Although the coronavirus pandemic is expected to trim global storage installations by almost 20% according to some analysts, 2020 should still be a record-breaking year for new storage projects in the United States.
Seven states now have dedicated storage procurement targets. They are California, Massachusetts, Nevada, New Jersey, New York, Oregon and Virginia.
Procurement targets, improving economics and increasing levels of renewables on the grid are leading to record procurement activity this year. Some utilities are releasing requests for storage proposals in the megawatt and even gigawatt range.
The procurement ramp-up has led a flood of developers to go to market in search of debt, cash equity and tax equity financing to get projects they have been awarded off the ground. Discount rates tend to be higher, and interest rate margins wider, reflecting the perceived riskier nature of storage compared to wind, solar and gas.
Financing storage is different than financing other kinds of projects.
We see five kinds of offtake structures currently for standalone storage facilities. Storage projects provide a number of services and, for each service, receive a different revenue stream. The developer tries to lock in a long-term offtake agreement for each service.
The first offtake structure is a capacity sales agreement with a utility.
The project company receives a capacity payment that is a fixed dollar amount per megawatt in exchange for an obligation to be ready to run (charge or discharge energy to the grid) when called on by the grid operator. The utility purchases only capacity, so the project company may be able to earn additional revenue from selling energy or ancillary services in the wholesale market. This structure is common in California where the investor-owned utilities and community choice aggregators need to procure capacity to meet resource adequacy obligations set by the California Public Utilities Commission.
The second structure is a twist on the basic capacity sales agreement.
The project company may negotiate a put option that gives it the right to sell to the utility on an annual basis all of the stored energy and ancillary services at a fixed price. Although the project company loses the flexibility to earn additional revenues in the market, it may assign greater value to the certainty of a fixed revenue stream. The agreement is typically structured as a tolling arrangement, where the utility provides and pays for all charging energy during the put period. In return, the utility has the right to charge or discharge the facility as it sees fit.
The third offtake structure is an ancillary services financial hedge.
Ancillary services are used by the grid operator to balance the frequency of the grid and ensure there is enough reserve capacity to meet unexpected stress events. The project company sells ancillary services to the market at the spot price. It swaps floating payments for a fixed-dollar-per-megawatt-hour price calculated on a fixed volume of capacity for each settlement period. The swap uses as the floating price the market clearing price for the specific ancillary service product sold. The project company can mitigate volume risk by self-scheduling rather than taking the risk of not being dispatched by the independent system operator under economic-merit-order rules.
The fourth offtake structure is a demand response grid services agreement.
It involves aggregation of distributed storage facilities to form a virtual power plant that provides demand-response service to the utility in exchange for fixed payments. Demand response means shedding behind-the-meter load in response to a signal from the utility. The battery or other storage device may be used by customers for other applications when not providing demand-response services.
The fifth offtake structure is a demand-charge management agreement.
Unlike the other structures, this agreement is with a commercial and industrial solar customer rather than a utility. Power from the storage facility is used to meet peak demand at the customer premises, thereby reducing expensive fees the utility would otherwise charge the customer for peak electricity consumption. Demand-charge savings are split between the customer and project company under a shared-savings model. Alternatively, the customer pays a fixed monthly subscription fee in return for guaranteed savings. This provides revenue certainty for the project company, but it eliminates upside potential.
Storage developers are relying on merchant revenues for an increasing part of their overall cash flows. Contracted revenues as a percentage of total project revenues are expected to continue shrinking as banks remain eager to lend and sponsors continue to pressure debt and equity providers to assume more risk.
In 2017 when we closed the first-ever non-recourse financing of standalone storage assets, banks were unwilling to lend against anything other than a fixed capacity payment locked in for a specific contract term. We have seen the market shift toward giving credit for uncontracted revenues from sales of energy and ancillary services in the spot market. However, when sizing the debt, banks are likely to lower the advance rate.
Merchant exposure for storage is fundamentally different from gas, solar and wind in two ways.
The first is variable fuel costs. Fuel costs for merchant gas are usually fixed under a gas supply contract. For wind and solar, fuel is essentially free. Fuel for storage is the electricity used to charge the battery and, in a merchant project, it is purchased on the spot market. This opens storage to double merchant exposure on both the input and the output sides. The project might mitigate exposure on the output side with a hedge that sets a floor under the electricity price.
