Even though energy storage was one of the hottest topics in 2017, the industry has a long way to go before utilities recognize (and compensate) storage assets for all of the benefits they can offer.
Distributed energy storage systems have long been touted as the holy grail of grid modernization. After all, storage can be leveraged to address opportunities and challenges on both the customer and utility side of the meter. Setting aside cost and permitting considerations, batteries are, in theory, an eloquent solution to addressing the increasingly complex operational requirements of the electric power delivery system.
The flexibility provided by energy storage assets is largely due to the fact that storage can operate as a generator or load. In addition, advanced inverter capabilities can provide grid services such as reactive power and voltage control. However, locking in long-term financial certainty from multiple value streams on an energy storage application has remained a challenge, mostly because technological, performance, and cost breakthroughs have largely outpaced the requisite business model changes.
Some states are waking up to the unique benefits of energy storage. California, Oregon, and most recently New York have enacted procurement targets in recent years – often as complementary or compulsory initiatives for meeting ambitious renewable energy standards.
At the Federal level, the Federal Energy Regulatory Commission’s recent notice of proposed rulemaking on Electric Storage Participation in Markets Operated by Regional Transmission Organizations and Independent System Operators recognized that market rules designed for traditional generation resources may act as barriers to emerging technologies like energy storage.
While these federal and state initiatives are good signs that storage value is beginning to be recognized, energy storage installations today mostly consist of independent use cases focused on either behind-the-meter or grid-tied applications. California, for example, has the majority of behind-the-meter applications largely due to a combination of high distribution tariff demand charges and the incentives provided through the self-generation incentive program (SGIP). PJM has historically accounted for a significant amount of wholesale capacity thanks in part to modifications to frequency regulation compensation resulting from FERC Order 755 that ultimately led to market saturation.
Capacity is No Longer King
The utility distribution planning process has traditionally involved identifying potentially detrimental conditions on the grid and finding ways to solve them through utility-owned infrastructure or “wires” investments. Detrimental conditions can range from loss of load from equipment overloading and failures to more complex scenarios that result from the two-way power flow introduced by distributed energy resources (DERs).
Historically, utility investments were triggered by projected load growth typically informed by factors like new construction and service requests (often normalized to account for variance in weather). Marginal cost-of-service studies would then identify the costs associated with meeting these future needs. Marginal cost-of-service studies are a way of applying a standard measure for the cost of distribution infrastructure investments per unit of capacity ($/kW).
Typically, loading situations are encountered seasonally and last only a few hours per year and as such, spending a lot of money on a battery to resolve loading constraints has been difficult to justify economically when it is compared against traditional infrastructure upgrades – especially if the capacity of that battery is not utilized for other use cases. While there have been a number of utilities that have begun to explore energy storage in integrated resource plans (e.g., Portland General Electric) or via non-wires alternatives (e.g., Con Edison, Orange and Rockland), the inclusion of energy storage in business as usual distribution planning is still in its infancy.
The combination of flat or declining load growth in many places and the introduction of intermittent distributed generation sources like solar have introduced new challenges for maintaining a reliable grid including addressing voltage, power quality, and reverse power flow issues. This also means that in some instances, capacity expansion is no longer the primary driver of grid investment.
Today, even though most tariffs dictate penalties for failing to remain within utility-dictated operational parameters (e.g., injection of excess reactive power), resources like storage, which can correct these system attributes (e.g., achieving unity power factor), are seldom compensated.
Location-Based Tariffs – A Step in The Right Direction
Today, some utilities are working to refine their cost-allocation methodologies to more accurately value the contributions of investments on specific areas. For example, the value of distributed energy resource (VDER) tariff recently introduced in New York State is a composite form of compensation which combines energy, capacity, environmental, and location and temporally specific demand relief value (DRV) and locational system relief value (LSRV).
In California, investor-owned utilities have tested similar methodologies through the locational net benefit analysis (LBNA) process under the Distribution Resource Plan (DRP) and Integrated Distributed Energy Resource (IDER) dockets.
Although the components of the VDER and LNBA attribute more granular locational values, the fundamental issue remains that capacity/demand reduction value is only one of a myriad of benefits that batteries can provide. While these methodologies are clearly an indication of progress in accurately valuing DER, much work remains to align the operational flexibility of energy storage and other advanced technologies with distribution grid values.
Non-Wires Alternatives – The Near-Term Path for Storage?
If locational value tariffs are considered the blunt approach to DER valuation, non-wires alternatives (NWAs) should be considered the tactical and targeted way of providing certainty around the ability to monetize multiple applications by compensating third-parties for the ability to meet a system need. While many of the early solicitations for non-wires solutions focused on relatively simple loading constraints that could be met by traditional demand-side resources (e.g. demand response, energy efficiency, and non-load-following DG), the increasing number of constraints (e.g. loading, power quality, and voltage) identified in recent NWAs are well suited to the operational flexibility of batteries. However, these benefits are not without tradeoffs. For example, NWA solicitations are typically issued well in advance of operational needs, and third-parties cannot recognize revenue as quickly as projects which may be financed based upon existing tariffs today.
Tying It All Together with The Control Platform
An oft-overlooked challenge of balancing multiple use cases amongst stakeholders (utility, system operators, and third-parties) is the control software used to manage the schedule, commitments, and optimization of the battery. Managing the battery to meet multiple needs requires both preventative and corrective actions. Preventative actions that optimize the battery’s schedule are typically dependent upon forecast data, network model/status information — both of which can be subject to errors. Therefore, systems that rely only on preventative models are subject to larger, conservative operational margins to account for input variance.
Alternatively, when preventative methodologies are combined with corrective actions using real-time monitoring and control, much higher throughput can be achieved than solutions that rely purely on optimization. This joint approach allows each stakeholder to squeeze additional value out of the assets while satisfying the operational limits of the system.
Unlocking the value of energy storage requires recognition of the unique and concurrent benefits that storage can provide to the power delivery system. In many scenarios, this requires moving beyond compensating resources solely for historical use cases like capacity. It is critical that as tariffs and utility planning and investment methodologies evolve, appropriate mechanisms are introduced that recognize the unique attributes of this emerging resource class. Operationally, advanced, hierarchical control technologies will also undoubtedly play an important role in maximizing the value of these storage assets while ensuring continued reliability of the system.
Dr. Chad Abbey is an expert in renewables and DER integration and grid control and has held engineering, project management and consultancy roles with utilities and smart grid test centers. Zach Pollock leads business development for Smarter Grid Solutions in the North East.