Transmission lines in Texas, where ERCOT operates the grid. Image. Loadmaster (David R. Tribble).

Developer Available Power is focusing on the ‘distributed play’ of 9.9MW-or-less battery storage opportunities within the area of grid operator ERCOT in Texas, a senior executive told Energy-Storage.news.

The company was set up in 2020 by ex-Shell executives and has initially focused on the ERCOT market to “get really good in one space”, VP business development Alex Krass said, as well as ensure it gets projects on the ground before the market begins to saturate.

Battery storage projects in the ERCOT interconnection queue have reached the high double-digit gigawatts of capacity since the Inflation Reduction Act was passed. Most projects in the queue will likely not get built and Available Power has two main strategy pillars in place to ensure its projects, which it sells at notice-to-proceed (NTP) stage, see the light of day.

The first is focusing on smaller projects of 9.9MW while the second is bringing in an engineering, procurement and construction (EPC) partner Linxon to deliver on the project after it is sold to a buyer at NTP. The second pillar means it generally looks to sell to traditional financial institutions rather than those with existing EPC relationships.

Speaking to Energy-Storage.news while attending the Energy Storage Summit USA in Austin last month, Krass said the distributed play approach has a few advantages: “One, you can skip a part of the interconnection process with ERCOT (with projects under 10MW) so your time to market is quicker, which is fantastic. Secondly, the data on distribution substations and capacity and locations is harder to come by than for transmission data, so there are fewer eyes on those smaller, distributed scale opportunities.”

On the second pillar, Krass claimed that most developers selling at NTP – otherwise known as a ‘develop and flip’ model – are focusing primarily on getting projects ready to sell and then are “done with it”.

“I think we, on the other hand, have attention to detail around what’s going to be a good project over 20 years. With that, location becomes key, and who you partner with to bring them to COD (commercial operation date) becomes key. And so for us the Linxon relationship is fantastic because they’re really the ones who take the ball once it hits NTP and bring it to COD.”

“We sell the projects at NTP but with the Linxon relationship, we have the contracts, the equipment procured and everything in place, so it’s sort of a turnkey approach to the asset buyer who doesn’t need to bring any of that themselves. They just sign on the dotted line and provide the capital to bring it to fruition. So we’re looking more for the traditional financial capital partners versus someone who might have an EPC relationship or have an equipment relationship.”

“And while we don’t necessarily take an active role post-NTP, we have teed all of that up to bring it to COD, and believe we’re picking the right partners and have the right contracting mechanisms in place to ensure that the assets don’t just stay in the queue and drop out but actually get into operation.”

Available Power has 300MW/600MWh of near-term projects which it expects to reach NTP this year and COD in 2024, comprised of a 100MW/200MWh project near Austin and ten 9.9MW projects (the firm still does larger projects on an ‘opportunistic basis’, Krass said). Its total pipeline is over 1GW.

“Two hour duration is the sweet spot. A lot of the PUCTs (Public Utilities Commission of Texas) regulations coming in are incentivising the 2-hour-plus duration, but going to three or four you really get hammered on the Capex,” Krass added.

The question of whether or when the ERCOT market would saturate was a big talking point at the two-day event in Austin, and Energy-Storage.news will be publishing a more in-depth piece with multiple views on it in the coming weeks.

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Kathy Hochul, Governor of New York. Image: Governor Kathy Hochul official Flickr.

New York’s energy storage market is set for take-off, driven by strong policy goals, but it could come too late for the US state to meet a targeted 6GW of deployments by its 2030 deadline.  

Governor Kathy Hochul doubled New York’s 3GW target in early 2021, with the majority of the targeted amount expected to come from large-scale energy storage facilities, defined in state regulatory frameworks as ‘bulk’ storage of over 5MW. The 6GW figure corresponds to a forecasted 20% of New York’s peak load at the end of this decade.

Industry sources interviewed for a feature article in our quarterly journal PV Tech Power (vol.34) said that the state’s proactive and supportive approach to fostering an energy storage market will most likely succeed in driving New York to become a leading US state for storage deployments.

