Author: Will Troppe
In the run-up to the annual Solarplaza Summit Asset Management North America, we hosted a webinar that zoomed in on the specifics of energy storage assets coupled with solar PV plants. The session, entitled “Storage Asset Operations 101: From Theory to Practical Case Studies,” was moderated by Will Troppe of Power Factors and included analyst insights from Aaron Marks of Wood Mackenzie and practical asset operations experiences from Jeremy McKellep of Canadian Solar. You can view the full recordings and consult their slide decks here.
During the webinar, the panelists addressed as many audience questions as they could. Still, given the volume of interest in the topic and the high level of interactivity from the crowd, we were left with a list of pertinent questions that we hadn’t been able to fully address during our allotted time. To follow up on the webinar, we’ve asked Aaron, Jeremey, and Will to elaborate on the key areas of interest in this follow-up Q&A. We’ve organized the Q&A around four key themes of the session: augmentation, standardization, value stacking, and industry dynamics.
Do most projects augment? Once purchased, how long can you store batteries for future augmentation use? How are EOL units accounted for — do you buy and store them, or do you hope there will be sufficient units in the supply chain at the time of need?
The months-long transition from development to operations is complicated for any clean energy asset. Overlapping stakeholders, contractual handoffs, capacity testing, offtaker permissions, shifting site conditions, and continuously updated documentation to reflect as-built realities create a complex, dynamic environment. Storage compounds these challenges compared to solar and wind due to the higher number of involved stakeholders.
Storage’s need for augmentation means that development is occurring throughout the operational life of the system. If solar is simple but not easy, storage is complex and not easy. Augmentation means you’re effectively building the plane the entire time that you fly it. When you add capacity, you also need to ensure all associated systems are updated, from data platforms to ticketing and warranty management systems. And you need to ensure the new hardware is behaving and communicating properly. Proper controls around the “continuous onboarding” needs of augmentation are crucial — not just in the field, but also in the cloud.
Except for specific project profiles with low cycling (e.g. storage as a transmission asset where the battery is cycled maybe 5-10 times per year), all energy storage projects are modeling augmentation if they’re aiming for a 20-year lifespan. While some projects can likely overbuild 15-20% above nameplate at COD and have that be enough, there will be some form of excess capacity worked into the project plan, whether that’s at COD or later in the project lifespan.
Most projects are performing what we call “AC augmentation,” where an entire additional string and inverter are added. “DC Augmentation,” using new modules and a DC-DC converter for balancing, is lower CAPEX but more technically complex. The other issue with AC augmentation is the need to reserve footprint for the new equipment in the asset site (this is true for both forms of augmentation but AC augmentation requires more space).
Every energy storage project that I have experience with models/plans for future augmentation.
I don’t know of an exact time frame for the storage of batteries, as I would assume this is based on the manufacturer of the specific system. For example, you may be allowed to store the battery for up to a year with certain conditions (Temp -20 to +45C, humidity <85%, and SOC between 30-60%).
I typically see planned procurement occurring through an MSA (Master Supply Agreement) in which the total EOL battery unit quantity is purchased.
Is there a storage availability standard similar to wind’s IEC 61400-26? Is there a common standard for battery capacity testing? How is availability impacted if a storage system’s inverter is available to operate, but the controller doesn’t request output power from the inverter? If all stakeholders in the industry claim to want standardization, what’s preventing it?
IEC 62933 covers energy storage terminology, planning, performance assessments, capacity testing, and beyond, but it does not cover availability.
“Standardization” is a broad term that can be applied across data access methodology, data connection topology, cell chemistries, system design, business processes, contracts and business models, and market structure and incentives. Standardization will happen over time across the board, through a variety of different mechanisms. Some will occur organically, while some will occur when owners with market power begin to apply leverage.
Parties seek standardization that benefits them. Misaligned incentives exist; data disparity between two contractual counterparties benefits the party with the best data and the best tools to make sense of that data. Today’s supply constraints mean OEMs hold significant market power. They typically retain operational responsibility for the batteries themselves, and generally restrict access to cell-level data, preferring downstream stakeholders to treat packs like turnkey “black boxes.” OEMs don’t want to give up perceived commercial value, negotiating leverage, or IP.
At Power Factors, we typically recommend that owners retain as much control over their data as possible. Like the wind industry before it, it’ll take time and a shift in market dynamics to standardize data access in the storage industry.
The storage industry is still relatively young, so part of the reason standardization hasn’t happened yet is simply time. We’ve seen grid-scale lithium-ion deployments for a little more than a decade, while grid-scale wind deployments started nearly four decades ago. While standardization of lithium-ion storage is happening and will happen in the coming years, it also drives lithium-ion storage further toward a commodity product. In our current supply chain environment it’s easy for OEMs to say they want standardization, but when prices and supply relax it’s likely that they will be pushing their own differentiation again.
There is no “standard” developed for availability or capacity, but the capacity testing methodology is determined by both OEM recommendations and contractual (i.e. PPA) requirements. Storage Capacity Tests (sometimes called SCTs) have these general parameters: Net electrical energy output to the Storage Facility Meters, Net electrical energy input from the Storage Facility Meters, and the Stored Energy Level (MWh) of the system.
This test corresponds to the facility in general. Each battery manufacturer is going to have a specific method to calculate their battery cell capacity. Companies are constantly going back and forth on contract language/agreements; that being said, there is no standard that the industry has adopted to calculate and identify proper equipment availability. Additionally, the site design (i.e. overbuild) can also impact the equipment availability and availability guarantee calculations that may not be taken into consideration on other storage assets.
