshi Matano, executive vice president of MIGA. “By helping to diversify the energy supply, the new plant contributes to Malawi’s transition to a low-carbon and climate-resilient economy.”

The country in southeastern Africa has among the lowest electricity access rates in the world at just 11.2% in 2019 according to the World Bank, with plans to increase this to 30% by 2030. It does have a high renewable generation proportion of 75%, mainly from hydropower in Lake Malawi, but this makes it vulnerable to the impacts of climate change.

As well as smoothing out the intermittency of the solar PV plant, the BESS will help manage peak loads on the grid reducing the requirements of fossil fuel generating plants.

JCM Golomati UK Limited’s parent company JCM Power is an existing MIGA client, having obtained guarantee coverage for their investments in the 60MW Salima solar power project in Malawi in 2019.

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Image: Uniper Energy Storage.

E.ON spinout Uniper Energy Storage has received €2.75 million (US$2.8 million) in EU grant funding towards a project to store hydrogen at scale in a salt cavern in Northern Germany.

Uniper Energy Storage will test the construction and operation of a new salt cavern specifically built for hydrogen storage at scale at a natural gas storage facility in Krummhoern, Northern Germany, closed since 2017.

The project, called KRUH2, is also being funded by the state of Lower Saxony and will test how green hydrogen produced by electrolysers can meet a plant’s own demand for heat, mobility and electricity. The company said the project will be the first of its kind.

A new pilot cavern will be built using an existing well, and the storage facility is scheduled to start operating by 2024. Uniper Energy Storage will invest around €10 million in the project with a storage volume of up to 250,000 cubic metres of hydrogen, though it hasn’t revealed the MW power of the planned electrolysers or the MWh storage capacity of the cavern.

The project aims to provide information across the entire green hydrogen value chain on how the gas can be stored and how equipment and materials react to hydrogen. A flow chart from Uniper (pictured) illustrated its potential long-term use cases, including fuel for transportation, industry, powering fuel cell generation and direct injection into the transmission grid.

Doug Waters, managing director of Uniper Energy Storage, said: “We are delighted about the funding commitment from the state of Lower Saxony. With this pilot project, we are gathering the empirical data that we urgently need in a world without fossil fuels: namely, how we can realize the storage capability of green electricity in a CO2-free future.”

Uniper Energy Storage is part of Uniper Energy, which was created when energy giant E.ON spun out its conventional generation, commodities segment and energy trading businesses in 2016. Uniper Energy Storage operates natural gas storage facilities in Germany, Austria and the UK with a working gas capacity of over 7.5 billion cubic meters.

It said green hydrogen will be important for balancing energy supply and demand fluctuations in future, but that existing storage facilities for gas need to be converted for hydrogen use.

A press release said that Krummhoern’s geographic location near the windy North Sea and its decades-old energy connections to the gas and electricity grids make it an ideal location for the project.

While far from being tested or commercialised at scale anywhere, green hydrogen projects are attracting significant attention and investment globally. Its ability to scale easily, relatively low cost once scaled, and use of existing gas infrastructure make it an attractive option for many governments and companies, with Germany particularly bullish on its potential.

Its most economical use case is as a replacement feedstock for industry, particularly ammonia fertiliser production for the food industry, followed by use in transportation and then as a replacement for natural gas in combined cycle power plants. A fourth use case is for electricity energy storage, whereby the produced hydrogen is then converted back to electricity, but very low round-trip efficiency currently prevents this from being economical according to most in the industry.

While appearing considerably smaller based on the investment size, KRUH2 is set to come online a year earlier than another major green hydrogen project using a cavern, ACES Delta in Utah, US. That project is being financed by over US$1 billion in equity and Department of Energy (DOE) loans and will have 300GWh of green hydrogen energy storage capacity.

Uniper’s project funding comes a month after another green hydrogen storage project was announced at a campus of the DOE’s National Renewable Energy Laboratory in Colorado. Called HY2MEGA, the project will pair green hydrogen storage subsystems with existing electrolysers and a fuel cell plant on the site to be stored for conversion to electricity.