The second difference has to do with the potential for overlap between the term of an offtake agreement and the time period during which the project makes merchant sales. When calculating advance rates, lenders will credit a certain number of years of revenue beyond the term of the power purchase agreement. Because of the unique ability of storage to provide different services to different customers at the same time, storage can realize contracted and uncontracted revenues during overlapping periods, rather than waiting for a merchant tail.
Batteries that are combined with wind or solar projects on which investment tax credits are claimed potentially qualify for such an investment tax credit at the federal level.
The amount of ITC for which a battery linked to a solar or wind project qualifies potentially depends on whether the battery is installed as part of the original construction or as a later improvement, when construction started and when installation is completed.
There are two important eligibility rules. The first is that the battery must be considered part of the generating equipment as opposed to a transmission asset. To accomplish this, the battery should be on the low-voltage side of the step-up transformer. It should be physically adjacent to the generating equipment and owned by the same legal entity. Care should be taken about giving the utility dispatch rights, since they can tend to make the battery look like a transmission asset unless dispatch is solely for the purpose of regulating the ramp rate at which electricity from the wind or solar project is fed into the grid.
The second eligibility concept is that at least 75% of the energy stored by the battery should come from the renewable energy project to which it is coupled. Standalone storage does not qualify for tax credits at this time. (For more information, see “Batteries and tax credits” in the October 2016 NewsWire.)
Lenders and tax equity investors will want a covenant in the loan agreement and tax equity documents requiring the sponsor to ensure exclusive charging from the linked solar or wind facility during the first five years of operation during which any tax credit claimed remains exposed to recapture. To the extent the offtaker has a right to control charging, the owner may want to build in a right to recover any ITC-related recapture or losses in the PPA.
Split-obligation EPC contracts
Project lenders and tax equity investors have historically preferred a fixed-price, turnkey EPC contract that aggressively shifts as much risk as possible from the owner to a single EPC contractor. In contrast, a split structure may have multiple equipment supply, construction and installation contracts. Split EPC contracts are more common in storage projects than in gas or solar.
There is more risk for the project owner under a split arrangement than a full-wrap structure where a single contractor takes responsibility for ensuring that all the different parts of the project will work together once the project has been fully assembled.
Splitting creates interface risk with lost time and finger-pointing to sort our responsibility for any defects. Construction lenders and tax equity investors will assess the “bankability” of split EPC contracts by assessing whether the additional risk exposure is sufficiently mitigated.
There are various ways that a project owner can mitigate risk.
To begin with, the owner should mitigate against the risk of construction delays by ensuring that all supply, installation and construction schedules match so that the project will meet target milestone dates.
The construction contractor will usually be excused from its obligation to pay delay liquidated damages if delays are attributable to other contractors hired by the project owner. When this happens, whichever contractor is on the hook for an unexcused delay should be liable for liquidated damages that are large enough to meet any penalties under the offtake agreement stemming from a failure to start delivering power on time. The project owner would also be well-advised to negotiate a common dispute resolution mechanism that applies in the event of a dispute as to which contractor is to blame for a construction issue.
Performance guarantees and warranties
Storage projects have a shorter operating track record than gas, wind and solar because the technology is newer. Poor operational performance can jeopardize offtake contracts and subject developers to heavy non-performance penalties in certain wholesale markets.
Project finance lenders and tax equity investors do not like technology risk.
For storage, the key technology risk is capacity degradation. Financiers will look for a performance guarantee or capacity maintenance agreement under which the service provider refreshes the battery with new cells to maintain capacity at minimum, albeit decreasing, levels over time.
The cost of disposal and recycling of the old cells should be factored into the model if the service provider has not assumed responsibility.
Debt service coverage ratios for storage projects are typically more conservative than for other assets to reflect the risk of the project realizing lower revenues if degradation occurs at a faster rate than what is warranted in the performance guarantee. Lenders may also want to build a reserve account into the financing documents.
Creditworthiness of the performance guarantor is a major issue. Insurance products are available to bolster warranty and performance guarantee providers with weak balance sheets.
Regulatory regimes for storage are in a state of flux.
The Federal Energy Regulatory Commission and regional transmission organizations or RTOS are struggling with whether to classify storage as generation, transmission or a hybrid.
