Navigant Research Blog

Distributed Energy Storage Deployments Driven by Financing Innovation, Part 2

— February 13, 2017

As highlighted in the previous post in this two-part series, the development of standardized power purchase agreement contracts by the National Renewable Energy Lab’s Solar Access to Public Capital Working Group has contributed to the continued growth of at-scale solar PV financing. Building on those solar PV standardization successes, Navigant Research is witnessing the development of new energy storage business models and financing instruments driven in part by contractual standardization. Navigant Research recently explored these new energy storage financing instruments in a recent research brief, Financing Advanced Batteries in Stationary Energy Storage.

A second type of standardized contract has emerged to help finance behind-the-meter distributed battery energy storage systems (BESSs). This new standardized contract focuses on aggregating BESS assets across multiple sites as a virtual power plant (VPP) to reduce energy demand.

Demand Response Energy Services Agreements

A demand response energy services agreement (DRESA) is typically executed with a local utility responsible for managing load on the distribution system by means of VPP technology. In this case, the utility compensates a third-party VPP owner for system availability (capacity) and actual DR energy storage services provided (performance). With a DRESA, the local utility can utilize the VPP for a defined duration for grid DR. But in most cases, the energy storage system owner or operator also promises to provide demand charge costs savings to hosts by means of a demand charge savings agreement (DCSA).

Advantages and Challenges for DRESAs

Key advantages of financing distributed BESS VPPs using a DRESA include:

  • The ability to deploy reliable DR assets in local power markets without upfront capital expenditures by either the local utility or the commercial and industrial (C&I) host facility
  • The ability for utilities to deploy reliable DR assets to optimize the local distribution system without the need to own and operate new storage assets

Key challenges facing the financing of BESS VPPs using a DRESA include:

  • The ability of BESS VPP software platforms to evaluate historical building load profiles and site-specific tariff requirements across large portfolios of C&I host sites to predict VPP deployment scenarios and project revenue.
  • The hardware/software complexity involved with integrating building load, onsite distributed generation, and building control across large portfolios of C&I host sites into VPP deployment strategies.

Standardized Approach to Quantifying Complexity, Risks, and Revenue

One can only imagine the complexity required to be addressed in these types of standardized agreements and technology deployment scenarios. For example, for a DRESA VPP application, the highest value will often be for the energy storage software system to leverage automated DR building efficiency technology to aid in reducing building load. Quite simply, installing and deploying this technology with some degree of battery energy storage capability will likely have a lower overall installed cost than deploying only larger batteries and inverters to do all the work.

Navigant Research can point to two examples where these issues have been sufficiently addressed, resulting in BESS VPP financing commitments:

As referenced in the previous post in this blog series, Navigant Research anticipates that standardized contracts such as DCSA and DRESAs will lead to the kind of financing innovation necessary to drive the deployment of distributed energy storage technology.

 

Distributed Energy Storage Deployments Driven by Financing Innovation, Part 1

— February 8, 2017

This blog is the first in a two-part series that will focus on innovative financing instruments that are being applied to deploy new distributed battery energy storage applications.

The growth of solar PV has been fueled in part by lower equipment and project development costs, but also by the development of standardized power purchase agreement (PPA) contracts. Without a standardized PPA contract, each new project looked unique to investors. This type of contractual uncertainty made investors’ ability to evaluate and finance projects at scale next to impossible. The introduction of standardized PPA contracts as part of The National Renewable Energy Laboratory’s multi-stakeholder Solar Access to Public Capital Working Group enhanced investor comfort levels by standardizing key contract terms and the approach to project revenue streams. These efforts resulted in the growth of an at-scale financing asset class that continues to drive solar PV technology deployment today.

Markets for the deployment of behind-the-meter (BTM) stationary battery energy storage systems (BESSs) are beginning to grow. Navigant Research recently explored the development of new BTM energy storage business models and financing instruments in its recent research brief, Financing Advanced Batteries in Stationary Energy Storage. Similar to the financing benefits delivered by a standardized solar PV PPA, several new standardized contracts have emerged enabling BESS financing. One such standardized contract focused on tariff-specific demand charge savings at commercial and industrial (C&I) facilities.

Demand Charge Shared Savings Agreements

A demand charge shared savings agreement (DCSA) mimics the contractual approach employed by energy service companies (ESCOs) to finance energy efficiency projects. An ESCO uses the cost savings from energy conservation measures like lighting or heating, ventilating, and air conditioning system upgrades to repay debt and equity partners. With a DCSA, the host and a third-party energy storage system owner or operator agree contractually on how BESS and load management software will be deployed during peak energy use to reduce demand charges. The financing partners depend on a portion of the cost savings from tariff-specific demand charge reductions to be paid by the host to debt and equity partners.

Advantages and Challenges for DCSAs

Key advantages of financing distributed energy storage technology deployments using demand charge savings agreements include:

  • The deployment of a BESS with no money down by the C&I host, thus eliminating the access to capital challenge.
  • The ability to bundle O&M costs for the BESS into a single transaction, eliminating the need for the C&I host to add staff or resources to manage the system.

Key challenges of financing distributed energy storage technology deployments using demand charge savings agreement include:

  • The ability of the BESS software platform to accurately evaluate historical building load profiles and site-specific tariff requirements relative to future load to generate project revenues.
  • The effect of future changes in building load profiles and tariffs on battery deployment assumptions and project revenues.

Quantifying Complexity, Risks, and Revenue

These contractual hurdles are being addressed today, despite the complexity. Navigant Research points to Green Charge Network’s commitment from Ares Capital in early 2016 for non-recourse project finance based debt funding as an example of where these issues have been sufficiently addressed, resulting in DCSA financing commitments.