Contractual verbiage is important with respect to how the asset operates. Theoretically, if the inverter is available to operate (whether it is dispatched to discharge power or not), then the EA calculation and AG should not be impacted. However, we see the opposite with respect to the idle time where the inverter is not called upon to “output power” and suffers a fault or error of some kind and the EA is impacted per the contractual definitions and verbiage.
I think there are multiple factors preventing standardization: (1) the age of the industry as a whole, and the “trial and error” process still taking place; (2) proprietary information and the reluctance to lose any potential IP (3) technology is ever-expanding and it is difficult to standardize something that will be changed in the next few years
Are Canadian Solar storage sites operating in an arbitrage capacity, rather than ancillary services or other schemas? How does the revenue side of the equation compare across markets? How does it influence LCOE-optimal operational and augmentation strategies?
Almost ten years ago I contributed to the early stages of RMI’s report on the economics of battery storage. Value stacking has come a long way since then. It’s key to value stack without voiding your warranty and violating the overlapping contracts you need to sign. Recently a Tesla system in Australia failed to respond during a critical grid congestion event and failed to have sufficient resource adequacy capacity available for multiple months, presumably while it was providing other grid services. This led to millions of dollars in fines and returned revenue.
Realizable revenue beyond energy arbitrage is waning in certain markets. We’re seeing reduced pricing in ERCOT’s frequency markets as more supply comes online, and pure-play energy arbitrage is becoming more common. This introduces additional questions for storage owners: Who accepts merchant risk? How should we structure these agreements?
Meanwhile, the Inflation Reduction Act allows tax equity partners to benefit from the Investment Tax Credit nationally on standalone storage projects, effectively compensating storage systems for simply existing.
One additional angle with value stacking, especially in markets like ERCOT where an asset is aiming to earn revenue with multiple market products, is the role of software. Storage operators are going to approach energy management differently, and this will depend both on how they choose to operate and what market they’re operating in, but also on the existing infrastructure the operator has. Utilities typically already have dispatch and operations centers, and in states where the utilities can own generation these operation centers are already well-equipped to dispatch and bid storage assets. IPPs and smaller operators may find themselves more dependent on third-party software for bid, revenue, and state-of-charge optimization.
To add to both your points, we see third-party “schedule optimizers” collaborating with owners and the SCs on bidding and energy trading markets. I will also say that O&M normally stays away from these types of activities and my department specifically does not handle or assist with energy markets/PPAs etc. — we are purely operations and maintenance.
Canadian Solar’s storage sites in California are primarily operated in a “load shifting” strategy that is dependent on grid peak demand and renewable makeup. However, some of our assets bid into RA and Spinning Reserve markets to maximize their revenue; this is solely based on Generator Asset Owner preference and strategic use of the plant.
What role does the scheduling coordinator play in dispatching the asset? What is Canadian Solar’s relationship like with the OEMs? How do industry stakeholders communicate? What are the operational differences between a hybrid solar + storage and a standalone storage site?
I work with storage owners and operators. To me, this market looks a lot like wind and solar, save for a few additional stakeholders and their associated acronyms like BESS OEMs and QSEs. There are parallels across project M&A, O&M, Asset Management, real-time data acquisition technologies, data intermediaries, and beyond.
It’s more common for solar companies to branch into storage than for wind companies to do so. Solar operators are best positioned for BESS because of the skillsets and certifications required in the field and the combined benefits of hybrid and co-located solar and storage. Still, operational needs are quite different with a dispatchable asset and concentrated store of energy, forcing core competency expansion.
Storage systems are “digital-native;” in 2023, “digitalization” appears as an appropriately anachronistic term. Still, there are challenges, and industry participants will apply increasingly sophisticated techniques to squeeze everything they can out of batteries: (1) field insights to optimize downtime to minimize revenue loss while accelerating the transition from calendar- to condition-based maintenance; (2) characterizing and actualizing insights related to the impact of operational decisions on battery health; and (3) forecasting its impact on energy trading strategies. Industry partnerships and collaboration are key on all fronts.
When looking at the storage industry from an operational standpoint, there’s still a number of diverse business models and competition across how owners choose to operate, maintain, and augment their assets. Even in recent years, we’ve seen flux in how much risk operators are willing to take in terms of how they approach LTSAs and CMAs. As we see operators gain more and more experience, there are likely to be more best practices developed in terms of how they work with integrators, OEMs, and subcontractors to maximize their assets.
Canadian Solar has a good relationship with all of the OEMs on the energy storage side, probably related to our connection with SSES/CSI Solar, which is our sister company under the Canadian Solar umbrella that builds/integrates these systems.
The scheduling coordinator simply provides available capacities (charge and discharge) to the ISOs and reports on outages, submits resource adequacy plans, etc. They will work to schedule the asset for operation based on capacity availability as well as work with other companies (O&M provider, GAO, “schedule optimizers,” etc.) to ensure accurate dispatching and planning. They determine the setpoint (ADS/AGC) that is ultimately seen by the plant and thus control the desired output.
The main operational difference between hybrid solar + storage and standalone storage is the logic in the PPC with respect to charging/discharging. The hybrid system can charge from its coupled PV plant whereas the standalone system does not have that luxury. Furthermore, there may be operational/maintenance concerns and additional planning because of the shared electrical components that hybrid systems share (e.g. feeder breakers in a substation or GSU transformer in a substation that affects both PV and BESS circuits).