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U.S. Battery Storage: Big Players Shaping the Landscape

Increasing state-led and federal regulatory activity to boost energy storage deployment across the US is set to open the floodgates for battery storage in the country. In 2018, debt financing made a notable appearance, while 2019 will see the  market readying a series of master plans to open up merchant avenues

Alongside an explosive growth in renewable energy capacity, battery storage projects are becoming particularly mainstream in certain US regions as part of the energy transition. 

Battery storage costs have declined an impressive 80 per cent since 2010 and are slated to reach US$100 (£76.8 €88.5) per kWh by 2025. As a result, batteries are on course to compete with traditional grid service providers as they can offer more efficient and potentially more competitive services. 

In October [2018] the Pacific Gas and Electricity Company (PG&E) received approval from California Public Utilities Commission (CPUC) to install a storage portfolio of 567MW to replace gas-fired peakers due to the utility's belief that battery storage will offer better value for grid stability. 

Some states in the country seem to be significantly bullish on this. Therefore, a major driver for storage deployment in the country has been state-driven policies making it obligatory for utilities to procure a certain amount of MW capacity by a deadline, such as in the case above. 

Additionally, independent system operators (ISOs) and regional transmission operators (RTOs) are offering opportunities for merchant battery storage projects to provide ancillary services, including capacity and frequency response. 

These market drives create opportunities for all kind of market participants. The majority of large-scale projects across the country are owned by third parties, but a significant amount is owned by utilities which offer private construction and development contracts. 

In 2017, utilities commissioned approximately 216MW. By the end of 2017, the US had interconnected a total of 708MW, including residential, non-residential, and utility-supply.  

Back in 2010, California was a first-mover mandating its three main investor-owned utilities (IOUs) to procure 1,325MW of storage by 2020— a move that resulted in California developing the largest energy storage market in the United States. 

In 2018, another state that made big news around storage mandates was New York. Initially, it announced a 1,500MW mandate alongside a US$200 million (£153.6m €177m) investment in the technology through the state-sponsored NY Green Bank. 

However, in January [2019] New York Governor Andrew Cuomo launched his so-called 'Green New Deal' upscaling the state's commitment to 3GW by 2030. 

States that are in the process of setting storage mandates and policies are Arizona (3,000MW proposed), Nevada, and Colorado. Massachusetts is also setting up its Clean Peak Energy Standard scheme which is being designed to allow a certain number of peak hours to come from renewables, indirectly promoting clean energy projects plus storage developments. 

According to Moody's, state-driven regulatory support could result in a nine-fold growth in installed capacity from 2017 to 2022. 

Interestingly, Deanne Barrow, associate at Norton Rose Fulbright in Washington, DC, noted that the residential behind-the-meter sector saw explosive growth in 2018, and it constituted the fastest growing area of storage in the country. 

"We see a lot of consumers in places like Hawaii, Florida, Puerto Rico and Texas – places hit by storms and weather events – who are willing to pay for home batteries because it provides the peace of mind that they can have back up power in the event that the grid comes down," Barrow says. 

In fact, in 2017 Hawaii led the ranking for energy storage per customer, with Kauai Island Utility Cooperative averaging 415 watts per customer. The Arizona utility Tucson Electric Power Company came second with 50 watts per customer. 

Debt financing 
In 2018, the US storage industry was boosted by a slight increase in non-recourse battery storage project financings, albeit mainly allocated to projects co-located with renewables generation. 

The most notable debt financing development was when in December [2018] Macquarie Capital secured US$100 million (£76.8m €88.5m) for a portfolio of projects for Southern California Edison. The package comprises the refinancing of a 52.5MW/315MWh asset – which became the first non-recourse financing of battery storage in 2017 – and will fund the construction of an additional 177MWh portfolio of behind-the-meter. 

The debt package was led by CIT Group and saw commitments from Sumitomo Mitsui Banking Corporation (SMBC) and Rabobank. 

The largest non-recourse financing of battery storage assets worldwide is still considered to be the US$2.3 billion (£1.76bn €2bn) funding of the AES Southland project in the US which closed in June 2017. 

The project included a 100MW utility-scale system in California, a 10MW utility-scale battery storage system in Arizona, and two combined cycle gas plants of 1,284MW in California. 

The financing comprised approximately US$1.5 billion (£1.1 bn €1.3bn) of senior secured notes, a US$492 million (£377.9m  €435m) senior secured loan, and a $350 million (£268m €309.8m) equity commitment from AES. 