Now that the ball is rolling on energy storage financing, the roadblocks facing energy storage projects don’t look so difficult. Navigant Research anticipates that these types of standardized contracts will lead to the financing innovation needed to drive the deployment of stationary energy storage technology.

 

Sweden Looks to Stimulate Residential Storage with New Subsidy

— October 31, 2016

Lithium BatteriesGreater interest in the benefits of distributed energy storage systems (ESSs) is growing out of successful deployments around the world. The leading markets for residential ESSs have all seen some level of government support (typically in the form of subsidies to reduce the upfront investment required). Joining a growing number of countries, the Swedish government recently announced a new subsidy program to support its residential ESS development.

There has been little energy storage market activity in Sweden to date; however, the country has set an ambitious goal to eliminate all fossil fuels used for electricity generation by 2040. Swedish officials hope that much of the new generation capacity will come from solar PV, and distributed ESSs will allow for a smooth integration while improving the Swedish grid’s resiliency. The new subsidy will be among the most generous in the world, covering potentially 60% of the cost to install a system, up to $5,600 per customer. The program is scheduled to run until the end of 2019, with a maximum $19.6 million budget that could result in 3,500 new systems and over 25 MWh of new ESS capacity.

Support Is Key

Residential ESS deployments to date have been heavily concentrated in four countries, each with some level of financial support for the technology. Navigant Research’s recent Residential Energy Storage report explores conditions supporting the market’s growth worldwide.

One of the largest markets to date has been Australia, where the country’s Capital Territory is looking to support 36 MW of new residential ESS capacity. Customers in that state can apply for a subsidy of $527 per kW of a system’s capacity, likely to cover around 20% of upfront costs.

Although the United States is emerging as a leading market for residential ESSs, nearly all systems deployed in the country are located in California. The state’s market is supported by subsidies through the Self-Generation Incentive Program, which was recently reformed and extended through 2019. The program has a  budget of $270 million, 75% of which is set to fund energy storage projects, with 15% specifically reserved for residential systems (less than 10 kw), providing approximately $600 per kWh of storage capacity. So far, the program has supported roughly 1.8 MW of residential ESS capacity, with another 7.5 MW in the pipeline.

Highlighting the geographic diversity of the residential ESS market, the two largest markets to date have been Germany and Japan, both of which have run subsidy programs for several years. After some debate about whether to continue the program, German officials elected to continue subsidizing residential ESSs through the end of 2018. That program may cover approximately 30% of a system’s cost when tied to solar PV.

Japan is home to the most generous residential ESS subsidy worldwide. The country’s Ministry of Economy, Trade, and Industry offers over $9,000 in incentives toward the installation of a lithium ion ESS for homeowners. Notably, this is the only subsidy targeting a specific battery chemistry, as the country looks to become a world leader in lithium ion technology.

Ready to Grow

Subsidies have been key for the residential ESS market to date, as the technology requires further decreases in costs to see widespread adoption. However, most subsidy programs will end before 2020 and are unlikely to be continued if battery system costs continue to fall as expected. Navigant Research expects that the residential ESS market will begin to see much more dramatic growth in the next 2 to 5 years as falling system costs combine with reduced solar PV incentives to greatly increase the value of these systems.

 

Pending Blackouts Highlight Benefits of Energy Storage

— June 2, 2016

Production Plant - NightConsequences of the largest natural gas leak in U.S. history continue to be felt across Southern California. The leak at the Aliso Canyon storage facility in Porter Ranch, California had a major impact on the local environment, forcing thousands of residents to abandon their homes and releasing the equivalent of the annual greenhouse gas pollution of 572,000 cars. While the leak has been stopped, the facility is now out of commission and the region faces a major shortage of natural gas, which could lead to 14 days of blackouts this summer and potentially 9 more in the coming winter unless action is taken.  The situation highlights the danger of relying too heavily on any one source of energy and is accelerating plans to transition to a system based on renewable energy.

What the Grid Needs

The potential blackouts this summer result in part from the shortage of gas supplies to fuel peaking power plants needed when demand spikes on hot summer days. In order to avoid widespread outages, the peak demand on the system needs to be reduced. Reducing the overall peak demand has been a focus of grid operators for year, and a number of solutions, including energy efficiency programs, demand response and energy storage systems, are being employed to meet this challenge. While these solutions all have their downsides (such as a low reliability or high upfront costs), the current situation in Southern California highlights the benefits of distributed energy storage systems in particular.

California is already a leader in the distributed storage market, and the threat of numerous blackouts may result in increased demand for these systems. As explored in Navigant Research’s Solar PV plus Energy Storage Nanogrids report, distributed storage systems can provide backup power during an outage (perhaps indefinitely when paired with solar PV) in addition to reducing electricity bills. While backup power is one of the main drivers of interest in distributed storage, these systems can provide much greater value to the grid as a whole. Storage systems aggregated into a virtual power plant can allow grid operators to reduce demand on the system at peak times, shifting energy usage to maximize the use of solar PV and limiting the need for gas-fired generation.

Central vs. Distributed?

As grid operators in California consider how storage can reduce the risk of blackouts, they are examining one of the key debates in the energy storage industry: Is it better to deploy centralized or distributed storage systems? While some of the issues facing the grid can be solved with centralized storage, distributed systems are being installed in increasing numbers without any action from utilities. Centralized storage systems won’t keep the lights on for customers in the event of a major outage and can take much longer to develop, an important consideration given the immediate need for new resources. Overall, it seems distributed storage systems are in the best interest of the California grid. While some customers get improved resilience, everyone benefits from the improved reliability that comes with these flexible assets on the grid.

 

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