Potential for ‘significant effect’ on the surrounding environment
Projects requiring discretionary approvals from government agencies, such as land amendments and use permits, which have the potential to cause an impact on the surrounding environment are subject to the CEQA review process.
The lead agency will first prepare an Initial Study (IS) to determine whether the new project could have a “significant effect” on the environment, defined by CEQA Section 15382 as “a substantial, or potentially substantial, adverse change in any of the physical conditions within the area affected by the project including land, air, water, minerals, flora, fauna, ambient noise, and objects of historic or aesthetic significance.”
If the lead agency decides the project won’t have a significant effect on the environment, it will publish a Notice of Determination (ND) approving construction of the project.
If it is decided that the project could have a significant effect on its surroundings, the lead agency will produce an Environmental Impact Report (EIR). This document typically takes over a year to produce and outlines the potential effects of the project, measures to mitigate these impacts, and analysis of project alternatives.
Expedited CEQA review process 
Instead of a potentially lengthy environmental review process, a lead agency and developer can work together to reduce the environmental impacts of a project to a less than significant level.
The lead agency will outline these revisions agreed upon by the developer in a Mitigated Negative Declaration (MND), which is posted online alongside the IS that is then subject to a public comment period.
If the lead agency doesn’t receive any comments containing evidence of the project having a potentially significant impact, it will issue an ND approving construction of the project, which was filed by the City of Carson for Arevon’s Avocet project on August 6 2024.
The City of Carson concluded the project would have a ‘less than significant impact’ on the surrounding area, with mitigation measures in place.
The project will be located between an industrial gas facility from Air Products and a petroleum coke handling facility from Marathon, as shown in the render at the top of this article.
200MW/800MWh connecting to the CAISO grid 
The IS and MND report describe the Avocet Energy Storage project as a 200MW/800MWh standalone BESS located at 23320 Alameda Street in the City of Carson, California.
Interconnection to the California Independent System Operator (CAISO) grid will be via Southern California Edison’s (SCE’s) Hinson 230kV substation through a single gen-tie line.
Arevon has already secured an interconnection agreement for the project with CAISO and SCE that was processed as part of the California system operator’s Cluster 12 process (queue no. 1608).
The IS and MND report outlining further project information can be found here, with mitigation measures found on page 151-160: Chapter 4 – Mitigation Monitoring and Reporting Program.
Battery supply agreement and power offtaker secured 
The Avocet project is one of Arevon’s most developed pipeline projects, with the developer having also secured a battery supply agreement with Tesla along with a power offtake agreement with California community choice aggregator (CCA) San Diego Community Power (SDCP).
Under the terms of a 15-year energy storage services agreement (ESSA), SDCP will pay Arevon a fixed price for capacity—adjusted for availability and verified capacity—commencing 15 April 2026.
The agreement was unanimously approved by SDCP’s Board of Directors at a regular meeting held on 16 November 2023. The agenda packet containing further details on the agreement can be found here.
Arevon also disclosed in a recent press release that Tesla would be supplying its Megapacks for the project.
Extensive California BESS portfolio 
Arevon has an extensive BESS portfolio in California at various stages of development, including its 200MW/800MWh Condor Storage facility located in San Bernardino County that was recently cleared for commercial operations, as reported by Energy.Storage-News last week.
It also includes a larger 300MW/1,200MWh BESS located in San Diego County known as the Nighthawk Storage facility, which is under construction according to the developer’s website.
Arevon has secured a 15-year resource adequacy agreement for power offtake from the project with California utility Pacific Gas & Electric (PG&E).