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Wildfire season causes many problems each year in the US including impacts on the electric grid and peoples’ ability to keep the lights on. Pictured is a 2013 wildfire at Yellowstone National Park. Image: Mike Lewelling, National Parks Service via Flickr.

The US Department of Energy (DOE) has launched 140 programmes to advance equitable development of climate, sustainability, and health measures, including a US$5 billion grid resiliency grant.

The announcement was made yesterday that the programmes in support of President Biden’s Justice40 initiative are underway. Funding is being unlocked through the historic Bipartisan Infrastructure Law (BIL) legislation that Biden was able to pass through last year, committing billions to overhauling the US’ infrastructure with targeted investments.

Through Justice40, at least 40% of improvements in areas including climate mitigation and clean energy, water quality and housing will benefit disadvantaged communities.

Key among these, from an energy storage perspective, are US$5 billion in grants for the ‘Preventing outages and enhancing the electric grid,’ which was first announced in January. It will offer funding to the likes of electric grid operators, electricity storage operators, generators, transmission and distribution entities, fuel suppliers, states and tribes.

They will be able to use the money towards activities that supplement existing efforts to increase resiliency of electricity supply as well as reduce the likelihood that wildfires are caused or exacerbated by electric infrastructure. Efforts should also reduce the likelihood of outages and disruptions.

A Request for Information (RFO) is available from the Federal Register here and the DOE anticipates that the programme will open for applicants in the third quarter of 2022.

Along with grants to help local authorities and tribal nations to reduce fossil fuel use and improve energy efficiency worth US$550 million and other programmes, electrification programmes for buildings and much more, a DOE press release highlighted that US$10 million financial assistance will be available to states, utilities, tribes and academic institutions towards design, permitting, technical studies and other aspects of siting and building pumped hydro energy storage (PHES) systems in their region.

The full list of BIL-enabled programmes that support Justic40 aims includes several funding opportunities Energy-Storage.news readers may already be aware of.

The newly established DOE Office of Clean Energy Demonstrations for example is funding pilot programmes for energy storage technologies, (US$355 million grants) and a long-duration energy storage demonstration and joint development scheme (US$150 million). Again, both are expected to open for applicants in the third quarter of 2022.

You can read the full list of funded programmes here.

US$2.5 billion loan kicks off battery manufacturing support

In related news, the DOE’s Loan Programs Office has made its first conditional commitment to support the battery manufacturing industry.

Ultim Cells, a joint venture (JV) between carmaker General Motors (GM) and battery company LG Chem, looks to be getting a loan worth US$2.5 billion from the Loan Programs Office (LPO) for the construction of three new lithium-ion battery factories in Ohio, Tennessee, and Michigan.

It will help supply cells to support GM’s manufacture of a million EVs in North America by the end of 2025 and create 6,000 construction jobs and 5,100 operations jobs at the factories themselves. Ultim makes nickel cobalt manganese aluminium (NCMA) chemistry battery cells.

Although the investment directly supports electric vehicle battery manufacture and not stationary energy storage systems, DOE noted that the Federal Consortium for Advanced Batteries – a group of four federal agencies banded together – has identified grid storage as one of the key end markets for lithium batteries.

The BIL funding will also inject US$7 billion into critical minerals supply chains for the battery industry, including components, materials and recycling businesses.

The DOE’s Loan Programs Office had lain dormant during the Trump presidency but reopened with sustainable infrastructure investor and solar industry veteran Jigar Shah at the helm. Its first loan offer, made a few months ago, is to the 300GWh Utah ACES green hydrogen storage project, the consortium behind which will borrow US$504 million.

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COP26 president Alok Sharma (left) meets with Niti Aayog VC Suman Bery last week. Sharma also met with Power Minister RK Singh and visited the National Institute of Solar Energy and other organisations on his trip. Image: Niti Aayog.

India’s government has added an Energy Storage Obligation alongside its Renewable Purchase Obligation for the first time.

Meanwhile, a government thinktank has predicted around 180GWh of demand for batteries for stationary energy storage systems (ESS) by 2030.

