Large-scale Distributed Storage for Southern California Edison

Firm Contracts mean a Financing first for Distributed Storage

Southern California Edison (SCE), California’s second largest utility, will tap into a 50MW, 200 MWh distributed fleet of battery storage projects, allowing it to shed up to 50 MW x 4 hours of peak load within its West Los Angeles Basin service territory, which is both generating resource and grid-constrained.

The 50MW is composed of many individual batteries in different buildings, which are aggregated into “fleets” and operated as a single resource. This allows SCE to shift the entire fleet of buildings to stored energy when grid resources are strained.



The storage system portfolio was acquired in August 2016 by Macquarie Capital, from Advanced Microgrid Solutions (AMS), who developed it. AMS (and SunEdison) first signed a joint development agreement to finance and deliver the 50 MW of energy storage for SCE back in September 2015. That followed storage system contracts which were awarded to AMS in November 2014, as part of SCE’s 2013 Local Capacity Requirement solicitation.

Since the 2016 acquisition, through which Macquarie provided the project capital to be used to build and operate the fleet, Macquarie and AMS have been jointly developing and constructing the individual projects. Bank financing was closed in March 2017 (see below).

The portfolio is expected to come online in phases over a period of 12-24 months, during 2016 and 2017. AMS will continue to serve as the asset manager of the projects.


Project Deployment & Finance

The project will deploy Tesla Energy’s Powerpack 2 lithium-ion battery systems, behind the meter, at various large-load commercial, industrial and government host sites in Los Angeles and Orange counties.

Hosts range from a large commercial real estate firm to a state university. AMS refers to the sites as “hybrid-electric buildings”. Along with the battery itself, the sites are provided with demand management software and efficiency systems.

The storage will be used to provide utility grid services (to SCE) including flexible and reserve capacity, solar integration and voltage management. SCE will purchase capacity under 10-year capacity contracts to provide load reduction services as part of SCE’s plan to modernize the grid by 2022.

Retail energy service opportunities (i.e. values at the energy user sites) include demand management, back up generation and enhanced power quality. There is no up-front cost to users for the storage installations.

The total cost of the battery storage fleet is estimated at $200 million. Financing, led by CIT Bank, was confirmed in March 2017.

In addition to the long-term (10-year) capacity purchase contracts with SCE, the project involves contracted use guarantees from the large host customers of the project. It is these contracted guarantees that made the portfolio financeable in traditional markets, in a structure much closer to those used for solar energy development projects. CIT, Macquarie Capital and Advanced Microgrid Solutions called it the “first non-recourse project financing of a battery storage system”.


Market Context (SCE)

SCE’s grid area covers 15 million people:

The utility has been adding energy storage at a rapid rate following the shutdown of the Aliso Canyon natural gas reservoir in 2015. It is one of the largest reservoirs west of the Mississippi and the supply source for the power plants in the region. The shutdown followed a catastrophic rupture at a gas well in the reservoir in 2015, that released around 725 tonnes of methane into the atmosphere.

In addition to the Aliso Canyon incident, SCE was also motivated by the opportunity to offset power once produced by the decommissioned San Onofre nuclear power plant, as well as other soon-to-be retired (gas-fired) plants.

Overall, SCE’s grid modernization plan aims to add around 2.2 GW of newer, cleaner resources energy storage and renewables by 2022.

This distributed battery storage project is a first of its kind to replace utility power generation capacity as a peak load solution. Battery storage offers several benefits over traditional power sources: it is cleaner, responds faster and – as in this case – can be located directly at load centres. During peak demand periods, advanced energy management software enables the building load to be shifted from electric grid to battery power. In effect, some of the grid operator’s largest energy users become its cleanest, most efficient grid flexibility resource.

It was back in November 2014 that SCE announced the results of a competitive solicitation, of which this project was just a part. In total at that time it signed agreements for 250 MW of storage, despite only expecting about 50 MW of storage projects to be selected.


Market Context (Energy users)

AMS too has other storage projects in the pipeline, announcing for example (in April 2017) an “initial” 40MWh of battery-based energy storage across 27 Walmart stores in Southern California. Again, each system will reduce peak demand at the stores, emphasising that this appears to be the biggest driver for current commercial and industrial (C&I) energy storage sector in the US.

One AMS case study on a completed project for Morgan Stanley claims to reduce peak energy demand by 20%, using 0.5 MW / 1 MWh of storage. Demand charges can be a significant contributor to businesses electricity bills: spikes in demand can total up to 50% of a C&I electricity bill. Thus big reductions in peak demand can drive big reductions in electricity bills too.

By contrast, the key to adoption by utilities has been to drive costs down, which has meant scaling up beyond single building projects.

Aggregating multiple end-user sites together allows a developer to offer a large enough supply to interest the utility, along with the economies of scale to drive competitiveness. AMS describe their business plan approach as “designing the system for what the utility needs” while providing the host with “a no-hassle, cost-free upgrade to its energy profile, with batteries that are usually discharging during the same afternoon hours that coincide with peaks in commercial building energy use”.


Market Context (California storage mandate)

California has a strong RPS (renewable portfolio standard) benchmark of 33% of electricity retail sales by 2020. In October 2015, California’s ambition was extended to 50% by 2030.

In driving the rapid growth of renewable power capacity, the state started to encounter various challenges resulting from this. In particular, sources of power are susceptible to curtailment because solar and wind are unable to achieve the load-following characteristics required to match demand. As a result of solar power in particular, mid-day negative electricity prices are being encountered and more rapid daily load ramping requirements have emerged, needing spinning reserves or other stand-by power supplies to quickly match usage at the beginning and end of each work day.

Energy storage is one way to mitigate these problems. Rather than wait for the market to build it, California chose to kick-start the market by introducing a mandate (a bill known as AB 2514).

Adopted in 2010, the bill required California’s three largest power generating utilities to contract for an additional 1.3 GW of energy storage power generation (meeting certain criteria) by 2020 and to come online by 2024.

AB 2514 expressly excludes pumped storage hydro >50MW, so its real impact has been on “non-traditional storage” solutions. In particular, analysts have described it as driving “a new mindset in grid management” – beyond just storage – that has helped focus on localized solutions to localized problems: the “where” and “when” of power infrastructure rather than simply the “how much”.

In September 2016, four new laws (AB 2861, AB 2868, AB 33 and AB 1637) were introduced to California’s storage market. These laws:

  • improved conflict resolution procedures for interconnection disputes
  • directed utilities to consider energy storage as a distributed energy resource with benefits to the grid
  • directed the California Public Utilities Commission (CPUC), in coordination with the California Energy Commission (CEC), to evaluate the potential of bulk (long-duration) storage to integrating renewables into the grid
  • expanded funding incentives for customer-sited storage projects.

SCE has been particularly active in communicating to stakeholders and the public about the complexity of valuing storage. It has chosen to purchase more than five times the amount of qualifying storage required by California’s mandate.


[last update April 2017]


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