Financing energy storage projects: assessing risks

Financing energy storage projects: Assessing risks

June 01, 2017 | By Brian Greene in Washington, DC and Deanne Barrow in San Francisco

Technological and cost breakthroughs are expected to lead to rapid growth in the number of utility and behind-the-meter storage projects. 

Industry insiders say the energy storage market in 2017 feels like the rise of the solar industry in the late 2000s. In 2016, energy storage developers in the US installed 336 megawatt hours of storage, double the amount from the previous year. By 2022, energy storage installations are expected to reach 7,300 megawatt hours and generate revenues of US$3.3 billion. 

States are stepping in to provide rebates and energy storage mandates. Deal flow is picking up, with lenders and investors eager to move in on this emerging trend. 

In the last two years, at least two non-recourse project financings of standalone energy storage projects have closed in the US. For the energy storage market to reach its expectations, lenders and investors will have to get their heads around the unique risks posed by storage projects.

Two types

Utility-scale storage projects provide services to the utility grid. 

An important service is integrating energy from variable renewable sources. Energy storage helps in two ways. 

First, it smoothes out fluctuating output from solar and wind that can otherwise wreak havoc on a grid by upsetting frequency balance. Both solar and wind are prone to rapid ramp up and ramp down, leading to grid instability. Batteries having short charge-and-discharge cycles on the order of seconds can respond to fluctuating renewable output more quickly and accurately than thermal power plants. 

Second, energy storage can help integrate renewables by shifting supply to better align with demand. By doing so, curtailment of these sources is avoided. This service requires batteries with longer charge-and-discharge cycles on the order of hours. 

Behind-the-meter systems provide services to the grid as well as to the host customer. These systems are installed on the customer side of a utility meter. The customer can be either commercial and industrial or residential. Both residential and commercial customers benefit from having a backup supply of power. If the customer is commercial or industrial, then it gets the added benefit of demand charge savings under its retail rates. Demand charges are what utilities charge customers for their maximum load during a certain interval. They can make up a significant portion of a customer’s bill. By drawing on the battery instead of the grid during periods of peak electricity use, the customer can avoid expensive demand charges. 

Behind-the-meter storage also helps with integration of distributed resources. The energy storage system can store excess energy produced by a solar system on the customer’s roof, usually during the day when the customer is not home, and release the energy when demand increases, usually during the evening. Without energy storage, the excess energy gets fed back into the grid at a time when there is no matching demand, which can cause problems for the grid. 

Creditworthy corporate offtakers like Whole Foods, Walmart and Amazon are increasingly interested in energy storage. The interest of these players in energy storage is an extension of the “corporate PPA” trend that took hold in 2016.

California is the dominant market leader for storage in the US. Total deployments in 2016 increased 100 percent over the previous year largely due to a burst of activity in California in the fourth quarter of 2016, when more than 200 MWh came online. The deployments were driven by fast tracking of procurement to compensate for potential electricity shortages after a gas leak was discovered at the Aliso Canyon natural gas storage facility. Other markets such as Hawaii, Massachusetts, New York and Texas are waking up. 


Incentive programs are gaining momentum as more states pass laws and adopt regulations to drive this nascent industry. Project developers should have a firm grasp of any incentive programs to the extent the financing is dependent on them. 

At the federal level, a 30 percent investment tax credit may be available for certain energy storage installed in conjunction with solar or wind projects. (For a more detailed discussion, see “Batteries and Tax Credits” in the October 2016 NewsWire.) 

At the state level, the regulatory landscape varies widely. 

In California, the self-generation incentive program (SGIP) has been a key contributor to the growth of the energy storage market by making the projects economically attractive. The program has been around since 2001. It offers rebates to certain distributed energy technologies, including wind, combined heat and power, fuel cells and energy storage. The SGIP is funded by a charge levied on all ratepayers and collected by the three California investor-owned utilities. 

A revamped version of the program that greatly benefits energy storage became effective on May 1. Under the revamped program, the total amount of rebates being offered is US$166 million per year, double the previous amount, and 75 percent has been allocated to the energy storage category. For commercial energy storage projects greater than 10 kilowatts in size, the rebate offered is 50¢ per watt-hour of energy produced (but only 36¢ for solar-plus-storage so as not to over-subsidize projects that qualify for a federal investment tax credit). The customer must bear at least 40 percent of total project costs. 

California, Oregon and Massachusetts have each adopted an energy storage mandate that sets mandatory storage procurement targets for utilities. 