Last week, the country’s Ministry of Power issued an order revising the tariff policy around Renewable Purchase Obligations (RPO), through which entities such as electricity distribution licensees must ensure a minimum of energy consumed comes from renewable sources.

Earlier this year, Power Minister RK Singh said energy storage would be included in the policy. The new order sets a trajectory to the years 2029-2030.

Along with stipulating certain parameters for energy storage’s eligibility, the government has determined that large-scale pumped hydro energy storage (PHES) over 25MW be classified as part of the RPO under a separate Hydro Purchase Obligation.

By 2029-2030, combined wind, hydro and other renewable energy purchase obligations will reach a combined 43.33%, comprising 6.94% wind, 2.82% hydro and 33.57% other renewable.   

The Energy Storage Obligation (ESO) specifies that the percentage of total energy consumed from solar and/or wind, with or through energy storage should be set at 1% in the 2023-2024 timeframe and gradually rise to 4% by 2029-2030, as in the table below.

Energy Storage Obligation will be fulfilled when at least 85% of energy procured and stored on an annual basis comes from renewable energy sources.

Financial YearStorage percentage of consumption (on an energy basis)2023-20241.0%2024-20251.5%2025-20262.0%2026-20272.5%2027-20283.0%2028-20293.5%2029-20304.0%

Read the Ministry of Power’s order on the RPO and ESO trajectory to 2029-2030, here.

Government thinktank estimates 182.9GWh cumulative ESS battery demand 2021-2030

The order is the latest step in market-seeding activities by the government of India, which is targeting a total of 500MW generation capacity from non-fossil fuel sources by 2030, including 450GW of wind and solar PV, and has already exceeded 150GW.

The national Central Electricity Authority has previously determined that this will require about 28GW/108GWh of energy storage to integrate into electricity networks.

However, industry group India Energy Storage Alliance (IESA) has modelled a need for 160GWh or more of storage by that time, and a new report from government tech and innovation Niti Aayog forecasts that it could be even higher.

Last week British politician and COP26 president Alok Sharma met with Niti Aayog CEO Parameswayan Iyer and its vice chairman Suman Bery to discuss collaboration between the UK and India on electric mobility as well as reuse and recycling in the battery market.

The think tank has produced a report in partnership with the UK government on the prospects for advanced chemistry cell (ACC) battery recycling and reuse in India. India is currently supporting private entities from home and abroad to set up 50GWh of annual ACC manufacturing capacity by 2025 and is hotly anticipating much more will come online.   

While the report therefore focuses on various aspects of the battery industry ecosystem, it begins with an estimated forecast of demand for batteries across all sectors to 2030.

It predicts a total cumulative potential demand between 2021 and 2030 of 600GWh: electric vehicles (EVs) of various kinds take the biggest share at 380.6GWh, while grid applications total 136.4GWh, behind-the-meter applications 46.5GWh, while consumer electronics demand for batteries is forecast at about 36.4GWh.  

Niti Aayog estimated cumulative demand for batteries in India by sector, 2021-2030. Image: Solar Media / data from Niti Aayog report.

Read the full report: ‘Advanced chemistry cell battery reuse and recycling market in India,’ here.

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Rhett Bennett

Cypress Creek Renewables has added 400 MW/600 MWh to its storage portfolio after acquiring four Texas standalone energy storage projects from Black Mountain Energy Storage (BMES). The projects, each 100 MW, are located throughout the Electric Reliability Council of Texas (ERCOT) market and are currently under development.  

Cypress Creek will continue project development, entitlement, engineering, procurement, financing and construction. It will operate the 400 MW/600 MWh portfolio once complete. The four projects are expected to be placed in service in 2024. 

Nationally, Cypress Creek has developed more than 11 GW of solar to date and has a 15 GW solar and storage pipeline. In the ERCOT market, Cypress Creek has developed 5 GW of solar and storage assets, bringing resiliency and flexibility to the grid.   

“ERCOT is an incredibly dynamic power market, and standalone storage assets will continue to provide opportunities to increase grid reliability through flexible and dispatchable resources,” says Jack Murray, director of M&A at Cypress Creek. “Black Mountain has been an exceptional partner to work with and we are excited to throw our development, EPC and financing expertise behind these assets to move them across the finish line, affirming our commitment to developing resilient renewable energy resources throughout Texas.” 