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The two BESS projects will be the largest in TEP’s portfolio and among the largest in the state, and will help TEP manage supply and demand in the state. They will be built alongside each other next to a TEP substation near Tucson, the capital of Arizona.
“Our new Roadrunner Reserve II system will help us make the most of intermittent resources, especially during the summer when usage is highest and customers are counting on us the most,” said Susan Gray, TEP’s President and CEO. “We need additional energy storage as part of a diverse energy portfolio to support service reliability.”
Both projects will be built by engineering, procurement and construction (EPC) firm DEPCOM using lithium iron phosphate-based (LFP) BESS units. DEPCOM’s VP of energy storage business development discussed its approach to building Roadrunner Reserve in an interview with Energy-Storage.news recently (Premium access), including combining EPC with operations and maintenance (O&M).
TEP, a utility operating solely in Arizona, has 50MW of operational BESS today, including the 30MW unit at the Wilmot Energy System, pictured above.
The Roadrunner Reserve projects, which will quintuple that capacity, are in line with the utility’s 2023 Integrated Resource Plan (IRP), part of its roadmap to achieving net zero direct greenhouse gas (GHG) emissions by 2050.
It will also procure the power from the Winchester Solar project, which combines 80MW of solar and an 80MW BESS, from developer-operator Torch Clean Energy when it comes online in 2027.
Roadrunner Reserve II was selected through the utility’s 2024 all-source request for proposals (ASRFP) process, which sought 825MW of ‘firm capacity’ alongside 625MW of renewables. TEP and sister firm UniSource Energy Services are evaluating other proposals submitted for the ASRFP.
Utilities are driving the grid-scale BESS market in Arizona, either by building the projects themselves, like TEP, or procuring their power under long-term tolling agreements. Salt River Project (SRP) and Arizona Public Service (APS) recently secured power via tolls from 1,000MWh and 600MWh BESS projects, respectively. California-based utilities are doing the same for projects across the state line, including PG&E.

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Colbun submitted its environmental impact study (EIS) in June 2024, but earlier this week (12 August), the Environmental Assessment Service (SEA) for Antofagasta issued an ‘early termination notice’.
Its notice said information was missing, which would not allow the assessment to proceed in the appropriate manner. The missing information, the service said, meant it couldn’t rule out whether it would have a significant impact on local flora and fauna as well as human populations that are part of the indigenous peoples of Paposo.
One specific issue was the lack of consideration for how the construction of a cable car related to the project would affect wildlife on the cliff face.
It also omitted to mention that two groups of indigenous communities belonging to the Chango People live less than 500m from the site.
Of the eight communities that were addressed in Colbun’s EIS, the resolution found that three said the project would not affect them while five said the construction would limit their movement and obstruct their ability to collect coastal plants for medicinal uses and graze cattle.
In a Spanish-language press release published on BNAmericas two days after the early termination notice, Colbun said it disagreed with the reasons given by the Antofagasta SEA for doing so.
The Paposo project would entail US$1.4 billion of investment. The overall energy storage capacity of the project hasn’t been revealed, but PHES technology would typically have a discharge duration of 6-20 hours, meaning anywhere from 4.8GWh to 16GWh in this case.
Colbun is also deploying battery energy storage systems (BESS) in Chile, with the first of some 800MW coming online in late 2022.
In a related development, Colbun entered into a memorandum of understanding (MOU) with high-density PHES technology company RheEnergise last year to explore the potential of a smaller system in Chile using RheEnergise’s technology.
You can read the Spanish-language EIA documents from the Chilean government pertaining to the Paposo project here. See a Spanish-language video render of the project from Colbun on Youtube below.

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Energy-Storage.news’ publisher Solar Media will host the 3rd annual Energy Storage Summit Latin America in Santiago, Chile, 15-16 October 2024. This year’s event brings together Latin America’s leading investors, policymakers, developers, utilities, network operators, EPCs and more all in one place to discuss the landscape of energy storage in the region. Visit the official site for more info.

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GridBeyond’s solar, storage and EV regional director Stace Tzamtzidis and Balancia Consulting strategy consultant Peter Newland were in conversation with Energy-Storage.news editor Andy Colthorpe.
Tzamtzidis discussed building a business case for battery storage from various angles. Those included technical performance and reliability, evolving market dynamics and volatility, regulatory and environmental considerations, market access, forecasting and modelling and operational flexibility.
The firm’s solutions include battery storage design software, a forecaster application, a bid optimiser application and a machine learning price forecaster. Tzamtzidis went through each of these and how they can be applied to battery storage to maximise performance.
That was preceded by a data-driven look at the market across utility-scale, commercial & industrial (C&I) and residential segments in Australia from Peter Newland, strategy consultant, Balancia Consulting.
Speakers:

Stace Tzamtzidis, solar, storage and EV regional director, GridBeyond
Peter Newland, strategy consultant, Balancia Consulting

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You can also register to watch the webinar from the on-demand section of the site, which will also enable you to access the presentation slide deck, and where you can find all our other Energy-Storage.news webinars.

