This article first appeared in POWERGRID International.
The rapidly expanding market for energy storage has historically been segmented by use case and the stakeholders poised to benefit from the application of these use cases. Particularly for distribution utilities, who are in de-regulated states and do not own generation, energy storage is viewed as a potential solution for solving a specific and oftentimes specialized engineering problem, and economics are evaluated secondly (and against typical utility infrastructure investments). Conversely, the use cases for behind-the-meter energy storage are normally driven by some combination of cost saving opportunities and revenue generation (typically through demand response or frequency regulation). Despite the maturity of these early use cases, on both the utility and customer side of the meter, these benefits are finite and the opportunities are fleeting at best. Today these investments are developed in parallel, not fully realizing the complementary benefits that may be shared by distribution utility and customer driven use cases.
From a utility perspective, deploying battery storage on circuits projected to exceed capacity ratings as an alternative to circuit reconductoring or new substation construction have been key utility use cases, but typically do not pencil out compared to traditional “wires” investments. However, the benefits of these capital deferrals and mitigations are often based on principles of regulatory accounting, and may not be a straightforward assessment which allows the full value of the storage resource to be captured due to the fact that frameworks typically limit concurrent benefit realization – particularly if these benefits accrue across multiple stakeholders. By way of traditional accounting methodology, using storage to solve a specific technical issue, which may occur for only a few hours a year, is leaving additional value on the table during the times when that problem does not exist.
Battery storage is increasingly being considered as an alternative to mitigate impacts of intermittent distributed energy resources like solar photovoltaics (PV). As the grid transforms to accommodate more distributed, bidirectional and intermittent power flow, distribution system engineers will need to first identify the issue at hand and then pick from an increasing toolkit of solutions to mitigate it. As the costs of energy storage continues to decline, it is likely that storage will become a more viable solution in a portfolio of options but it is also important to note that solutions can be provided by other emerging technologies including smart inverters and power electronics devices. Hence, there is no guarantee that cheaper storage alone will lead to more deployment as many industry analysts have speculated.
In an ongoing effort to promote innovation and stimulate the commercial deployment of the technology, some U.S. states have passed legislation which requires utilities to procure cost-effective energy storage. California’s monumental mandate for its investor owned utilities to procure 1.3 gigawatts of energy storage set a precedent and spurred massive activity in the industry. Oregon followed suit with a much smaller requirement of 5 MWh for each investor-owned utility to have in service by the beginning of 2020. Most recently, Massachusetts Gov. Charlie Barker signed into law H. 4568, which could make the state the first in the east to have a utility scale energy storage procurement requirement. These bills are certainly key enablers for the industry, and should be evaluated by other states to assess how they may fit into their overall grid modernization and energy policy objectives in the short-run. However, these mandates do not necessarily provide long-term certainty and may also serve to confound pure project economics.
On the customer side, use cases for behind-the-meter energy storage are dictated predominantly by economics stemming from avoided costs or revenue generation opportunities that are presented by demand-based rate structures. In some instances, such as utilizing storage for demand response, benefits may be composed of both of these benefit streams. The principal value proposition for commercial customers is straightforward – electricity bill savings through demand charge reduction or time-of-use rate optimization. Still, these use cases are inherently opportunistic and there is no guaranteed long-term certainty around their benefits.
Conversely, as utilities continue to modify their residential rate structures, residential energy storage will become more economically viable through TOU rate optimization and demand charge management. Institution of residential demand charges or reducing net metering excess generation to wholesale rates bolster the business case for pairing storage with existing solar systems. Hawaiian Electric (HECO) recently had its first customer “self-supply” PV system go online, which allows customers to draw power from the grid but does not provide compensation for selling back to the grid for net excess production, as is the case with most traditional net metering tariffs. With Maui having already reached its “grid-supply” net metering cap and Oahu and the Big Island close to 70% of allotted capacity, it is expected that more customers will chose the “self-supply” option and pair it with energy storage systems to bolster the business case.
In certain states, the economics of energy storage can be enhanced by subsidies and incentive programs. A prominent example of a subsidy for distributed energy storage is California’s Self Generation Incentive (SGIP) program, which provides incentives for both qualifying commercial and residential systems. Recently, customers have increasing opportunities to realize additional revenue through providing grid services. Regulatory and market reform promoting aggregation of distributed energy resources for grid services has been ongoing in places such as Texas, New York, California, and others. However, these opportunities are immature and are small in comparison to the revenue streams which exists for traditional generators.
On the wholesale side, market opportunities for energy storage have been small, finite niches of the ancillary services markets in a select few regions, most notably PJM’s frequency regulation market. As of April 2016, PJM had a total of 246 MW of interconnected battery storage projects. Motivated by FERC Order 755, which directed market operators to better compensate fast responding resources, PJM provided significant clarity to project developers through its establishment of the dynamic regulation market (RegD). In turn, this has recently led to increased competition and saturation amongst market participants. In the broader wholesale markets, the current low commodity price environment has made storage significantly less competitive in comparison to traditional fossil fuel alternatives. The lower marginal cost to run these generators for meeting peak demand creates a much smaller spread between and on and off peak prices, diminishing arbitrage revenue.
Other market operators have actively been trying to develop products to appropriately compensate storage resources for the value they can provide, yet reaching consensus among stakeholders and developing these services has been a slow process. In August 2011, CAISO began a stakeholder initiative to design a flexible ramping product, which was intended to allow the ISO to procure sufficient ramping capability via economic bids. The amended tariff was filed with FERC on June 4, 2016 and is currently awaiting approval. Additionally, the CAISO is currently exploring a flexible resource adequacy initiative which would allow storage to provide flexible capacity.
In the case of third parties developing and financing these projects, it is challenging to build a strong investment pipeline based on traditional contracting mechanisms or merchant market participation. This issue is in part due to inherent technology cost risk, but also because there is a lack of wholesale market products that compensate energy storage for the services it can provide.
Energy storage is a unique resource, in that it can provide capacity, energy, and ancillary services to the grid irrespective of its physical location. However, the engineering constraints of making a system simultaneously available to provide all of these services – under a particular contract structure – are substantial. These business realities coupled with regulatory hurdles make the ability to stack energy storage value streams difficult in practice, leading to the storage owner or developer not being able to monetize the asset to its technical capability.
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The following recommendations address some of the unique economic and engineering challenges that characterize energy storage which will need to be solved to move the market forward, taking into consideration the priorities of utilities, developers and customers.
The market for energy storage has developed in parallel over the last few years with use cases both in front of and behind-the-meter motivating different investment opportunities. Simultaneously, several regulatory and market initiatives are underway which clearly acknowledge that grid modernization will be an encompassing process inclusive of customers and other historically passive stakeholders. This convergence of stakeholder interests will require extensive collaboration between all parties involved in order to maximize cost-effective energy storage investments, with consideration given to the utility regulatory model of the state in question. Ultimately, the prevailing energy storage business models of the future will be those that realize its full technical and economic potential. Critical to achieving this will be clearly identifying complementary and mutually exclusive use cases and ensuring these tradeoffs are evaluated in a transparent, repeatable process which may enable sharing these benefits across multiple stakeholders.
Alex Pischalnikov is an energy and utility expert at PA Consulting Group