“It was a pleasure working with the Cypress Creek team, and we are pleased to have assisted them on their journey to be one of the most significant renewables developers in the U.S.,” states Rhett Bennett, CEO of BMES. “Cypress not only understands the power market, but also the critical importance of energy storage. They are committed to renewable energy, and we are excited about the potential of these projects and the immense positive impact they will bring to the grid.” 

The transaction was facilitated through the LevelTen Energy Asset Marketplace, connecting renewable energy projects and buyers towards deal execution. 

“It was an honor to support this transaction via the LevelTen Asset Marketplace, which brings together project developers and investors, and delivers the online tools they need to complete asset sales,” comments Patrick Worrall, vice president of Asset Marketplace, LevelTen Energy. “Black Mountain Energy Storage and Cypress Creek Renewables are leaders in the industry, and we look forward to watching development on this portfolio of storage projects progress.”

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IEA’s St. Joseph Solar Farm in St. Joseph County, Ind.

MasTec and Infrastructure and Energy Alternatives Inc. (IEA) have entered into a definitive agreement under which MasTec will acquire all of the outstanding shares of IEA in a cash-and-stock transaction valued at $14 per IEA share. The transaction has been unanimously approved by the boards of directors of both MasTec and IEA.

The acquisition is expected to close late fourth quarter of 2022, subject to IEA stockholder and Hart-Scott-Rodino approvals, regulatory approvals and other customary closing conditions. MasTec has entered into agreements with various IEA stockholders, which collectively own approximately 35% of IEA’s outstanding stock, to vote their shares of IEA common stock in favor of the transaction. Based on estimated IEA net debt levels at closing, the total transaction consideration will be approximately $1.1 billion. MasTec expects to issue approximately 2.8 million MasTec shares in the transaction.

“We are proud to expand our service capabilities, scale and expertise providing critical infrastructure to support the nation’s energy transition to secure and sustainable renewable sources,” says Jose Mas, MasTec’s CEO. “We are excited to welcome JP, the IEA management team and almost 6,000 IEA team members to the MasTec family. We have long admired IEA’s operating excellence, and we have a strong cultural alignment with IEA in safety and customer service.”

Founded in 2011 with roots dating to 1947, IEA is a renewable energy and infrastructure solutions services provider with expertise and capabilities spanning engineering, procurement, construction and other related services. It has completed more than 260 utility-scale wind and solar projects across North America.

“We believe that the addition of IEA’s union based clean energy power generation services, coupled with MasTec and IEA’s combined non-union craft labor capacity, will provide increased scale and capacity needed to meet expected growing customer demand for renewable power generation over the next decade,” continues Mas. “We also believe that MasTec’s existing electrical transmission and distribution service capabilities, coupled with expanded renewable power generation services from the IEA acquisition, will provide a compelling and complete suite of services to support customer’s needs for both power generation and power grid system infrastructure required to transition to renewable energy and reduce carbon emissions.”

Under the terms of the agreement, IEA stockholders will receive $14 per share, comprised of $10.50 per share in cash and 0.0483 of a MasTec share, with a value of $3.50 per share, based on MasTec’s closing share price on July 22, 2022, and represents a 34% premium to IEA’s closing stock price on July 22, 2022.

“The combination with MasTec will create new opportunities for IEA’s employees and our customer base, states JP Roehm, IEA’s president and CEO. “Our joint resources and capabilities will advance our ability to serve our customers in the renewable energy, power delivery and infrastructure markets. We believe that IEA stockholders will benefit from MasTec and IEA’s combined operations and scale, and this belief is reflected in our agreement to receive 25 percent of the transaction proceeds in MasTec common stock. MasTec is the ideal owner for IEA, and I am excited to continue to lead the IEA team during this exciting new chapter of our story.”