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Along with its fellow IOUs, Southern California Edison (SoCal Edison) and San Diego Gas & Electric (SDG&E), PG&E’s adoption of battery energy storage system (BESS) technology has been a major driver for California’s leading position among US states as an energy storage market over the past few years.
Long-time readers of Energy-Storage.news over the past 10 years will recall that as California’s AB2514 legislation put in place a mandate for the IOUs to procure 1.325GW of energy storage between them by 2020, an outsized portion of our reporting was driven by activity in the California Independent System Operator (CAISO) bulk power system.
That policy target took a while from its passing in 2010 into an actionable plan in the latter part of the decade but was quickly overshot as the needs of the CAISO grid converged with the falling costs of batteries.
Today, CAISO has more than 10GW of storage resources connected to it, and while other states are starting to catch up, most notably Texas with the Electric Reliability Council of Texas (ERCOT) service area, California remains a focal point for the US utility-scale BESS market.
Quick history
Over the past five years since deployment began at scale, PG&E has brought online more than 2,300MW of energy storage resources. More than a gigawatt will be added to that over the next year and a half to the end of 2025, PG&E’s Paul Doherty says, of a total 4.2GW of storage under contract.
“You can really see how these systems have proliferated and how state policy has really directed that in support of grid resiliency, the shift to renewables and the capability to load shift and buffer our energy for the evening peaks,” Doherty says.
Nearly all of the BESS resources in PG&E’s service area are third party-owned. PG&E has just one large-scale BESS in its ownership, the 182.5MW/730MWh Elkhorn project at the site of the former Moss Landing gas power plant, not to be confused with the slightly more famous 3GWh Moss Landing Energy Storage Facility at the same site owned by Vistra Energy with PG&E as its offtaker.     
Doherty points out that energy storage has been a “major” part of the utility’s resource mix since 1984 when its 1,212MW Helms pumped hydro energy storage (PHES) plant opened.
“We started to deploy actual battery energy storage systems in around 2012-2013 with a technology that was sodium-sulfur,” Doherty says.
That would be the sodium-sulfur (NAS) battery technology from Japan’s NGK Insulators. Two projects, one 2MW and the other 4MW, were deployed at a customer site and a substation through a customer-funded R&D programme called Electric Program Investment Charge (EPIC).
“Then in 2016, PG&E deployed our first lithium-ion energy storage system—that was Tesla Powerpack technology—at a substation about 50 miles north of Sacramento, to test out some real-world use cases.”
Those included testing the integration of BESS into the utility’s distribution grid system and how it could participate in CAISO markets. The company’s next trial project assessed how battery storage could be used to help manage peak summer loads on the PG&E network.
A project currently underway in mountainous Humboldt County attests to the direct way those trials translated into broader deployments.
One of the longest distribution lines in PG&E’s service area runs through Humboldt. By deploying a large-scale BESS to solve capacity and voltage issues, the utility is saving millions of dollars versus a traditional poles and wires upgrade.
Doherty calls it a “US$10 million solution versus a US$100 million solution,” along the 50-mile distribution line.
Wildfires and resiliency
California is among the US states with the most ambitious decarbonisation policy targets, aiming to reduce emissions to 40% below 1990 levels by 2030 and net zero by 2045. That’s a major driver for renewable energy deployment and, therefore, energy storage.
Improving the resiliency of electricity supplies, and the stability of the grid is also a major concern for utilities and the regulatory California Public Utilities Commission (CPUC) that oversees them.
The project in Humboldt County also speaks to that driver for PG&E to make investments in battery storage.   
California’s vicious wildfires imperil lives, and they imperil the electricity grid, and in the past, these threats have become intertwined with tragic consequences.
PG&E has been found liable for historic wildfires that started because the utility did not take sufficient measures to mitigate the risk of its equipment causing or exacerbating fire events.
Most recently, the CPUC approved a US$45 million settlement between PG&E and the regulator’s Safety and Enforcement Division (SED) in January this year, for the utility’s involvement in the 2021 Dixie fire, which burned across nearly a million acres before it could be contained.
Due to wildfires, the three IOUs now enact Public Safety Power Shutoff (PSPS) events in high-risk areas. These events essentially cut off power by de-energising distribution lines. They can last an indeterminate period of several days or even weeks.
In some of these areas, PG&E has built around a dozen ‘pre-installed interconnection hubs,’ essentially distribution-level microgrids, in downtown areas that are safe to energise, “even though the broader grid surrounding them is within the high-fire-risk areas,” Doherty says.
“We can bring in diesel generators and provide power to an area where there are community resources, like banks and gas stations and grocery stores, emergency services or other essential downtown places where people could go and still have that continuity of society where the rest of the town have their power shut down.”
PG&E is exploring greening those microgrids, trialling battery storage alongside mainspring linear generators that run on different types of gas.
It is also, with gravity energy storage startup-turned BESS integrator Energy Vault, building a large-scale system that combines lithium-ion (Li-ion) batteries with a green hydrogen electrolyser.
At 290MWh capacity, it will be a long-duration energy storage (LDES) system capable of powering the downtown and surrounding area of Calistoga for up to 48 hours during a PSPS event. The system is due to come online before the end of this year.