However, some expressed concern that it might come too late to meet that target in time. The target is meant to set New York on the right trajectory to attain its bigger goals of 100% emissions-free retail electricity by 2040 and carbon neutrality by 2050.

To that end, the state convened the New York Climate Action Council to oversee implementation of the Climate Leadership and Community Protection Act (CLCPA) legislation that set those goals. At the beginning of this year, the council’s Scoping Plan for implementation was complemented by the publication of Energy Storage Roadmap 2.0, itself a follow-up to a 2018 roadmap.

Put together by the New York State Energy Research and Development Authority (NYSERDA) and the state’s Department of Public Service, Roadmap 2.0 was warmly welcomed by industry, particularly the inclusion of proposals for state-contracted solicitations for bulk energy storage.

Vanessa Witte, energy storage analyst at Wood Mackenzie Power & Renewables, pointed out that the Roadmap’s proposed Index Storage Credit solicitations for bulk storage are unlikely to begin until 2024 at the earliest.

Even taking into account that roughly 1,500MW of that total target will be distributed energy storage – commercial and industrial (C&I), community-scale and residential – New York will be “cutting it fine” when it comes to getting the remaining amount of the 6GW total online by 2030, the analyst said.

Projects in New York tend to have long lead times, and New York ISO is not an easy service area to work in. At the same time, the Index Storage Credit, designed as a sort of top-up payment from the state to make up the revenues developers need versus what they can earn in the ISO wholesale market, may or may not provide the necessary financial incentive to drive the market forward.

Perhaps illustrative of these points is that regulators at the New York Public Service Commission (PSC) recently handed the state’s major utilities a three-year extension to an already-extended deadline for energy storage procurements handed down in the first 2018 Roadmap.

Developers bullish on long-term prospects in New York

Key Capture Energy CEO Jeff Bishop was bullish on New York’s prospects. The developer built the state’s first large-scale battery energy storage system (BESS) project in 2019, and Bishop said he is confident that New York will have a booming market by 2025.

Bishop conceded that this does throw some shade on the likelihood of achieving the full deployment target by the deadline, but said that ultimately, he is confident New York will achieve its climate goals.

Another developer spoken to for the PV Tech Power interview, Kelly Sarber of Strategic Management Group, was similarly bullish over the long-term outlook. New York’s overwhelming need for energy storage, coupled with its strong policy direction would dictate its success, but Sarber said she was “nervous” over whether the 6GW target could be reached on time, “based on where we’re at today”.

Read an extract of the feature article ‘Hunting the ‘missing money’ in New York’s energy storage market’, here on Energy-Storage.news, or subscribe to the PV Tech Power journal to read the full article, in Volume 34, published in February, here.  

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Masdar has further expanded its presence in the U.S. renewables market after closing the acquisition of a 50% stake in a combined solar and battery storage project from EDF Renewables North America. 

The Big Beau project, located in California, comprises a 128 MW AC photovoltaic solar plant and a 40 MW/160 MWh battery energy storage system. The project came online last year.

Masdar notes that this is one of eight projects that the company and EDF Renewables have agreed to jointly partner in, with a combined capacity of 1.6 GW.

“Big Beau and the other projects that we are operating with EDF Renewables are already making an active contribution to U.S. clean energy targets, highlighting the strength of the UAE-US relationship that the recent PACE announcement seeks to build on,” says Dr. Sultan Al Jaber, chairman of Masdar.

Masdar and EDF Renewables North America agreed in 2020 to jointly partner in the 1.6 GW portfolio, which includes three utility-scale wind projects in Nebraska and Texas totaling 815 MW and five solar projects in California totaling 689 MW – two of which include battery energy storage systems representing 75 MW. All of the projects are operational.

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Big Beau (pictured) is part of an eight-project portfolio of operational assets Masdar and EDF will partner on. Image: Masdar.

UAE state-owned renewable energy developer Masdar has acquired a 50% stake in a 128MW/160MWh solar-plus-storage project from EDF Renewables North America.