IEA is reaffirming its expectation that full year 2022 revenue will range between $2.3 to $2.5 billion, with net income ranging between $45 to $51 million, adjusted EBITDA (a non-GAAP measure) ranging between $140 to $150 million.  For 2023, MasTec expects that IEA will generate revenue between $2.6 to $2.7 billion, with adjusted EBITDA ranging between $160 to $170 million, exclusive of any post transaction synergies1. MasTec expects near term post transaction annual cost savings of approximately $10 million primarily from the combination of reduced IEA public company reporting and other costs. Inclusive of both transaction finance costs as well as expected synergies, MasTec expects that IEA will generate approximately $45 to $50 million of adjusted net income (a non-GAAP measure) in 2023.  

MasTec has obtained committed bridge financing from Bank of America and J.P. Morgan, should it be needed, to complete the transaction. MasTec, however, intends to pursue certain other debt financing alternatives to finance the cash portion of the transaction consideration.

J.P. Morgan Securities LLC is serving as financial advisor to MasTec, and Fried Frank Harris Shriver & Jacobson LLP and Holland & Knight LLP are serving as legal counsel. Lazard is serving as financial advisor to IEA, and Gibson, Dunn & Crutcher LLP is serving as legal counsel.

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Rendering of EVLO containerised battery units. Image: EVLO.

Renewables developer Innergex has completed a battery energy storage system (BESS) project in France, using a BESS solution designed by a subsidiary of utility Hydro-Québec.

Full commissioning has taken place of the 9MW/9MWh Tonnerre BESS at Joux-la-Ville, a small commune in the north-central French region of Bourgogne-Franche-Comté, Innergex, which is also headquartered in Quebec, Canada, said on Friday (22 July).

The battery system has been built close to two existing Innergex wind farms, Yonne, built in 2016 with 44MW gross generation capacity and 30.6MW net capacity, and Yonne II, commissioned in 2021 with 6.9MW gross and 4.8MW net capacity.

The plant will contribute to local grid stability and help maintain network security of supply. Innergex was handed a 7-year capacity contract for the plant from France’s grid operator RTE. When it isn’t being called upon by RTE to provide system services, Innergex will be able to use the asset to participate in other revenue-generating market opportunities.

It’s the latest in a wave of BESS projects being developed and constructed in France, a battery storage market which to date has been slower to develop compared to those in neighbouring Germany or the UK.

In fact, Innergex’s Tonnerre plant represents about 1% of the amount of publicly announced battery storage expected to be deployed at grid-scale in France during 2022 and 2023, according to figures provided in March to Energy-Storage.news by energy storage consultancy group Clean Horizon.

Clean Horizon tallied together project announcements and found about 900MW of projects this applied to. Analyst Corentin Baschet from the firm said in an interview that this rapid progress was remarkable given that – unlike the UK where battery operators can access several different revenue streams – batteries in France can basically access only two.

One of those is long-term contracted revenues for capacity market participation and the other is the European frequency control reserve (FCR) aka primary control reserve (PCR) ancillary services market. However, a third revenue stream, secondary reserve, or automated frequency restoration reserve (aFRR) is in the process of being opened up.

aFFR’s introduction had been scheduled to already happen in France late last year, but the ongoing crisis over rising electricity prices in the country led regulators to put a pause on it. It is expected in the coming months in France and its introduction is being staggered across the various European markets by 2025 in coordination with each territory’s regulators, grid operators and other main stakeholders.

While there have been solar-plus-storage sites built in France’s island territories through tenders over the past few years, the biggest battery storage site in mainland France so far is a 61MW/61MWh project in Dunkirk, northern France, developed by TotalEnergies and supplied by battery storage company Saft, which TotalEnergies owns.

Chart of French grid-scale battery developers and their publicly announced assets, as of March 2022. Image: Clean Horizon Consulting.

At the Tonnerre site just commissioned, Innergex contracted EVLO to supply the BESS solution used. Utility Hydro-Québec, which has the provincial government of Quebec as its main shareholder, launched EVLO in late 2020 to capitalise on opportunities in the growing energy storage market.

EVLO Energy Storage, to give its full name, designs and makes battery systems based on lithium iron phosphate (LFP) cells. Prior to launch to the wider market, the systems were tested in operation on Hydro-Québec’s own grid network, performing a range of applications.

