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.

 

Overcoming Hurdles to Monetizing Value Streams from Energy Storage Systems

— August 19, 2016

GeneratorFederal Energy Regulatory Commission (FERC) Order 755 requiring regional transmission organizations (RTOs) and independent system operators (ISOs) to implement a pay-for-performance structure for frequency regulation service has been instrumental in demonstrating the benefits that fast-responding resources like battery energy storage systems (BESSs) can provide to the grid. For example, since Order 755’s implementation, PJM experienced a 30% reduction in overall regulation reserve requirements as more fast-responding resources have cleared the market. However, despite the early regulation successes in PJM, storage directly connected to a distribution system (known as front-of-meter, or FTM) continues to faces uncertainty and barriers in the United States associated with rate treatment.

On another front, energy storage stakeholders now recognize that BESSs connected to the distribution system from behind the meter at a residential and/or commercial & industrial customer’s property can deliver benefits to the host, RTOs/ISOs, and utility distribution system operators. This evolution is driving the development of software and hardware platforms that can analyze, control, and optimize not only a single BESS, but also aggregated BESSs. These advances are now giving rise to energy storage assets that can recognize multiple value streams by stacking grid benefits in virtual power plants (VPPs).

Regulations and Requirements

However, regulatory eligibility and performance requirements for aggregated behind-the-meter battery energy storage assets have not caught up with these technological advances. To date, there has been limited participation by energy storage in demand response markets, and several instances demonstrate how wholesale market rules are missing opportunities for these assets to provide multiple grid benefits. For example, the CAISO Proxy Demand Resource (PDR) prohibits a VPP from providing frequency regulation, even though the systems would be technically capable of doing so. And in ISO-NE and NYISO, Northeast Power Coordinating Council rules prohibit behind-the-meter energy storage from providing spinning/synchronized reserves.

At the Energy Storage North America (ESNA) expo in October, a panel discussion will feature case studies from across the country on the challenges, feasibility, and economics of how single BESSs and VPPs can stack energy storage value streams. Don’t miss out on the conversation—register for ESNA today.

 

Tesla and SolarCity: Is Financing a Bundled Clean Energy and Transportation Service on the Horizon?

— July 8, 2016

Electric Vehicle 2Tesla’s recent announcement that it intends to acquire SolarCity was an unprecedented Energy Cloud trifecta. It’s not easy for a single release by one company to stir the interests of three separate sets of passionate stakeholders tracking transformative clean energy and transportation technologies and business models. And rightly so, as the potential for Tesla to pair vehicle electrification with solar and advanced battery energy storage as integrated distributed energy resources (DER) is an eye-opener to say the least.

Tesla’s vehicle and battery manufacturing businesses are very different than SolarCity’s solar business, both technically and revenue model-wise. It will likely be a challenge for the company to explain these separate businesses to its investors and manage expectations. One could argue that Tesla might be better off focusing 100% of its efforts on building out the Model 3 and Nevada Gigafactory battery manufacturing capacities in the short term.

The DER Standpoint

But from a DER technical standpoint, it’s intriguing to consider the possibility of what the new Tesla could do. For example, the new Tesla could couple the energy capacity of plug-in electric vehicle (PEV) batteries with solar, PEV charging infrastructure, and virtual power plant (VPP) software all at the home of a single customer. It’s not hard to envision how this type of arrangement could serve both as DER and an overnight revenue source to utilities. The new Tesla indicated that it plans to continue to partner with utilities, which are increasingly interested in aggregated behind-the-meter demand response capacity. And SolarCity’s recent efforts to partner with utilities in New York on a new program to eliminate net metering along with the company’s recent hiring of former Federal Energy Regulatory Commission (FERC) Chairman Jon Wellinghoff as Chief Policy Officer demonstrates a willingness to pursue such new and innovative business models.

Going to Market

But how might the new Tesla take this sort of concept to market? A key aspect of technology innovation in renewable energy has been financing innovation. The development of power purchase agreement financing has been instrumental in the growth of solar PV. Navigant Research believes that financing innovation will also drive energy storage markets over time, as well.

But the new Tesla could be uniquely positioned to apply financing innovation to an integrated solar battery PEV-based VPP while also providing consumers with the use of the vehicle. Imagine a homeowner entering into a 15-year financing agreement for solar, energy storage, and use of a Tesla Model 3 under a single contract. In this scenario, the new Tesla/utility partner manages the VPP asset while the customer gets access to, but not ownership of, a Tesla Model 3. If the new Tesla/utility partner decides to extensively use a Model 3 battery as part of the VPP, then the homeowners get a new Tesla battery. In this scenario, the long-term assumptions on VPP revenue, replacement batteries, or even new vehicles and solar storage benefits are bundled under one customer-facing agreement.

This type of integrated financing innovation might sound challenging. But I can guarantee that a trifecta (or more) of interested Navigant Research teams will be closely tracking if and how the new Tesla comes together.

 

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