Energy storage as a service
Under efforts to understand the global energy storage as a service market and an increasing move among energy providers to employ energy storage as a service, the Metering & Smart Energy International team spoke with Doug Staker, vice president of global business development at Demand Energy.
Staker defines energy storage-as-a-service as the deployment of energy storage (behind the meter for C&I customers) under a fee for service, shared savings or management model other than a direct purchase of the asset by the end customer.
Energy storage has been shown to be cost competitive with a wide range of resources and solutions on both the utility and customer side of the meter; and a study conducted by the Smart Electric Power Alliance (SEPA) found that of utility-scale energy storage capacity was added onto the US grid in 2016.
The study, the 2017 Utility Energy Storage Market Snapshot, found that increases in the adoption of energy storage is being driven by utilities’ increased efforts to secure energy supply by integrating more distributed renewable energy resources into grid networks. Moreover, a decrease in the cost of lithium-ion batteries is also playing a leading role in the growth of the market.
Tanuj Deora, SEPA’s executive vice president, said: “The primary opportunity is for market players (utilities, regional transmission organisations, distribution system operators, regulators, third parties, etc) to work together to develop tools and policies to identify and value precisely the variety of value streams that can be stacked to support energy storage deployment.” However, the cost of such deployments for smaller utilities or C&I customers can be prohibitive and this is where energy storage as a service (ESaaS) provides the benefits of an energy storage system without needing to outlay the significant CAPEX costs.
Energy storage systems provide a range of services to generate revenue, create savings, and improve electricity resiliency. The operation of the ESaaS system is a unique combination of an advanced battery storage system, an energy management system, and a service contract which can deliver value to a business by providing reliable power more economically.
Most commonly used for ESaaS are lithium-ion or flow batteries, mainly due to their size, their high efficiencies and fast reaction times, but other methods of storage – flywheels, compressed air or pumped hydro – can also be used.
ESaaS systems are remotely monitored and controlled using a SCADA system which communicates with the facility’s energy management system, power conversion system and battery management system.
The system operator is responsible for monitoring and responding to the facility’s needs as well as overriding commands to participate in regional incentive programmes such as coincident peak management and demand response programmes in real time.
The case for ESaaS
The grid is aging and in need of significant upgrades. The integration of renewables and other distributed generation has created new challenges and opportunities, and the historical utility business model of building to the ‘peak’ is no longer accepted by the public utility commissions that oversee and regulate utilities. With recent storms and other extreme weather events, resilience is growing in importance.
In developed markets like North America, market opportunities are driven by tangible market factors, such as the peak load challenge in New York City. This has helped drive the state’s Renewing the Energy Vision (REV) initiative and the focus on identifying non-wire solutions to significant capex investments in new substations and distribution grid infrastructure. This is also true in California and Hawaii, where significant deployment of renewables (solar and wind) has created a different set of challenges for managing the grid.
In emerging markets like Africa where 600 million people don’t have reliable power, the opportunity is to deploy distributed and resilient microgrids with renewables and energy storage.
Without question, energy storage-as-a-service makes absolute sense where there are grid infrastructure challenges, rate structures and regulatory drivers that allow a strong business case for the deployment of storage to save end customers money and provide grid support for the utility.
According to Staker, C&I customers are increasingly reconsidering their approach to managing their energy expense and seeing the benefits of alternatives. Forward-thinking customers are looking to reduce their total energy expenditures, while minimizing capital investment (financing flexibility).
In a world of growing complexity when it comes to managing energy resources, it is often best to have such operations managed by an expert partner.
The leading benefit would be the conservation of capital and reduction of risk that would encourage customers to take advantage of a faster path towards deployment of energy storage and other distributed systems.
An additional advantage is the significant reduction in risk of operating these complex systems. The aggregation of energy storage with solar, CHP, fuel cells and other energy management measures requires a sophisticated software controls platform and deep expertise to implement these dynamic business cases. This is not a core competency of most commercial/industrial businesses and is best delivered under a managed service agreement.
Energy storage is a remarkably flexible resource that delivers a wide range of benefits on both sides of the utility meter and across the electricity grid. To optimize the full range of value streams to an end customer (behindthemeter) and to the grid requires a mutually beneficial service model. This is best provided under an ‘as-a-service’ structure that can build a viable business case, delivering value to multiple entities through a business model that can be financed by a third party.
Certainly the ‘as-a-service’ model does not require the energy storage asset to be financed. For some customers, the right approach might be a direct purchase with a managed service agreement to operate the energy storage system and other DERs to deliver optimal long-term value. To properly manage and optimise the returns of these systems, an intelligent control system can be instrumental.
Factors driving the market
Grid infrastructure challenges from aging infrastructure and significant deployment of renewables are key factors driving the market. These markets often have significant incentives and other programmes that strengthen the business case for energy storage delivered as a service.
Markets where recent natural disasters like Hurricane Sandy in New York, as well as the recent storms in Houston and Florida, are reminders of just how valuable resilience is – and are helping to focus attention on grid-connected microgrids with energy storage.
Rate structures with high rates for demand charges to C&I customers (NY, NJ, CA, etc) are also creating real opportunities to save money.
Factors having a negative influence on the market are a) uncertainty at the national policy level (i.e. FERC) and b) variability across state public utility commissions that oversee utilities, down to the authorities having jurisdiction (AHJs) that exercise control over the permitting and approval of new systems being interconnected at the local level.
A final factor impacting the market is the ability to finance these kinds of projects. The lack of an investment tax credit for storage is a challenge. When combined with perceived risks at the policy level over rate structures and adoption of DERs and other distributed energy assets, it makes it hard to attract investment capital.
Recommendations to boost the market
Utility rate structures that recognize that the cost of electricity has a locational and time-of-use (TOU) component are important to boosting the uptake of storage. These TOU rates are most common in New York and California.
