How banks evaluate energy storage
by James Wright, with CIBC Capital Markets in Chicago
Banks have been ready to finance batteries for a while, but until recently, they had not seen many deals come across their desks in need of financing.
The market is changing rapidly.
First, the basic economic case for them had been marginal until recently. Engineers talk about a learning curve for any new technology, which is the cost decline as a function of deployment volumes. This compares favorably with batteries to what bankers saw earlier for wind and solar. Battery costs have declined significantly in the last couple years.
Second, a more favorable regulatory environment is taking shape in many states as utilities put batteries in their plans for capacity build outs. It has only been three years since the Federal Energy Regulatory Commission came out with Order No. 841 that gave a lot more tailwind for battery storage rolling out across organized markets.
Third, the banks had to go through a bit of education on the financing side about the storage landscape and the complexity of the various usage cases: in more basic terms, the number of ways that batteries can be used and how they fit into the broader market.
Finally, it has been a hot renewables market the past few years, and bankers have been so busy with regular wind and solar deals that there was no need to branch out. All of that has now changed. Practically every solar deal today is solar-plus-storage. Banks cannot duck it. They have had to master batteries to remain relevant.
Banks like historical data to help assess risk, risk-weighted cost of financing and debt-service-coverage ratios. There is not a lot.
The US Department of Energy reported recently that only 14 utility-scale batteries have been operating for more than 10 years. That is not just in the US, but globally.
Lenders have been getting comfortable by taking deep dives into the basic chemistry and finding comfort there. About 90% of storage deals that come across our desks involve lithium-ion chemistry. This form of battery has been around for a long time. It dates back to the 1970s and was first commercialized by Sony in the 1980s.
A lot of what comes across bankers' desks are augmentation use cases. A solar project is generating during peak hours of the day, the sun goes down and then the battery kicks in for another four hours.
Many of the deals bankers see have power purchase agreements with capacity payments, which is helpful from a financial perspective.
The way banks approach these deals has been similar to the typical solar deal with a long-term offtake contract, but coverage ratios have started to diverge recently. Capacity deals are arguably more like an availability type of construct, so all the owner needs to do to earn revenue is to have the battery on and available for use. That means there is not a lot of resource risk. Debt-service-coverage ratios for availability deals are around 1.2x, meaning the projected revenue needs to be around 1.2 times debt service.
The deals are using typical mini-perm, back-leverage types of structures. The debt sits behind the tax equity in solar-plus-storage deals, and typically banks are being asked to monetize the full value of the PPA (or beyond).
Warranties and service contracts are important. There is a performance obligation lasting 15 to 20 years in the power contract. There has to be some fundamental backup for that from the battery manufacturer. Most deals banks have seen recently have had 10- to 15-year-plus warranties supporting them.
Sponsors are being careful to budget for required future costs to augment the batteries. Cells age over time and must be augmented to ensure the batteries hit required capacity levels for the full 15-or 20-year term of the PPA.
Some sponsors want to bill more for power in the early years to build up a reserve quickly. Others prefer to add to reserves over time.
The usage cases fall into two buckets.
Bucket one is where storage is used by a utility or grid operator to supply capacity at a certain time of day. That feels like a strategic asset to a lender. Those usage cases typically have high levels of predictability in terms of operational dispatch, which lenders love. The banks then focus on the operating assumptions with the independent engineer because the battery is in a well-defined dispatch box in terms of how it will be used.
The second bucket is where batteries are being used as more of a standalone business. The revenue is largely from providing ancillary services to the grid or earning an arbitrage return. These deals have more unpredictable revenue profiles, making them harder for the project finance market to take a long-term assessment. Banks have been taking more merchant risk in wind and solar deals as they see proof of concept deployed at capacity across the grid. It will probably take a little time before true merchant plays with batteries become primetime in the project market.
Leverage is typically around 90% of value for capacity-type deals in bucket one.
Pricing for such deals is currently at a small premium over regular solar deals. Lithium ion is a well-known technology and most such deals involve bigger sponsors, with robust fundamentals of the underlying PPA and performance warranties. These are the types of factors that typically support high leverage.
The focus until now has been exclusively on batteries with a four-hour or less duration window. Lithium ion struggles to be the chemistry of choice for longer dispatch cases. California has been doing modeling that shows by 2045 to 2050, the state will need a lot longer duration storage to support the big renewables buildout expected, especially as gas peakers are taken off line.
Within the last couple of months, some California community choice aggregators have issued procurements for eight-hour storage. The bids coming in are for pumped-storage hydro, compressed air and chemical battery solutions. These CCAs want the ability to replace gas peakers, which requires the ability to draw on stored electricity from about 4 p.m. to the next morning.
Other states like New York are also looking at long-duration usage cases, but such usage cases are still at an early stage and we are not seeing them yet in the project finance market.
There are other global examples where longer-duration storage is being looked at as an alternative to transmission line upgrades or as a way to avoid solar curtailment in the summer with dispatch of the stored power months later in the winter.
Some interesting technologies are being tested, such as flow batteries, gravity-based solutions and cryogenic air solutions. Most are still in the demonstration phase, but banks are helping to innovate more credit solutions coming to market and, with the right regulatory support, we expect to see some of these newer battery chemistries also approaching the project market.
Congress is talking about tax credits for standalone storage and other forms of support such as a push to electrify the transportation sector. Any major push to deploy recharging networks will strengthen the case for more storage on the grid to address load mismatches between time of peak use and intermittent supply from renewables. Energy storage could also be a key piece of grid resiliency. Wider storage deployment would have made a difference last February during the four-day cold snap in Texas. The big picture points to a growing role for storage.