The Tonerre project was partially announced to be the subsidiary’s first project, and its expected commissioning date had been for late 2021, which appears to have been pushed back.

In December last year EVLO launched EVLO1000, a modular, containerised BESS unit with 1MWh capacity equipped with battery management system (BMS) technology developed by Silicon Valley company Nuvation.

Innergex noted that EVLO’s BESS enclosure at Tonnerre is IEC 62933 certified and UL 9540A tested, while the system’s energy management system (EMS) developed in-house at EVLO made it capable of meeting RTE’s stringent requirements for frequency reserve providers.

Founded in 1990, the developer to date has put 3,484MW net capacity of renewable energy assets into operation, most hydroelectric and wind, with some solar sites in Canada, France, Chile and the US. The Tonnerre project marks its first-ever standalone battery energy storage project.  

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Renewables-plus-storage at Agnew Gold Mine, Australia. Image: EDL.

Early engineering work has begun on a hybrid power plant project at a uranium mine in the Republic of Niger, according to independent power producer (IPP) Enernet Global.

US-headquartered Enernet Global said on Friday (22 July) that work has commenced on the microgrid for Global Atomic Corporation’s Dasa Project which lies within one of six zones for which Global Atomic holds uranium exploration permits in the African country.

The power plant needs to provide 12MW of peak load for the uranium mine. It will do this with a combination of 16MW solar PV generation capacity, a 15MW battery energy storage system (BESS) and 16MW of diesel generation for backup.

It will also be integrated into the local grid owned and operated by Sonichar, a majority state-owned utility company.

The power plant will lower the mine’s upfront capital costs while supporting the local economy through purchasing power from Sonichar, as well as creating a solar legacy for the region, Global Atomic chairman and CEO Stephen Roman said.

Meanwhile, the addition of backup generators should reassure investors that power supplies to the mine will be fed reliably at all times, Roman said.

A feasibility study completed late last year found that the high-grade sandstone uranium deposit at Dasa could offer IRR of 22.7% over 12 years with an assumed uranium price of US$35/lb, according to Global Atomic Energy.

Enernet said early engineering works underway include preliminary design of the plant, equipment selection and configuration of the connection to Sonichar’s grid.

This phase will be complete late this year, after which construction will begin for an expected commissioning date in 2023. Enernet’s local subsidiary headquartered in South Africa will carry out the project and the company will own and operate the hybrid power plant.

“This will be one of the greenest operations in Sub-Saharan Africa,” Enernet CEO Paul Matthews said.

It’s the latest in a line of projects at remote mining sites all over the world, where power needs are great, but access to sufficient reliable grid electricity capacity is often not. Mine operators frequently have to rely on fossil fuels brought onto site by trucks.

These are not only polluting but expensive and can present logistical challenges to deliver regularly, while solar PV and battery storage are considered to require less maintenance than thermal power generation equipment.

Recent examples of forthcoming projects reported by Energy-Storage.news include financial close achieved in June for a flow battery-based minigrid for a vanadium mine in South Africa and a project in development by Hitachi Energy at another vanadium mine, this time in Nevada, US.

At Agnew Gold Mine in Western Australia, a hybrid solar-wind-plus-storage power plant enables the mine to run on an average of around 50% to 60% renewable energy penetration, a figure which gets up to 95% at times. The Australian Renewable Energy Agency (ARENA) which helped fund the project said earlier this year that the Agnew hybrid power plant (pictured above) has been operating successfully since its commissioning last November.

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Developer Neoen’s 350MW Victorian Big Battery in Victoria, Australia. The company is now building a 100MW/200MWh system in the ACT. Image: Victoria State government.

The state government of the Australian Capital Territory (ACT) will pledge funding towards a battery energy storage system (BESS) rollout in its 2022-2023 budget to be announced 2 August.

The government’s procurement process is already open for the Big Canberra Battery, a three-stage energy storage project through which it aims to get a 250MW grid-connected BESS built, followed by smaller systems at government buildings and then a set of ‘neighbourhood batteries’ for residential communities.