Located in California, the Big Beau project is part of an 8-project, 1.6GW partnership agreement between Masdar and EDF Renewables which includes five solar projects totalling 689MW and two utility-scale wind farms representing 815MW. All of the projects are operational.

EDF Renewables signed 15-year power purchase agreements (PPAs) for Big Beau in 2018, three years before it came online, with two California Community Choice Aggregators (CCAs), Monterey Bay Community Energy (MBCE) and Silicon Valley Clean Energy (SCVE), as reported by Energy-Storage.news at the time. Located in Kern County, its battery energy storage system (BESS) is 40MW/160MWh.

“EDF Renewables’ partnership with Masdar enjoys a successful history and today we celebrate another project to add to the growing portfolio,” said Tristan Grimbert, president and chief executive officer of EDF Renewables North America.  

“Decarbonisation of the energy sector will take the combined effort of developers, offtakers, and investors alike working in collaboration toward ambitious goals.”

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

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

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The battery storage containers at the solar PV plant in Büttel, Schleswig-Holstein. Image: Enerparc.

Developer Enerparc has turned on its first solar-plus-storage project in Germany awarded under 2020/21’s Innovation Tender.

The company announced the project in Büttel, Schleswig-Holstein was operational yesterday (12 April). A battery energy storage system (BESS) was installed at the 35MW Büttel solar park.

The BESS has a power rating of 12MW and an energy storage capacity of 8MWh, meaning a discharge duration of 40 minutes (0.66 hours). It was installed in six 40-foot containers and Enerparc claimed it is one of the largest batteries installed in combination with a ground-mounted solar plant in Germany.

“We are making it possible for the large-scale storage facility, together with the solar park, to be a central part for tomorrow’s energy markets. For institutional investors, too, such storage projects are the most effective way to become CO2-neutral. We are therefore also looking forward to soon being able to connect three further PV storage systems to the grid,” says Christoph Koeppen, CEO and chairman of the board of Enerparc.

The company concluded a power purchase agreement (PPA) for the offtake of the site with Axpo Germany, the local arm of the Swiss-based wind energy and energy trading firm, in April 2022. Though Enerparc’s own trading subsidiary Sunnic Lighthouse will be structuring the feed-in of the energy to the market.

It did not reveal the technology provider for the BESS portion of the project.

The project was awarded under the round of Germany’s Innovation Tender programme for co-located renewable and storage projects which was concluded in 2021. The Innovation Tender is running annually until 2028 and a total of 5,450MW of capacity is expected to be procured in that time, consultancy Clean Horizon recently told Energy-Storage.news.

The systems must be charged from the renewable asset and need to be able to provide aFRR (automatic Frequency Restoration Reserve) services although are not actually obliged to participate, analysts Naim El Chami and Vitor Gialdi Carvalho added. The Innovation Tender is similar to one being implemented in Spain.

Last month, a smaller project in Saxony came online, commissioned by developer and independent power producer (IPP) Qair Energy, the first from the Tender to come online in the state.

Germany’s utility-scale BESS market has started to pick up in the past year after a prolonged period of stagnancy, with a record amount installed last year. The main drivers are increased energy market volatility driving revenue opportunities in the wholesale trading and ancillary service markets, increased investor comfort with the asset class as well as the Innovation Tender.

The Tender awards a premium per kWh of energy discharged to the market from assets that combine two or more clean energy technologies.

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A 240kW/480kWh BESS system installed at the San Pasqual Band of Mission Indians tribal centre in California. Image: Industria Power.

The California Public Utilities Commission (CPUC) has approved the rules of its programme to offer US$200 million funding for microgrid projects in the service areas of the state’s investor-owned utilities (IOUs).

The Microgrid Incentive Programe (MIP) aims to accelerate the commercialisation of clean energy microgrids that can support disadvantaged vulnerable communities (DVC) impacted by grid outages, giving them a reliable supply of low carbon energy during wildfire seasons and other causes of disruptions.  