Hydrogen tank on its way to the PG&E-Energy Vault Calistoga microgrid project. Image: Energy Vault.
Incidentally, on the subject of new technologies, PG&E is also among the US utilities set to pilot the iron-air battery developed by Form Energy. The tech startup claims it will provide multiple days of low-cost electricity storage. Form is leading that project, Doherty says, with CEC grant funding.
“As a part of our continued integration of additional renewable resources, and maintaining resilience to the grid, we are piloting and testing the use of cleaner generation solutions for battery storage and for our microgrid sites,” he says.
“We’re really expanding the pool of our contracted technologies, piloting those viable non-diesel technologies in particular, and exploring opportunities to build a portfolio of non-fossil solutions for the longer term.”
Addressing ‘so many different grid focus areas and issues’ with energy storage
The utility therefore is procuring different scales and configurations of energy storage assets across its portfolio.
In addition to large-scale systems that operate in the CAISO market and help the utility meet its resource adequacy (RA) requirements and its microgrids, Doherty claims PG&E is also taking seriously the potential of customer-sited storage resources.
Energy storage is enabling the utility to “address so many different grid focus areas and issues,” including residential and commercial systems which can participate in demand response programmes, Doherty says.
“Californians have for a long time been early adopters of clean energy technologies, whether it’s EVs, whether it’s batteries or solar.”
Leveraging vehicle-to-grid (V2G) technologies from EVs equipped with bidirectional charging capabilities is “such an opportunity,” with PG&E expecting to support charging for three million EVs by 2030.
“We’re at more than 600,000 EVs connected to our grid today. That’s a really outsized number compared to the rest of the country and other utilities. We envision a future where two million of those three million EVs are participating in some sort of managed charging, or some sort of vehicle-to-grid applications.”
More broadly speaking, there are virtual power plant (VPP) programmes with Tesla and Sunrun that see home battery storage systems aggregated to provide demand response through PG&E’s Emergency Load Relief Program (ELRP).
It is still early days for VPPs, not least of all because ELRP only allows for batteries to perform demand response applications during peaks which occur during heat waves, but nonetheless they have been a huge success.
There is a “huge ecosystem” of battery storage applications across California, as Doherty says. Nowhere is this more evident than on the CAISO website, which features a portal where you can see how much energy storage is contributing to the ISO’s resource mix.
“It’s an exciting moment when you think about all that, and you think about the different grid architectures and the capabilities for batteries to support both on the utility-scale, but also the customer scale,” Paul Doherty says.