In 2013, California established a collective mandate of 1,300 megawatts by 2020 for all utilities. Oregon followed in 2015 with a smaller-scale mandate of five megawatt-hours by 2020 per utility. In August 2016, Massachusetts passed a law authorizing its state energy commission to set a storage mandate. The Massachusetts Department of Energy Resources will decide the level of the mandate by July of this year. A state-commissioned report recommended 600 megawatts by 2025. If the recommendation is adopted, the Massachusetts target would be the most aggressive, representing 5 percent of peak load, while the California and Oregon targets represent 3 percent and 1 percent of peak load respectively. 

In May, Maryland became the first US state to offer a tax credit for energy storage. The amount of the tax credit is 30 percent of the cost of a customer-sited installation, subject to a cap of US$5,000 for residential installations and US$75,000 for commercial installations. A total of US$750,000 per year is available under the program. The Maryland tax credit is not limited to solar-plus-storage. The tax credit becomes available in 2018 and will run through 2022. 


Investors and lenders are eager to enter into the energy storage market. 

In many ways, energy storage projects are no different than a typical project finance transaction. Project finance is an exercise in risk allocation. Financings will not close until all risks have been catalogued and covered. However, there are some unique features to energy storage with which investors and lenders will have to become familiar. 

Energy storage projects provide a number of services and, for each service, receive a different revenue stream. 

Distributed energy storage projects offer two main sources of revenue. Capacity payments from the local utility are one. Power purchase agreements providing capacity payments for distributed energy storage systems with terms of 10 years or more are becoming customary in California. Payments for demand charge management for on-site load are another. Demand charge management occurs when electricity is drawn from the during times when grid prices are highest. By drawing on the battery for power at those times, customers avoid expensive demand response charges. Although the customer’s cost savings vary, developers can lock in a revenue stream by charging customers a fixed monthly fee based on projected cost savings. 

Distributed energy storage systems that have been financed by borrowing on a non-recourse basis to date have been able to demonstrate a rate of return that is acceptable to lenders based on revenues from capacity payments from a utility and compensation for demand response management from creditworthy customers. What many industry players find exciting about distributed energy storage is the potential to stack even more revenue streams from ancillary services, such as spinning reserves and voltage support. 

The primary benefit of distributed storage systems, so-called “value-stacking,” also presents a risk if competing uses of the battery are not properly managed. Unlike traditional project financings where assets are limited in their application, an energy storage system must be given the flexibility to operate in a variety of service roles. Covenants in loan agreements, for example, need expressly to permit the various uses the battery is intended to serve or could serve in the future. 

Unlike distributed energy storage, utility-scale projects do not have the intrinsic ability simultaneously to sell services behind the meter to a host customer and capacity or energy to a utility. Utility-scale projects have the potential to provide a number of ancillary services to support the grid, such as frequency regulation, spinning reserves and voltage support, but it is difficult to monetize these services at this time due to a lack of compensatory structures in wholesale electricity markets. As a result, while a utility-scale project could theoretically provide different services to separate offtakers, it is more likely to have a single offtaker or revenue stream. 

A limited number of utility-scale energy storage projects have been financed to date on a project-finance basis. The number of utility-scale projects should increase as costs for energy storage technology decline and utility-scale projects find a way to generate multiple revenue streams. 

In the case of behind-the-meter systems, the customer would typically pay for or provide the electricity required to charge the battery, but the developer must be able to show that the battery provides an economic benefit to the customer after taking this cost into account. If a distributed energy source such as rooftop solar is available at the site, then the battery can draw on the solar array for power. In that case, the customer has no expense except, perhaps, lost income if net metering is available. 

If no such energy source is available, then the battery will have to charge from the grid. In that case, the cost of the power will be paid by the customer as part of its monthly utility bill. The developer should account for this cost when setting its monthly subscription fee. One option is to deduct a fixed amount for the projected charging costs from the subscription fee. The charging cost (up to the fixed amount) then becomes a “pass-through” charge. With this structure, the customer takes the downside risk if charging costs turn out to be greater than the fixed amount, but takes the upside potential if charging costs are lower than expected. 

In the case of utility-scale systems, the storage project owner will need to purchase the energy to charge the battery through a PPA if the storage project is the electricity customer. Lenders and investors should conduct a bankability review of the PPA. The PPA is essentially the fuel supply arrangement for the project. 

If the storage project is providing storage services to a utility, then the utility and the storage project may enter into a service contract that requires the utility to pay both a capacity payment and an energy charge to keep the battery on call to accept electricity for storage or discharge it back to the utility. 