In a decision made earlier this month (6 April), the regulatory body created the MIP’s rules while also directing the three IOUs, Pacific Gas & Electric (PG&E), Southern California Edison (SCE) and San Diego Gas & Electric (SDG&E) to conduct outreach and consultation activities with communities that bid for a pot of funding.

An individual project can get up to US$15 million, with the utilities sharing the pot based on their relative size and needs: SCE gets the biggest share, at US$83.3 million, PG&E US$79.2 million and SDG&E’s share is US$17.5 million.

Rules voted on and approved by the CPUC govern the operation and market participation of the self-contained microgrids, which based on other recent microgrid projects in California are likely to include solar PV and battery energy storage system (BESS) technology, although many microgrids also feature some form of thermal generation as backup.

However, that backup or standby generation portion of the microgrids will not count as project resources under the MIP, while project resources that do count will be required to serve at least 24 hours of load to the defined microgrid boundary area when in Island Mode i.e., disconnected and operating independently of the utility grid.

Projects must be community microgrids for eligible DVCs, and be a critical facility, such as a hospital, or provide important community resilience services, such as an emergency shelter.

Risks they face could include being in High Fire Threat districts, or areas that experience public safety power shutoffs (PSPS), where utilities disconnect distribution feeders to reduce fire risk and often leave homes or whole communities without power for days, earthquake-prone areas, and areas with historically poor records of maintaining reliable electricity supply.

“The Microgrid Incentive Program will provide valuable support to disadvantaged and vulnerable communities towards ensuring they are not left behind in the broader statewide resiliency effort. These communities tend to be located in more electrically isolated areas with greater distances to essential services, experience more outages, and have less accessibility to entities with backup power,” CPUC commissioner Genevieve Shiroma said.

Commissioner Shiroma added that education and outreach to ensure DVCs are able to “meaningfully participate” are also important components of the programme.

SDG&E moves to harden grid against wildfires for tribal areas

In related news, IOU San Diego Gas & Electric last week said it had applied to the US Department of Energy (DOE) for up to US$100 million in federal funds to support its efforts to mitigate wildfire impacts.

SDG&E applied to the DOE’s Grid Resilience and Innovation Partnerships Grant scheme, which was created by the Infrastructure Investment and Jobs Act a.k.a., the Bipartisan Infrastructure Law, the 2021 predecessor to the Inflation Reduction Act (IRA).

If approved, SDG&E would match the DOE’s funding, which it said would be used for wildfire hardening efforts on and around tribal areas in the utility’s service territory.

The money would be spent on upgrading about 70 miles of power lines that serve 10 tribal areas, including putting a large portion underground.

In addition to seeking federal and state funds for specific climate adaptation measures, SDG&E’s strategy to lower costs for its customers includes maximising the available federal tax credits unlocked by the IRA for battery storage and microgrid projects, which it will refund to its customers, the utility said.

A few weeks ago, a solar-plus-storage microgrid with 6MWh of BESS was announced for the Soboba Band of Luiseño Indians in California’s Riverside County, by Scale Microgrids. The Native American tribe, as a non-tax paying entity, along with rural electric cooperatives, states and tax-exempt organisations, can avail of the Inflation Reduction Act’s investment tax credits (ITC) scheme through a Direct Pay option, sidestepping the complex and expensive tax equity financing structures and transactions that other projects require to get the ITC.  

That was one of a number of tribal microgrids in the state Energy-Storage.news has reported on, with others including a 60MWh project featuring long-duration energy storage (LDES) battery technologies from flow battery provider Invinity and zinc-air battery company Eos.

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The team from Cheesecake Energy, whose solution a combination of thermal and compressed air energy storage. Image: Cheesecake Energy.

The UK Department for Energy Security and Net Zero (DESNZ) is providing £30 million (US$37.5 million) in grants for long-duration energy storage (LDES) projects from Synchrostor, Invinity Energy Systems and Cheesecake Energy.

The three projects are receiving roughly equal portions of the funding for their LDES projects which use a range of technologies to store electricity with multi-hour discharge durations.