Projects are more likely to get financed the clearer the regulatory framework. ISO and RTO market rules for storage participation vary widely. It is crucial to have a deep understanding of the particular market in which the project is located.
The recent resolution of a long-standing dispute over the PJM regulation service market may offer some welcome regulatory certainty for storage developers.
The dispute began in 2017 when a group of prominent storage developers sued PJM over what they alleged were unfair changes to PJM’s regulation service market rules. PJM had revised its energy neutrality automatic signal for storage and other fast-responding resources participating in the regulation D market, adjusted its algorithms for determining which resources clear the market, and placed an overall cap on the amount of fast-responding resources that could be procured during peak-demand morning and evening hours. PJM said the changes were necessary after experiencing operational challenges (area control error) due to an influx of storage participating in the regulation market.
Owners of battery and flywheel storage projects in PJM (including AES, Convergent, EDF Renewables, Invenergy, NextEra and RES) complained to FERC that the changes were unfair, unduly discriminatory and would result in losses of up to 75% of their investments in some cases.
The project owners acknowledged the inherent risk of being early market entrants, but raised concerns that the re-designed market signal reduced compensation and increased the energy throughput of their storage assets, thereby decreasing life expectancy and compromising performance and warranty contracts with battery and other storage equipment manufacturers.
The case settled in March 2020. Starting on July 1, 2020 until January 1, 2024, PJM will treat all price-taking offers from participating storage resources as having cleared the market as long as they abide by the ISO’s conditional neutrality signal and meet certain minimum performance criteria. The settlement order identifies a list of storage projects to which it applies, but any storage project in PJM can sign up for the deal by filing a two-page “opt-in” form with the ISO.
Trump Executive Order
Tariffs and other trade and national security policies can affect procurement of storage system components.
On May 1, 2020, President Trump issued an executive order banning the use of certain foreign-manufactured equipment in the nation’s bulk-power system, meaning the interconnected electric grid.
There are three key questions for storage developers.
The first question is whether battery cells, modules and packs are covered by the order. The order defines the bulk-power system to include “facilities and control systems necessary for operating an interconnected electric energy transmission network” as well as “electric energy from generation facilities needed to maintain transmission system reliability.”
It appears a standalone battery connected to the transmission grid and injecting energy to provide voltage support would be covered by the order because it ensures transmission system reliability. The order does not apply to batteries that are sited behind the customer meter or interconnect to the distribution system.
The second issue is whether balance-of-system components are covered by the order. The inclusion of “control systems” could potentially cover inverters, power conversion systems and battery management system (BMS) hardware. The order says that it is intended to guard against “malicious cyber activities,” among other threats to the grid. This could signal an increased level of scrutiny for BMS hardware given its vulnerability to remote attacks and the crucial role it plays in maintaining the battery system in a non-hazardous state.
The third question is whether Chinese battery vendors and US companies that have manufacturing facilities in China are covered by the order.
The order covers bulk-power system equipment “designed, developed, manufactured, or supplied by persons owned by, controlled by, or subject to the jurisdiction or direction of a foreign adversary.” The foreign adversary countries have not been identified yet, but it appears the order is aimed at China.
If batteries are covered equipment, then the order could have significant ramifications for supply chains. According to Bloomberg New Energy Finance, China accounted for 73% of global lithium-ion cell manufacturing capacity in 2019. The US was a distant runner up with 12% of global capacity.
It is unclear whether US companies that have established manufacturing plants in China would be considered “subject to the jurisdiction or direction of a foreign adversary.” Tesla, for example, recently opened a “gigafactory” in Shanghai, although production appears to be geared towards the electric vehicle market.
Looking ahead, the order directs the US Secretary of Energy to publish regulations explaining how the order will be implemented in practice no later than September 28. The implementing regulations are expected to identify the particular countries and persons that will be considered foreign adversaries and establish a process under which vendors can apply to the Department of Energy to clear their products.
In the meantime, storage developers may want to consider using alternative suppliers to Chinese companies and other companies who do their manufacturing in China.
There could also be an opportunity for individual developers to obtain clarification from the DOE. In an interview in late May with Politico, the press, Bruce Walker, the DOE assistant secretary charged with implementing the order, suggested developers who are nervous about the order could “work with the Department of Energy . . . with regard to understanding places on the system that we’re more concerned about or not.”