An EPRI-led working group develops methods for grid operators to enable grid services from distributed energy resources
One of the most obvious manifestations of the energy transition is the huge amount of distributed energy resources (DERs) being integrated into the distribution grid. For example, U.S. energy storage capacity tripled in 2021, according to the U.S. Energy Information Administration. Though most of the new capacity was grid-scale, distribution system storage is also on the upswing. And while overall solar installations fell 24 percent in the first quarter of 2022, residential photovoltaics (PV) systems enjoyed their largest quarter in history.
The adoption of DERs is likely to accelerate, thanks to technology improvements, competitive pricing, and supportive policies and regulations. The recently passed Inflation Reduction Act provides long-term federal incentives for both energy storage and solar. An example of a state-level policy is New York’s Climate Leadership and Community Protection Act, which targets an emissions reduction of 85 percent from 1990 levels by 2050.
Equally important is the Federal Energy Regulatory Commission (FERC) issuance of Order 2222 in 2020. Order 2222 requires independent system operators (ISOs), transmission system operators (TSOs), and regional transmission operators (RTOs) to establish rules to allow full DER participation in wholesale capacity, energy, and ancillary services markets. In announcing the order, FERC said it was “a new day for distributed energy resources.”
DER Scale Demands Coordination
For distribution, transmission, and independent system operators, the growing influx of DERs presents opportunities to leverage a new type of resource to benefit the power system. At the same time, DERs can pose real challenges to power system resilience and reliability. Increasing levels of DERs also challenge distribution system operators (DSOs) and ISOs/RTOs to coordinate and optimize their management. As more and more DERs become operational and start delivering services to both wholesale markets and the distribution system, that need for coordination will only increase.
Unfortunately, there is no legacy of coordination to build on. “ISOs approach problems in the bulk power system in their own world, which is at the transmission level,” said Ajit Renjit, Smart Grid Engineer at EPRI. “Distribution utilities approach their problems purely from the perspective of the medium- and low-voltage networks which they operate. The need for coordination has never existed.”
DER aggregators are key stakeholders in this conversation about coordination. By aggregating DERs, they reduce the total number of individual solar, storage, and other DERs that need to be managed – a complex task, given the unique operational characteristics of different types of DER. Aggregators use control systems to abstract the complex capabilities of many DERs and present them as a simple, more manageable set of grid services to the grid operator.
In other words, aggregations of DERs can be managed much like a large power plant. “That is what the bulk market operator wants. They don’t want to talk to individual devices. They want to talk to one virtual plant that is large enough to provide a necessary service to the bulk system,” Renjit said. Under ISO market rules, DERs must have a minimum capacity to be eligible to participate—a threshold few individual devices can reach.
A Unique EPRI Working Group
In 2019, EPRI convened a working group that met weekly to facilitate TSO and DSO coordination discussions. The group included ISOs/RTOs, DSOs, DER aggregators, regulators, national research laboratories, academics, and others. Its work took on new urgency after FERC Order 2222 required wholesale market operators to develop rules enabling DER participation. The working group’s goal was to establish a framework and document a menu of coordination functions that would enable DERs to provide grid services.
Coordination functions can be defined as the expected actions, responsibilities, and data exchanges of two or more parties that perform a function or sequence of functions cooperatively. Major drivers for coordination are to maintain reliable system operation and to quantify the value of services provided by DERs. “Reliability is a problem when DERs start participating in the wholesale market and distribution utilities don’t have visibility into the operation of DERs following wholesale market signals,” Renjit said.
Valuation is also a nettlesome challenge. For example, many solar PV systems participate in net metering programs with their local utilities. Soon, those same PV systems may have the opportunity to provide services to the bulk system. “Without proper coordination methods, the same DER may get double counted for a service and could wrongly be compensated twice,” Renjit said. “A common framework needs to be established so DSOs and ISOs/RTOs can agree on how a DER asset will be used and compensated. The framework could determine that the DSO will use the DER services for a certain period, and then the ISO will use them. Or the DSO and ISO could each use 50 percent of the DER’s capability.”
The Building Blocks of a Framework
Earlier this year, EPRI released the TSO-DSO Coordination Functions for DER report, resulting from the working group’s years of effort. The report is a comprehensive menu of information, controls, and monitoring interactions and functions that can be assembled to create a coordination framework suited to an individual region’s rules and market conditions.
Besides developing a resource that acknowledges regional differences, the report recognizes that each entity involved with coordination has its own unique roles. “With this broad list of functions, one can build a framework considering each stakeholder’s unique roles and responsibilities under a particular jurisdiction. That’s the most important takeaway of this work,” Renjit said. “The regulatory framework in every state is going to define what the framework can and cannot include.”
The functions developed are also grouped based on the timeframe when they are likely to be relevant. For instance, some functions may be important in the context of a day-ahead or real-time market, while others are critical after a service has been provided to the bulk market for settlement.
The working group also addressed how ISOs/RTOs, DSOs, and DER aggregators actually apply the functions to develop the foundational technologies for coordination. “By specifying the roles and functions of a DSO or a bulk market operator or an aggregator, the work provides them the guidebook to specify requirements and design the planning and operational tools to make it work,” Renjit said.
The Road Ahead
A significant amount of work still needs to be completed to improve TSO-DSO coordination. For instance, DSOs need new capabilities, such as DER management systems (DERMS) and upgraded back office systems, to ensure reliable system operation when DERs are enabled to provide grid services. Utilities should also update their DER interconnection practices to determine the impacts of DERs providing grid services to the bulk system operator. Rules need to be in place to manage DERs equitably when they violate the operational limits of the distribution system and also to value the services they provide.
As ISOs and DSOs prepare to implement the requirements in FERC Order 2222, a major question of what constitutes a successful coordination framework still exists. EPRI’s ongoing work will provide guidance for selecting and developing these new frameworks by determining the benefits and limitations of various options. This includes asking questions about the cost and complexity of a DERMS or distribution management system, fully grasping how complex and frequent communication between aggregators and ISOs and DSOs needs to be, and determining how much connectivity is required to enable each framework.
Over the next year, EPRI will update its bulk market and DSO operational modules to integrate and manage DER aggregations. “We are going to upgrade our existing ISO and DSO tools to include DER management capability,” Renjit said. “This helps us study the benefits and limitations of different TSO-DSO coordination frameworks when DERs provide grid services. By the end of next year, we will have some interesting resources to share.”
EPRI Technical Expert:
Ajit Renjit
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