It is the latest round of a £69 million funding programme for LDES technologies in the UK, for which smaller amounts were provided in February last year with another £30 million handed out to five projects in November.

“Storing energy for longer periods is vital to build a robust and secure energy system and ensure that renewable energy is used efficiently. Fortunately the UK has a wealth of pioneering businesses that are making their mark on this industry,” said the Minister for Energy Security and Net Zero Graham Stuart said.

“Today we’re backing three UK businesses to make their projects a reality, which will go on to play a role in our country’s energy security.”

As reported by Energy-Storage.news yesterday, Invinity is receiving £11 million for a four-hour 30MWh vanadium redox flow battery (VRFB) project, which will be the largest to ever use the technology in the UK and the largest the firm has deployed to-date.

Edinburgh-based Synchrostor is getting £9.4 million to build a pumped thermal energy storage (PTES) demonstration project with 1MW of power and 10MWh of energy storage, 10 hours of duration.

The third, Cheesecake Energy, will receive the same amount to test its FlexiTanker technology and then install pilot units at two sites as part of a microgrid project in Colchester. The company’s technology uses a combination of thermal and compressed air energy storage (CAES) with a reversible air compression/expansion train to charge and discharge energy.

The funding is part of the £1 billion Net Zero Innovation Portfolio from the Department for Business, Energy and Industrial Strategy (BEIS), the precursor to recently-formed DESNZ.

The past few years has seen the UK become one of the most developed markets for short-duration, lithium-ion energy storage, and industry stakeholders are now looking to set up the right mechanisms and incentives to kickstart the LDES sector.

DESNZ is looking to bring in LDES-specific policy sometime next year to help incentivise the long-term investment into projects, according to panellists at the Energy Storage Summit in London in February. Developers with pumped hydro energy storage (PHES) projects, the oldest LDES technology, say energy market rules need to be changed to make their projects viable.

However, in the US equivalent event a month later, a grid operator from New York warned against moving too fast with less proven LDES technologies, saying the grid cannot afford any ‘hiccups’ along the way.

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The ACT government posted this picture, described as a ‘generic artist impression,’ although regular readers might note the similarity of the units’ design to those of Fluence’s Gridstack and Cube products. Fluence is also working with Eku on its 400MWh project with Shell Energy. Image: ACT Government

The government of the Australian Capital Territory (ACT) has partnered with developer Eku Energy to deliver its flagship Big Canberra Battery project.

The government announced this morning that Eku Energy will develop, build and operate the battery energy storage system (BESS), which at 250MW/500MWh would be one of the largest of its kind in the country.

The formation of the partnership was described by ACT chief minister and minister for climate action Andrew Barr as a “significant step in the delivery of the Big Canberra Battery ecosystem”.

First announced as part of the state’s 2020-2021 budget with AU$100 million (US$67 million) in funding pledged towards it, the government ran a procurement process for the grid-connected BESS which began in mid-2022.

Ahead of opening that solicitation, the government, together with the Australian National University’s Battery Storage and Grid Integration Program (BSGIP) and input from industry stakeholders, held a co-design workshop. Some of the themes that emerged included a recognition that while transmission-connected BESS can be a valuable asset, finding financing remains challenging.

Winning bidder Eku Energy is an energy storage development platform that was launched through the Macquaire Asset Management-owned Green Investment Group (GIG) in late 2022, taking over GIG’s development pipeline.

Government, developer to share NEM revenues

The expected total cost of the battery project was cited today as between AU$300 million and AU$400 million.

The BESS will store energy generated during times of surplus renewable generation and off-peak times, helping to manage Canberra’s peak load by injecting power back to the grid when it is needed.

It will participate in the National Electricity Market (NEM) and under the terms of the government’s agreement with the developer, revenues it earns from opportunities including the NEM’s frequency control ancillary services (FCAS) markets will be shared between the pair.

