By Alex Pischalnikov and Zach Pollock, PA Consulting Group
The rapidly expanding market for energy storage has historically been segmented by use cases and the stakeholders poised to benefit from the application of these use cases. Many distribution utilities in deregulated states that do not own generation view energy storage as a potential solution for solving a specific and oftentimes specialized engineering problem. 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, the benefits are finite and the opportunities are fleeting at best. 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 they typically do not pencil out when compared to traditional “wires” investments. The benefits of these capital deferrals and mitigations, however, are often based on principles of regulatory accounting and might not be a straightforward assessment that allows the full value of the storage resource to be captured. This is because 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, leaves 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 (DER) like solar photovoltaics (PV). As the grid transforms to accommodate more distributed, bidirectional and intermittent power flow, distribution system engineers must first identify the issue at hand and then pick from an increasing toolkit of solutions to mitigate it. As the costs of energy storage decline, it is likely that storage will become a more viable solution in a portfolio of options. It is also important to note, however, 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 technology’s commercial deployment, some states have passed legislation that requires utilities to procure cost-effective energy storage. California’s monumental mandate for its investor-owned utilities (IOUs) to procure 1.3 GW of energy storage set a precedent and spurred massive activity in the industry. Oregon followed suit with a much smaller requirement for each IOU to have 5 MWh in service by the beginning of 2020. Most recently, Massachusetts Gov. Charlie Barker signed into law Bill H. 4568, which could make the state the first in the East to have a utility scale energy storage procurement requirement. These bills are 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. These mandates do not necessarily provide long-term certainty, however, and may 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 presented by demand-based rate structures. In some instances, such as using 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 do not guarantee long-term benefits.
As utilities modify their residential rate structures, residential energy storage will become more economically viable through time-of-use (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 Co. (HECO) recently had its first customer “self-supply” PV system go online. The self-supply system 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 percent 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 Program (SGIP), which provides incentives for both qualifying commercial and residential systems. Recently, customers have more opportunities to earn additional revenue through providing grid services. Regulatory and market reform promoting aggregation of DER for grid services has been ongoing in places such as Texas, New York, California and others. These opportunities are immature, however, and are small in comparison to the revenue streams that 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 among 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. Reaching consensus among stakeholders and developing these services has been a slow process, however. In August 2011, California Independent System Operator (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. In addition, the CAISO is exploring a flexible resource adequacy initiative that would allow storage to provide flexible capacity.
In the case of third parties developing and financing these projects, building a strong investment pipeline based on traditional contracting mechanisms or merchant market participation is challenging. 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. The engineering constraints of making a system simultaneously available to provide all of these services under a particular contract structure, however, are substantial. These business realities coupled with regulatory hurdles make the ability to stack energy storage value streams difficult in practice, and does not allow the storage owner or developer to monetize the asset to its technical capability.
The following recommendations address some of the unique economic and engineering challenges that characterize energy storage. These challenges must be solved to move the market forward, taking into consideration the priorities of utilities, developers and customers.
• Utilities should take a cross-functional approach to developing a storage deployment strategy, soliciting expertise across the organization to build a unified plan to pilot, analyze, iterate and, finally, install storage at scale. They must consider where it is needed across the service territory and by which stakeholders (including customers).
• Utilities should evolve the “emerging technology” groups that many have formed to develop technology adoption strategies that are then transferred to the broader organization. Some utilities have created proprietary methods of evaluating and deploying energy storage by working with various technologies, developers and use cases. Duke Energy and Southern California Edison are good examples of companies with mature capabilities in this area.
• Distribution utilities should design and pilot programs that incentivize customers to both install and allow utility control of behind-the-meter energy storage. Although regulatory constraints exist in certain jurisdictions, the utility is well-suited to balance a portfolio of behind-the-meter resources to meet grid needs. Whether this is achieved through direct control of the resource or compensates the customer for performance, these types of solutions are beneficial to all parties and are indicative of the level of collaboration required between utilities and developers to fully monetize energy storage’s value.
POLICY AND REGULATION
• State legislatures and PUCs should thoroughly examine the potential of energy storage to lower energy costs, improve resiliency and enable grid modernization initiatives. Driven by this analysis and guided by lessons learned from California and Oregon, policymakers may choose to design their own utility procurement programs to expedite adoption and commercialization.
• Due to regional market differences for distribution utilities, distributed storage and other DERs are compensated differently across various areas, making it difficult to assess storage cost and performance metrics uniformly and develop standardized market rules and tariffs. This can be partially addressed by standardizing around a set of ancillary services across metrics, where performance metrics may vary over time but the long-term goal of the services remains consistent (e.g. outcome-based performance).
• Regulators should take a lesson from the solar industry and seek to avoid conflicting and polarizing policy decisions. As has been observed from state debates over net energy metering (NEM) policy, lack of uniform policies inhibit developers and financiers from providing certainty to customers. Similarly, bespoke regulation can slow commercialization of energy storage technologies. While state-level policy will never be unified, regulators should collaborate to identify aspirational polices across states that are directionally consistent and includes stakeholder feedback.
• To further the adoption of distributed energy storage, targeted, transparent and predictable incentives should be developed for both residential and C&I customer segments. The recently redesigned California Self-Generation Incentive Program (S)GIP may serve as a model for states that wish to promote battery storage installations.
CONTRACTING AND VALUATION
• An industry standard method is needed to evaluate accepted ways to assess how value streams can be prioritized and realized. This includes quantification of nonstandard benefits provided by energy storage, which may include reliability and environmental benefits.
• A standardized and transparent energy storage contracting process is needed to help all parties involved better understand expectations and commitments. Developing a set of essential terms and provisions similar to those established in the Edison Electric Institute (EEI) Master Contract or International Swaps and Derivatives Association (ISDA) Master Agreement would in turn help mitigate uncertainty and unlock financing options, making more storage projects possible. San Diego Gas & Electric has made its standard energy storage power purchase agreement publicly available online, which has helped set expectations and expedite negotiations when an award has been granted.
• Common standards for integrating batteries and balance of system components should be developed to allow for easier, faster and more cost-effective deployment. The Modular Energy Storage Architecture (MESA) Alliance represents significant strides in bringing stakeholders together to create a nonproprietary set of specifications and standards, with notable members including Duke Energy, Parker Hannifin and LG Chem, among others. More efforts like these are needed to promote interoperability of components while giving insight into measuring the performance of batteries and energy storage management systems.
• Mature energy storage software system capabilities are needed to realize the full value that these assets can deliver. In particular, applications that can integrate measuring asset operational performance with load forecasting and rate impact modelling can offer significant value to utilities or developers.
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 that 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. Consideration must be 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 expert at PA Consulting Group specializing in electric utility operations, regulation, distributed energy resources and smart grid technology. Pischalnikov has assisted both investor-owned and municipal utilities in strategic planning, operational performance improvement and deployment of new technologies. He is based in Los Angeles and regularly develops rate and regulatory analysis on California’s energy sector.
Zach Pollock is an experienced consultant with over five years of research and advisory expertise in the energy industry, particularly electric utilities and clean technology. He has authored several industry leading reports on grid modernization initiatives including advanced metering infrastructure, data and analytics and distributed energy resources. Pollock advises utility clients, equipment manufacturers and software providers.