Energy storage hedges
Battery storage developers are looking more frequently for contracted revenue streams and for ways to manage commercial risks associated with their projects.
One way to do that is through commodity hedges or related derivatives.
While energy storage hedges are not particularly common today, that may change as capital costs for battery storage assets decrease and other factors fall into place.
There are several revenue generation strategies for utility-scale battery projects, including pricing arbitrage (buying energy at low prices and selling at high prices), sales of capacity or ancillary services, or sales of demand response and transmission-related services.
In organized markets, merchant sales expose projects to market price risk. Developers, especially those seeking project financing, may prefer more predictable revenue streams where price risks are transferred to another party. A hedge or related derivative is a means to do that.
While many different transaction structures exist, the basic mechanism underlying all of them is that the project offloads price risk in exchange for upfront payments or giving away market upside to a counterparty that takes the price risk. Operating risks generally remain with the project.
In ERCOT, some developers have had success hedging revenue from ancillary services. The hedge provider pays a fixed price per megawatt hour, and the project company pays a floating price equal to the day-ahead clearing price for the ancillary services per megawatt hour. The two payments are netted. The project receives downside price protection in exchange giving the hedge provider the upside available during high price periods.
Similarly, in the past, some developers had success entering into Regulation D hedges in PJM. Regulation D is PJM's fast-responding regulation service to correct short-term changes in grid frequency.
Many market participants are trying to develop other products to help battery storage projects manage price risks.
Clearing prices in transactions with projects from other asset classes — for example, thermal, wind and solar — should play a central role in the attractiveness of these products to the power marketers likely to transact with projects.
Capital costs associated with battery projects should ultimately dictate pricing that make these products attractive to storage developers. As capital costs decline, so will minimum pricing that provides attractive returns for developers. If the federal government enacts legislation permitting standalone storage to take the investment tax credit, that may further reduce the clearing price for developers. The opportunities to "stack" other revenue streams with that provided by a derivative also may reduce the clearing price in certain situations.
If and when these factors converge, there is the potential for transactions to make sense for both parties and ultimately to get done.
Solar provides a potential analog. Solar hedges were not being executed in volume in the US until very recently. They only became viable as capital costs for solar projects fell and solar developers were able to accept lower offtake prices. Like other asset classes, the viability and timing of opportunities for storage hedges may vary in different organized markets.
When and where these products make sense, how will they be structured? The fixed-volume ancillary service swaps that have been executed to date for storage assets provide one option. These hedges in some ways resemble the fixed-volume swaps used by owners of wind and solar projects.
Given the dispatchability of storage assets, we also see opportunities to base products roughly on two structures that are used for thermal assets: the revenue put and the heat rate call option or "HRCO."
Repurposing a revenue put
A revenue put is in many ways similar to an insurance product. The developer pays a large premium to the counterparty upon execution. Often the revenue put is executed concurrently with the financing documents so that the developer can use the project's credit facilities to make the payment. The premium is a one-time payment rather than an annual or quarterly payment.
The basic idea is that the counterparty will true up the project company each year in the event that the revenue earned by the project company over the prior year is lower than a predetermined amount, calculated as a lump sum rather than a price per megawatt hour. However, there are several nuances.
The first nuance is that the measure of revenue earned by the project company is not actual revenue. Rather, the revenue is calculated as the amount of revenue that the project would have earned assuming the project had been operated at an assumed efficiency and dispatched at economically advantageous times. In this way, the developer retains operating risk, but the derivative is structured to account for the project's anticipated operational capabilities.
The second nuance is that project revenue is calculated by subtracting the plant's assumed start-up costs and certain operating and maintenance costs. Again, the developer retains operating risk, but the derivative reflects the projected operating expenses.
The third nuance is that the developer may negotiate the right to receive quarterly advances from the hedge provider calculated based on how the hedge would have settled if the settlement period were quarterly rather than annual. Once the annual calculation is run, the developer may be required to repay a portion of the advances during the year if the calculation shows that the hedge provider overpaid during the year.
The revenue put structure could be repurposed for a battery project. The developer would pay an upfront premium to the hedge provider, and in turn the developer would have downside protection in the event that the battery's assumed revenue, as recalculated under the derivative, is below a negotiated threshold. The revenue floor serves as a contracted revenue stream available for debt sizing.
The battery revenue would be calculated assuming the battery had been operated at a set efficiency. The parameters around this calculation would be included in the derivative and may include power capacity (which could decline over time to account for cell degradation), maximum duration or run time, depth of discharge, maximum number of cycles per year, charging hours and round-trip efficiency (which is a measure of how efficiently the system takes in electrical energy, stores it in electrochemical form, assuming a lithium-ion battery, and converts it back to electrical energy). Charging costs also would need to be addressed.
One of the attractive aspects of a revenue put structure is market upside is retained by the project. The derivative provides a contracted floor on revenues, but does not expose to the project to significant ongoing payment obligations. The project would retain the flexibility to pursue other revenue streams.
Repurposing a HRCO
For a gas-fired project, the counterparty under a HRCO has an option to buy power for a price that depends on the market price for gas and on assumed characteristics about the plant's capability and costs to convert gas into electricity.
A HRCO can be physically-settled (meaning power is sold to the counterparty as part of the transaction) or financially-settled (meaning no power is sold to the counterparty).
In both physical and financial HRCOs, the hedge provider pays an fixed option premium each settlement period to the project company. This premium is a contracted revenue stream that is used for debt sizing.
Under physical HRCOs, power is actually sold to the counterparty as part of the transaction. The counterparty has the option each day to provide a notice to the project specifying the volume of power it wants to purchase the following day. The volume is subject to certain constraints negotiated before execution of the HRCO that reflect the project's assumed operational characteristics. The hedge provider pays the "strike price" per megawatt hour of power purchased. The strike price is equal to the market fuel price multiplied by an assumed heat rate, plus a fixed O&M charge per megawatt hour. The hedge provider also pays for assumed start-up costs for the plant.
Financial HRCOs likewise have a strike price calculated similarly to the corresponding concept in physical HRCOs. However, in financial HRCOs, the hedge provider does not buy power for the strike price. Rather, the hedge provider pays the strike price and the project company pays the market price. This settlement amount is netted against the option premium and start charge owed by the hedge provider.
Both physical and financial HRCOs could be repurposed for battery projects.
In a both physical and financial storage structures, the hedge provider would submit a schedule for each day specifying the purchase of a certain volume of energy (in the physical hedge) or notional amount hedged (in a financial hedge) per hour for the following day. The schedule would be subject to certain parameters mirroring the operational constraints of the storage project such as power capacity (which could decline over time to account for cell degradation), maximum duration or run time, depth of discharge, round-trip efficiency and charging hours.
Each settlement period, the hedge provider would pay the option amount.
In a physical transaction, the project would deliver energy during scheduled hours for the strike price, the product of the assumed round-trip efficiency and the charging electricity price during charging hours.
In a financial transaction, the counterparty would pay the strike price, the developer would pay the market price, and these payments would be netted, together with the option premium.
There are variations on the HRCO-based structure may be worth exploring, including so-called "look-back" options where settlement is based on optimal exercise schedules determined retroactively for each month.
The developer should be prepared to provide credit support to backstop its obligations under the offtake arrangement. This credit support would probably take the form of either a letter of credit, a parent guaranty from a creditworthy entity or a first-priority lien on the project assets and equity interests in the project company.