In addition to the revenue-sharing, Eku Energy will receive fixed payments on a quarterly basis from the ACT for 15 years, while the BESS will also provide system stability and security services, helping to back up electricity supply in the region. Financial terms of the revenue share and fixed payments were not mentioned in Australian Capital Territory government releases.

“When I first announced the Big Canberra Battery project we had three objectives in mind; grow jobs in our renewable energy sector, create a meaningful revenue stream for the Territory and improve energy security for Canberrans – this contract delivers on all three of those objectives,” chief minister Andrew Barr said.

“As a combined network, this battery ecosystem can address network constraints, enable more Canberrans to reap solar benefits and present the opportunity for the Territory to reduce costs and generate revenue.”

The half-gigawatt-hour BESS is one component of a three-stage plan the Canberra Big Battery project comprises – the further two steps will be the deployment of distributed energy storage at government buildings and the installation of community-level ‘neighbourhood’ battery systems for residential areas.

The biggest large-scale battery asset currently under construction in the Australian Capital Territory is the 100MW/200MWh Capital Battery. Neoen, developer of that project, reached financial close on it in October 2022, due in part to a AU$35.5 million funding commitment from Australia’s national Clean Energy Finance Corporation.

Neoen’s Capital Battery is scheduled to go into operation in the first half of this year. The 250MW large-scale portion of the Canberra Big Battery project meanwhile is expected to begin construction in late 2024 and enter commercial operation during the following year.

It’s the second big Australian BESS project announcement in the past few weeks for Eku Energy covered by Energy-Storage.news: Macquarie’s GIG and Shell Energy said in late March that they are working together on a 200MW/400MWh project in the state of Victoria, with GIG’s equity stake in the project set to transfer to the developer.

Energy-Storage.news’ publisher Solar Media will host the 1st Energy Storage Summit Asia, 11-12 July 2023 in Singapore. The event will help give clarity on this nascent, yet quickly growing market, bringing together a community of credible independent generators, policymakers, banks, funds, off-takers and technology providers. For more information, go to the website.

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Laura Landreaux

Lightsource bp has closed on a $327 million financing package and started construction on the 313 MW DC Driver Solar project, located near Osceola in Mississippi County, Ark.

Lightsource bp completed development, permitted and financed the project and will construct the facility under a build-transfer agreement with Entergy Arkansas. Upon completion, Driver Solar will be the largest solar farm in Entergy Arkansas’ portfolio, as well as the largest in Arkansas.

Construction has started, with commercial operation expected by late 2024. Moss Construction was selected by Lightsource bp as their EPC contractor for the project and will install more than 650,000 solar panels manufactured by Arizona-based First Solar and solar trackers from New Mexico-based Array Technologies.

Debt for the Driver Solar project was provided by HSBC Bank, BNP Paribas, Societe Generale and Sumitomo Mitsui Banking Corp., with the balance of equity requirements supported by Lightsource bp.

Once constructed, ownership of the project will transfer to Entergy Arkansas under the build-transfer agreement.

“One of our key commitments to customers is to help them find economic solutions to meet their sustainability goals,” says Laura Landreaux, president and CEO of Entergy Arkansas. “Driver Solar plays a big role in providing savings to all customers and supporting businesses like U. S. Steel as they continue to advance their own clean energy future. These partnerships are helping to drive incredible growth in our state and will benefit our communities for decades to come.”

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Mario Azar

BAES Infrastructure and Black & Veatch today have completed the construction of two utility-scale solar projects – Crown and Sol – in central Texas’ Falls County.

Commercial operations are expected to begin this month with a combined capacity of 270 MW DC.

Both projects have executed a power purchase agreement with LyondellBasell to offtake 80% of the output.

The construction of these projects involved the installation of more than 600,000 photovoltaic modules and over 650,000 man-hours worked, with Black & Veatch performing the engineering, procurement, and construction services.

“In addition to underscoring BAES Infrastructure’s forward thinking in the energy transition, this project demonstrates our commitment to leveraging our deep expertise in clean energy in ways that achieve our clients’ decarbonization goals,” says Black & Veatch Chairman and CEO Mario Azar.

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