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Firm Power, a BESS developer, has 21 grid-scale projects currently in development across Australia, comprising 2.3GW of capacity in New South Wales, 2.7GW in Queensland, 500MW in Western Australia and 300MW in Victoria and South Australia, all in all totalling 5.8GW.
Terrain Solar, a large-scale solar PV developer, has six projects in development with a cumulative capacity of 1.8GW. Of this figure, 1.1GW is based in Queensland, 500MW in New South Wales, 100MW in Western Australia, and under 100MW in South Australia.
The acquisition will be completed in an A$250 million (US$165.5 million) deal, funded from cash on AGL’s balance sheet. The deal is subject to customary conditions precedent, with completion anticipated in 2024.
Managing director and CEO of AGL Energy, Damien Nicks, said the acquisitions will accelerate the company’s development pipeline, which recently hit 6.2GW of capacity. It will also ensure the company is “best placed to take advantage of market conditions and prioritise developments that generate the best long-term value and be a leader in the energy transition”.
“AGL’s development pipeline includes several mid-sized BESS projects, ranging between 200-500MW and two-to-eight-hours [of] storage duration. We believe this high-quality development pipeline presents strong optionality for AGL, focusing on firming capacity, which will be required to firm new renewable energy generation for our customer base and portfolio as thermal baseload generation exits the National Electricity Market (NEM),” Nicks said.
This article first appeared on our sister site PV Tech.

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The government is increasing the threshold for what constitutes a National Significant Infrastructure Project (NSIP) for solar and onshore wind to 100MW and 150MW, respectively, from 50MW currently.
“Now, the UK battery storage sector stands on the cusp of a transformative era, fuelled by the Labour government’s ambitious commitment to establishing the nation as a clean energy superpower by 2030,” Brooks said, as his company unveiled a 40-project pipeline.
Brooks also called for more to be done within planning reform, as well as the electricity market, to provide specific support for the deployment of BESS technology, which he said still faces several barriers.
Read Brooks’ guest blog in full here.

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The deal is significantly different to Gresham House and Octopus Energy’s recent shorter, two-year toll deal for a 568MW portfolio of 14 already-operational BESS projects. That was the first seen in the UK, while tolling agreements are common in the US and Australia.
In response to questions from Energy-Storage.news, BW ESS’s Roberto Jimenez, executive director for BW ESS, indicated that the seven-year BESS toll entails a fixed price for the entirety of it (presumably inflation-adjusted). He wouldn’t disclose how the figure was arrived at, considering the volatility of BESS revenues in the last three years, which makes seven years a very long time to agree a price on.
Jimenez pointed out that tolls are common in other infrastructure and related classes like solar and wind and said the deal is really about optimising the project’s financing. The project is also longer in duration—at 3.3 hours—than most other UK projects being built, and this played into the deal.
“Bramley agreed on a seven-year tenor because it optimised the project’s economic returns and is a tenor that is conducive for attractive long-term financing,” he said.
“The 3.3-hour duration of the Bramley BESS asset makes it attractive to traders/optimisers that expect to capture more value from arbitrages in the wholesale energy market. The choice of duration was also driven by technical considerations and a 15-year capacity market contract for 2.5 hours duration, which was secured for the project earlier this year.”
“There seems to be an increasing preference for longer duration assets, especially for longer-term deals, where assets need to be resilient in an evolving market.”
Market intelligence provider Modo Energy estimated in an analysis article that the toll price is most likely in the range of £70,000-80,000 (US$90,000-102,000) per MW. This was based on an estimated capex for the Bramley BESS project of £900,000 per MW and the revenues needed to achieve an unlevered IRR of 10% over the project’s lifetime (£108,000 per MW), balanced with the likely ‘spread’ or profit that Shell would want to make on trading the BESS.
Wider move to BESS toll deals could leave smaller optimisers at a disadvantage
Deals like Gresham House’s and BW ESS’ are part of a wider move in the UK and European industry to structures that enable financing for the largest-scale projects.
BW ESS said that tolls will be one of various structures that asset owners will go for, but that uncontracted merchant models and hybrid structures which leave some merchant exposure will have a place.
He indicated that for its two other large UK projects, Hams Hall at 400MW and Berkswell at 200MW, the company may retain some merchant exposure with those projects still uncontracted. Both are expected to come online in 2026.
Energy-Storage.news then asked Jimenez if there was room for smaller optimisation providers to provide tolls or whether it would be dominated by big utilities and energy companies, as the two large announced deals have been (Octopus and Shell).
“Optimisers could also offer toll agreements, but those may be perceived as less attractive as they do not provide the same ability to optimise a project’s cost of capital,” he said.
Others speaking off-record have put it more bluntly. A finance source recently said during a panel discussion that the best-performing BESS optimisers tend to be small, startup-type outfits that outperform large utilities and energy companies.
But asset-owners that contract with those larger entities are ‘effectively renting their balance sheet’ to get financing, they said. In other words, banks will be more willing to lend to a project optimised by a big entity with a deep balance sheet, even if its record of BESS returns is worse, because of the lower risk compared to an asset-light startup. The longer the length of the agreement, the more the risk element will come into the equation.