Although an announcement today from the office of ACT Chief Minister Andrew Barr did not disclose the amount of investment, various reports in local media said the state government will commit around A$850,000 (US$586,000) initial funding from the budget to get the project started.

The project was first revealed in a previous budget for 2020-2021, with the ACT government pledging to invest a total of A$100 million in the project over five years.

“The ACT is leading the nation on climate action. We are already powered by 100% renewable electricity, and the next step in our plan to reduce emissions and provide sustainable energy to Canberra households is the delivery of one of the largest battery storage systems in the Southern Hemisphere,” Barr said, with the ACT targeting net zero emissions by 2045.

The government recently also published a zero-emissions vehicles plan for the state, which Barr previously admitted would increase demand for power considerably as electrification progressed.

The batteries will reduce load on the electricity network and enable more ACT citizens to put solar PV on their roofs, the government statement noted, with the initial 250MW stream directly supporting the electricity network. In Stream 2, battery storage at government buildings in 14 sites will reduce their grid power consumption and the network of neighbourhood batteries will do the same for households in Stream 3.

Procurement processes for the first two streams are being readied for launch and are expected to be open for industry to take part from August.

The government had previously sought input from stakeholders, industry and experts last year on the Canberra Big Battery project, accepting views on possible locations, applications and other planning aspects.

Policymakers also worked with the Australian National University (ANU) to shape plans of how the batteries could work. Industry stakeholders were invited to take part in workshops held with ANU and according to the government, the high number of participants, from 42 organisations and their level of involvement indicated there is strong support for the programme.

Regular readers of Energy-Storage.news will recall that a team from ANU wrote an article for our quarterly technical journal PV Tech Power on the benefits of neighbourhood battery storage, as well as current technical and economic challenges they face, based on socio-techno-economic studies.

Commissioning is expected to take place across 2023-2024 for the ACT’s new fleet.

Two large-scale battery storage projects are already in construction in the ACT after their developers were awarded contracts in 2020 through a government renewable energy procurement.

Through the ACT’s fifth Renewables Reverse Auction, developers of two large-scale wind farms were awarded long-term contracts at under A$50/MWh (US$36/MWh) to build battery storage in the state.

French developer Neoen is building a 100MW/200MWh BESS along with its Goyder South renewables hub which includes wind, solar PV and batteries. The company, behind some of Australia’s biggest battery projects to date, signed another offtake agreement for the project with major energy generator-retailer AGL in April.

The other awarded project would see a 10MW/20MWh BESS built by developer GPG – a subsidiary of international renewables developer Naturgy – alongside the company’s new Berrybank Wind Farm.

Interestingly, neither firm’s wind farm is itself in the ACT. Goyder South is in South Australia and Berrybank is in Victoria, but through contracts with the ACT government will deliver power there and their battery systems deliver load management and grid services capabilities to the territory also.

Reconfiguring energy markets for the age of energy storage

In related news, today the Australian Renewable Energy Agency (ARENA) said it will help fund a study into the integration of energy storage into energy markets.

The national agency will fund A$495,000 of the total A$1.18 million expected cost of Monash University’s study, exploring alternative energy market designs that could encourage investment into energy storage and ensure Australia gets the energy storage it needs to transition from centralised fossil fuel generation to renewable and distributed energy.

Examples include formulating a spot market for inertia, an application energy storage can provide which ARENA has been keen to also explore from a technical level, helping to fund demonstration battery projects that provide synthetic inertia to the network through advanced inverter technologies.

“As traditional generation retires, we need storage to play a bigger role in firming up and balancing our electricity system,” ARENA CEO Darren Miller said, calling investment in everything from large-scale pumped hydro and BESS to small-scale batteries as “vital to continue Australia’s uptake of variable renewable energy into the grid”.

The ARENA funding will go to Monash Energy Institute’s Grid Innovation Hub at the university.

“For a successful transition to a low carbon energy future, energy markets must reflect the full value of all the services modern technology offers,” Grid Innovation Hub chairman Tony Marxsen said.

“Services from battery storage are not valued clearly at present, and this exciting research will reveal ways in which markets can better reflect their value to guide investment.”

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