The 100MW project had secured a 20-year PPA with Southern California Edison. Besides, it benefited from the existence of significant revenues from the gas-fired plants, which decreased the level of scrutiny that debt providers usually require for large scale standalone storage projects. 

Due to the project finance instinct for sufficient and stable revenue streams, storage debt financing is widely dependent on such contracted revenues being made available. 

Brian Greene, partner at law firm Kirkland & Ellis, says, "What project finance debt providers are looking for is a contracted revenue with a creditworthy third party – such as a utility. 

"As utilities award more long-term contracts to fulfil storage mandates and and resource planning, we will see more project financing of energy storage." 

Meanwhile, as is the oft-stated case with clean energy solutions, regulatory stability is a prerequisite for investment. 

"If the market is steady and the rules are clear and not always changing, then I do think investors— both debt or equity holders— would be more interested in entering the market," says Judy Chang, principal at Brattle Consulting Group. 

"It really depends on the regulatory regime and how quickly we can reassure investors that the revenue will be there," Chang adds. 

Moody's suggests that energy storage assets which plan to develop a stacked business case will need to make sure that they are designed in accordance with their destined use. 

Specifically, the financial credit agency notes that when projects open up to a combination of uses, it can change the operational profile of the project increasing the risk for faster degradation. 

Landmark boost for merchant projects 
In February [2018], the Federal Energy Regulatory Commission (FERC) issued Order 841 instructing the RTOs and the ISOs to outline their plans on how they will scale up battery storage participation in the wholesale markets for energy trading, capacity and ancillary services. 

The announcement was celebrated by the industry as one that would open the floodgates for energy storage in the country, especially since the order would facilitate business models with stacked revenue streams. 

"For battery storage projects, just because we can articulate and calculate the revenues on an economic basis, it doesn't mean that project investors can monetise every line of benefit," Chang comments. 

"And that is what the new order will attempt to change: lift some of the barriers for storage projects to monetise on all the services they can provide," she adds. "Order 841 is definitely a big, and necessary, step towards the right direction." 

"It is a very exciting time for the storage market because we are finally seeing a regulatory framework to really start to take shape after just being hypothetical — we are now seeing a plan," Norton Rose Fulbright's Barrow comments. 

In the wake of the news, an analysis by consulting agency Brattle Group stated that the energy storage market in the US could reach 50GW— provided that costs continue to decline. 

In December [2018], the wholesale grid operators completed their compliance filing, setting the stage for how storage will better integrate into wholesale markets and the implementation process is under review. 
The rules and the implementing tariffs are due to be published by the end of the year. However, industry experts anticipate delays partially due to heavy anticipated input by the industry. 

"There are already a number of battery storage projects in wholesale markets in various parts of the country. FERC's new rule, over time, will facilitate a larger number of projects receiving wholesale market revenues in RTOs and ISOS which cover around two-thirds of the country," says Robert Fleishman, partner at Kirkland & Ellis. 

Taking capacity market as an example, not all grid operators in the US have a mechanism in place. According to the U.S. Energy Information Administration the largest one is the Pennsylvania Jersey Maryland (PJM) Interconnection, followed by the New York ISO and ISO New England. 

Each capacity market has a different structure and different rules for energy storage. For example, each usually requires that a resource is available for a certain minimum time. For PJM it is 10 hours, for ISO New England it is two hours, and for New York ISO four. 

Following Order 841 compliance, PJM proposed to alleviate the 10-hour requirement by allowing energy storage projects to bid in three different modes: charge, discharge and continuous. 

The biggest markets for energy storage participation in frequency regulation have been the PJM and CAISO. 

PJM traditionally procured regulation services from coal-fired or natural gas plants briefly until 2011. In 2012, following FERC's Order 755— which instituted ISOs to reward projects with quick response in a more just way, PJM divided its frequency regulation market into two service provisions. 

Regulation A (Reg A) typically addresses conventional energy generators with slower ramp rates, and Regulation D (Reg D) is created for fast response resources— but with limited capacity— including energy storage. 

According to the U.S. Energy Information Administration, the move led to the deployment of 236MW in PJM's service area from 2012 to 2016 with more than 90% of these projects participating in the frequency response market. 

However, in 2017 the market entered a period of uncertainty and reduced revenues when the PJM put a cap on the amount of Reg D sources to be procured to a maximum 26% of the regulation requirement. It also updated the so-called 'benefit factor' by decreasing the value of the fast ramp response.

This article appeared in its entirety in the February 6, 2019, edition of Inspiratia. Article available to subscribers