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The project is being developed by Terra Solar Philippines, Inc. (TSPI), which is co-owned by independent power producer (IPP) SP New Energy Corporation (SPNEC) and utility Manila Electric Company (Meralco). The green lane certificate was received by Emmanuel Rubio, president and CEO of Meralco subsidiary MGen.
Terra Solar would span 3,500 hectares of land in the Bulacan and Nueva Ecija provinces and would cost PHP185 billion (US$3.2 billion). The project would be the largest in the world by capacity, in terms of solar, BESS and both technologies combined.
The BOI is the Philippines government’s lead industry development and investment promotion agency and a green lane certificate is designed to speed up the process of acquiring permits and licenses for strategic investments that align with the country’s national development plans.
It is hoped the certificate could help Terra Solar reach commercial operations for its first phase—for which the size has not been disclosed—by February 2026 and the second phase the year after.
The project has also received a Certificate of Energy Project of National Significance from the Department of Energy, more of a formality as any project above US$59 million in investment value receives this certificate automatically.
The Terra Solar project appears to be the same one that was proposed by billionaire Enrique K Razon’s Prime Infrastructure Holdings two years ago, covered by Energy-Storage.news at the time. Prima Infra along with IPP Solar Philippines set up a joint venture entity called Terra Solar to develop the project. At the time, it was said the project would provide power to Meralco under a power purchase agreement (PPA) rather than being directly owned by the company, which appears to have changed.
The Philippines was a hot topic of discussion at Solar Media’s Energy Storage Summit Asia 2024 last month—see our write-up of one of its panels discussing the country’s energy storage market here (Premium access).
The BOI’s green lane certificate for Terra Solar coincided with several other renewable investment approvals from the department, including PHP263 million worth of solar rooftop projects, the PHP297 billion Pakil Pumped Storage Hydroelectric Power Project and the PHP114.7 billion Guimaras Strait Offshore Wind Power Projects.

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The majority of the projects are at ‘advanced stages’ of development and the first are expected to reach ready-to-build (RTB) status in the first half of 2025. The power and capacity imply an average duration of around four hours per project.
It builds on SUSI and BIWO’s partnership in Chile, with SUSI investing in two solar-plus-storage projects developed by BIWO in November last year, which will feature 232MWp of solar PV and up to 900MWh of energy storage capacity.
Energy-Storage.news has asked SUSI to confirm whether the new portfolio includes or is in addition to these and will update this article if an answer is received. The announcement implied, though didn’t explicitly say, that the 860MW portfolio is made up of standalone projects, implying they may all be new projects.
The energy storage market in Chile is being driven by its high – and growing – penetration of solar PV and the grid congestion that comes with that, considering the most regions with the highest irradiance are in the north while demand centres are in the south.
BESS are either being deployed as independent projects that help the grid operator manage congestion, trade energy and provide capacity market services, or alongside solar PV to support renewable power purchase agreements (PPAs).
Standalone energy storage’s participation in the electricity market was enabled in late 2022 while its capacity market payments were recently finalised too, paving the way for project owners to build a business case.
SUSI is also active in the energy storage markets in the US, with projects in ERCOT, and Italy.

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