Service contracts between energy storage projects and utilities may allow the utility the option to require the storage project to be available to accept electricity 24 hours a day, seven days a week. This ensures that the battery can be used at any time to soak up excess power from the grid, such as during times of peak solar and wind output, and to discharge energy when needed to support the grid. Storage projects may also enter into service contracts with associated facilities developed by the same sponsor or an unrelated sponsor. 


Regulatory regimes for energy storage are in a state of flux. 

Both the Federal Energy Regulatory Commission and regional transmission organizations (RTOs) are grappling with how to update regulatory and policy frameworks to better integrate energy storage and remove barriers to market participation. Key regulatory issues currently under review include ways to remunerate energy storage in wholesale electricity markets and ways to facilitate interconnection. 

Regulations affecting remuneration of energy storage services present a key risk because of the impact they can have on determining what is commercial. There is currently very little uniformity among RTO markets. The economics of charging and discharging during the day, versus at night, and the duration of the charging and discharging, can greatly affect economics. 

On the subject of interconnection, there is some uncertainty over which FERC rules apply to large energy storage devices seeking to interconnect to the grid. A clarification that would place energy storage installations that exceed 20 megawatts within the ambit of FERC’s large generator interconnection rules is currently under consideration as part of a pending rulemaking that was opened in December 2016. (For additional information, see “Developers are Watching Two FERC Proceedings” in this issue.) Small-scale energy storage is already expressly included in FERC’s standard interconnection rules and agreements for small generating facilities. 

However, small-scale energy storage installations face uncertainty for a different reason. When small-scale energy storage is combined with a distributed energy source like rooftop solar, it is not clear whether the addition of an energy storage component affects the status of the rooftop solar system as a “qualifying facility” under the Public Utility Regulatory Policies Act of 1978 (PURPA). 

Qualifying facilities enjoy several benefits, including a right to interconnect, the option to sell energy and capacity to a utility at the utility’s avoided cost, and relief from certain regulatory burdens. The PURPA rules are unclear whether a storage project that uses renewable electricity for charging would be considered to be a renewable resource and, therefore, be considered a qualifying facility. It is also unclear whether a combined rooftop solar and battery storage system would be considered a qualifying facility if the electricity used to charge the battery is not primarily from a renewable source. 

Turning to environmental permitting, behind-the-meter storage systems do not generally raise separate material concerns because the footprints of such systems are typically small. Identifying permitting requirements for larger projects will require a review of local laws and regulations. 

Utility-scale storage is usually financed as an add-on to a project that includes other assets. This can have implications for regulatory and environmental permitting requirements. If the battery and the other assets are owned by different project companies, then the situation could arise where regulatory and environmental permits pertaining to the battery are held in the name of the other project company. Shared use of the permits will need to be provided for in a shared facilities agreement, if the permits allow for such sharing.

According to GTM Research, lithium-ion batteries made up 98.4 percent of the US energy storage market in the last quarter of 2016. Lithium-ion battery prices have fallen 73 percent since 2010, due to improvements in technology and scaling by manufacturers. Battery prices as a whole have declined 40 percent since 2014. 

The type of battery selected by the project will depend on the intended purpose because certain technologies are better suited for certain purposes. For example, batteries with long charge-and-discharge cycles work best for energy supply shifting and household solar PV, while batteries with short charge-and-discharge cycles are best for short-term regulation of the grid and frequency response. 

Because batteries are made up of chemicals, operating conditions can have a big impact on performance. The role of the asset manager is to optimize dispatch. The asset manager is a key player. Lenders will want to evaluate its credentials and track record. Given the nascent nature of the industry, many of these companies are startups. 

Some companies that act as asset managers are both developers and dispatch managers. Examples are Advanced Microgrid Solutions, Stem and Green Charge Networks. Integration of the developer and asset manager roles can offer a competitive advantage. The companies can size the battery from the beginning by taking into account how they will optimize dispatch once the battery is operating. 

A key operating parameter is the battery’s depth of charge. This refers to the amount of total capacity that remains, usually expressed as a percentage. For example, a battery with a 90 percent DoD has 90 percent of its total capacity remaining. Different uses require different DoD. In general, the greater the DoD required by a particular use, the faster the degradation of the battery and the more frequently the battery has to be replaced. It is good to look for a battery operator that knows the best operating parameters for the particular battery in question. Most battery developers offer O&M service for their batteries. Some developers may also be willing to provide a capacity guaranty.

Technical risk should be mitigated by a manufacturer’s warranty. Tesla offers 10-year warranties for its batteries. Ten years is generally the market standard at this time.