The battery storage deployment blueprint
In case you missed last week’s piece that covered the utility-scale energy storage landscape in the U.S. in broad strokes, here’s what you need to know to pick up the thread:
- Historically, technologies like pumped hydro have dominated large-scale energy storage.
- Advances in battery technology and manufacturing have made battery energy storage the largest growth vector in energy storage in 2023.
- Dominance of batteries will continue, though new chemistries, and perhaps new technologies, will come to the fore.
By way of introduction to today’s newsletter, some of the first battery energy storage systems were deployed in California of necessity.
In 2015, natural gas leaks from a gas storage facility in Aliso Canyon, California, forced Southern California Edison to close the facility temporarily. This reduced gas availability for power plants, threatening to strain the grid during the winter.
The public utility commission forced SoCal Edison to install 20 MW (80 MWh) of lithium-ion battery storage capacity to firm up the grid. Tesla and a number other manufacturers supplied the storage systems across a patchwork of projects, all of which got built in about six months. This was an initial ‘win’ for BESS that proved out proving out the flexibility and speed of BESS installations.
Eight years on, there’s a mad rush to build more energy storage. But while many projects still use Tesla’s technology, efforts today are largely proactively and profit-motivated rather than reactive. Today, we’ll focus on two key questions:
- How do new utility-scale battery energy storage systems get built in the U.S.
- What would need to happen to deploy even more of them more quickly
The BESS blueprint: How projects get built
The first thing to note about everything that needs to happen between someone thinking about deploying batteries alongside renewables or directly on the grid is how many different (often concurrent) processes there are and how many stakeholders there are to engage. The stakeholders alone range from manufacturers to developers to operators to utilities and other regulators.
It’s helpful to note that manufacturers, developers, and operators are silos with some overlap. In the past, battery energy storage system manufacturers used to get their hands dirty with development more. Now, most of them have given up this line of business. Some manufacturers are also still developing; Tesla, for instance, both manufactures and sells its megapacks and develops its own projects on occasion, though they predominantly sell to other developers. For reference, Tesla deployed 6.5GWh of utility-scale energy storage in 2022.
Moving to the developer bucket, there are ‘BOOs’ and ‘BOOTs’. BOO stands for build own and operate, while BOOT stands for build, own, operate, and then transfer. The idea is that there are companies like Agilitas Energy (more on them later) that build, own, and operate for twenty-ish years, i.e., the life of a battery.
Other developers (the BOOTs) are more like ‘sponsors’ who sell to utilities or other companies once a project is ‘broken in’ and de-risked from a development perspective. Finally, there are also pure play developers who sell before ever operating (usually as part of a portfolio).
As far as the blueprint for deployment itself, here’s a (highly simplified) process flow for developing a new utility-scale battery energy storage system:
- Origination: The first questions developers ask themselves include the variables of when, where, and how. For instance, factors such as land costs, land options, availability of nearby substations, grid congestion, renewable energy curtailment (as we introduced last week), and more might impact siting of a project. Pairing storage with solar is also different from pairing with wind or deploying storage in a standalone capacity.
- Project design: Once a developer selects where to build, the engineering team begins looking for OEMs to partner with and for equipment / system options. The engineering team will also start building footprints to forecast equipment needs.
- Sourcing: Once a first-pass design is in place, it’s time to talk to suppliers about lead times and negotiate prices. In an ideal world, developers can work on multiple projects simultaneously to bundle orders and get economies of scale.
- Interconnection: This is the doozy at present. Navigating the grid interconnection process, i.e., how the project connects to the grid, could take years. There might be 100 people in front of you ‘in line.’ More on this later in this newsletter.
- Notice to proceed: The project is approved for interconnection and usually coincides with financial close: Money starts flowing, deposits are sent to suppliers, and you break ground.
- Construction: The construction phase often happens in parallel with market registration and the finalization of grid interconnection. At this stage, developers also start considering how the project in operation will communicate and share data with the ISO, which coordinates, controls, and monitors the electric grid of the state or states that fall under their jurisdiction.
- Energize! The project ‘turns on,’ so to speak.
Across all phases, developers are also navigating financing, i.e., questions like how the project is going to make money and whether and to what extent to leverage tax equity, debt, PPAs, etc.
And beyond financing, there are other risks at every step in the development process.
For example, Stephan noted that in project design, many developers often make a mistake by trying to fill as much space as possible with batteries. You need room for a lot of other electrical equipment beyond just batteries to build a functioning and sound energy storage system. You might need a substation. You’ll definitely need switchgear (as pictured below), you might need auxiliary power, an O&M building, and a “bunch of other junk,” as Stephan quipped. Developers get too liberal at times; it’s prudent to claw back the battery footprint to leave space for other necessary equipment.
And that’s just one risk. A bigger (and growing) challenge lies in interconnection.
Missed connection: ‘Squatters’ and insufficient supply
In the wake of the IRA in the U.S., the number of projects seeking interconnection (i.e., a connection to the grid) has ballooned, eclipsing more than 1 TW of generating capacity. Wait times are growing as the line does. Here’s how the average time spent in the interconnection queue for completed projects has changed in the past 15 years.
- Projects completed in 2008: <2 years in queue on average
- Projects completed in 2015: ~3 years in queue on average
- Projects completed in 2022: ~5 years in queue on average
Part of this is a sheer numbers game: When more projects apply for interconnection, it makes sense that the queue gets longer and wait times increase. PJM, for instance, the TK that serves TK, is not accepting new interconnection queue applications until 2026.
There are other factors at play here, though. Not all projects and developers have equal intent to actually see a project to completion. In our conversation, Stephan noted there are many ‘squatters’ who don’t necessarily intend to go through or have no realistic shot at making it through the whole development process. They just want the option. Stephan identified this as a “huge problem.” Only approximately 20% of projects that are in queue end up getting completed.
Construction is pretty quick on these systems because the system’s main components are the batteries and the inverters, the switchgear, and the transformers, things like that; the actual, call it ‘hard balance’ of the system that exists on the site itself is pretty straightforward.
As long as we have supply locked in and available to deploy, construction can be done in as quickly as six months. Then it’s waiting on the utility to perform the actual interconnection… when I think about what we struggle with the most, it’s definitely utility interconnection.
The other major challenge that both Barrett and Stephan called out is supply. Specifically, batteries, transformers, switchgear, inverters, and other necessary electrical components aren’t in high supply. Even as investments in battery manufacturing capacity in the U.S. skyrocket, these still come with long lead times before factories are online. In the present moment, based on BESS deployment, markets are constrained and prices are rising.
One thing that’s not a massive issue for BESS deployment in Stephan’s eyes is permitting. This topic gets a lot of attention as it delays other energy projects, like building transmission lines (or natural gas pipelines). But the square footage of a BESS project is much more compact, simplifying things.
It’s one thing to identify interconnection as a critical constraint for deploying more renewable energy and BESS in the U.S. It’s another to solve that issue. The gridlock in interconnection could take years to sort out; As we noted, some queues are so backed up that they aren’t accepting new applications for years.It could continue to get worse!
I don’t have any grand palliative prescriptions here other than to say a) I’m now primed to investigate the policy question of ‘what would help’ more deeply and b) to say that this, alongside other things like permitting reform, should be a firm focus of regulators out to 2025.
It’s great the IRA got passed. But ensuring other changes, like updates to interconnection processes, follow suit is equally critical to make full and best use of public funding.