TODAY’S STUDY: Connecting Customer-sited Resources To The System
An Overview of Distributed Energy Resource (DER) Interconnection: Current Practices and Emerging Solutions
Kelsey Horowitz, Zac Peterson, et. al., April 2019 (1 National Renewable Energy Laboratory, Interstate Renewable Energy Council, Electric Power Research Institute, Florida International University, Smart Electric Power Alliance)
Motivation, Purpose, and Intended Use
Deployment of distributed energy resources (DERs), in particular distributed photovoltaics (DPV), has increased in recent years and is anticipated to continue increasing in the future (GTM 2017, Labastida 2017). The increase has been particularly significant on certain systems. Figure 1 shows an example of a rapid rise in the number and capacity of DER with net-energy metering (NEM) for two different systems in Missouri and South Carolina.
As DER deployment grows, there is a need for utilities and regulators to understand considerations for interconnecting these resources to their systems as well as different solutions that may be suitable given their DER penetration levels, system characteristics, capabilities, and organizational structures.
This report from the Distributed Generation Interconnection Collaborative (DGIC) was commissioned based on the need—identified through DGIC—for a central document summarizing considerations, practices, and emerging solutions across a broad set of topics related to DER interconnection. The report is targeted at a high-level, strategic-planning audience at utilities who are seeking an overview of DER interconnection issues and approaches and looking to understand how these may relate to their own situations. The audience includes a broad set of utilities and situations, including investor-owned utilities (IOUs), municipal utilities (munis), and cooperatives (co-ops) with a range of current DER penetration levels.
This report complements existing resources, including more detailed research reports on specific interconnection-related topics (e.g., Coddington et al. 2012b; Parks, Woerner, and Ardani 2014), in-depth handbooks or reports on a specific interconnection-related topic (Seguin et al. 2016), as well as the recently published “New Approaches to Distributed PV Interconnection: Implementation Considerations for Addressing Emerging Issues” (McAllister forthcoming), which is geared more at a policymaker audience and provides a more detailed review of interconnection practices at utilities and states. It also provides a broader perspective and some forward-looking information not contained in interconnection handbooks or guidebooks provided by some utilities (e.g., PG&E 2017b), which provide details of current interconnection policies and procedures of individual utilities relevant to interconnection applicants.
Although some areas of interconnection have established standards, many are still nascent with no clear or accepted best practice. Additionally, the practice most suitable for a given situation will vary depending on the level of DER penetration; the utility, customer, and developer characteristics and preferences; the attributes of the electrical power system; and other factors. This report does not seek to recommend or dictate practices in any of these areas, but rather provides an overview of the status of different aspects of interconnection, existing standards, and emerging solutions currently being explored that can inform utility planning and decisions. Some of this information may also be useful to regulators, policymakers, and DER developers seeking to understand barriers to interconnection, potential solutions currently being explored, and ways to work with utilities on interconnection policies.
DERs are resources connected to the distribution system close to the load, such as DPV, wind, combined heat and power, microgrids, energy storage, microturbines, and diesel generators. Energy efficiency, demand response, and electric vehicles are also sometimes considered DERs. These resources may be deployed individually, co-located, or aggregated and in some cases jointly controlled. According to the National Association of Regulatory Utility Commissioners (NARUC), these resources “can either reduce demand (such as energy efficiency) or provide supply to satisfy the energy, capacity, or ancillary service needs of the distribution grid” (NARUC 2016). DPV, wind, and energy storage may be behind-the-meter (BTM) or in front-ofthe-meter (FTM) and utility owned, customer owned, or third-party owned, although very little BTM wind and energy storage capacity is installed to-date. Some states, like Hawaii, have been dominated by deployment of small residential and commercial rooftop DPV systems (typically 1–200 kW in size), while others, like North Carolina, have seen more large, ground-mounted DPV systems ranging in size from several hundred kW to several MW that are not primarily sited to serve a given load or co-located with a load.
This report covers interconnection issues that apply broadly to distributed generation (DG), regardless of technology or type. The advanced inverter chapter applies specifically to inverterbased DERs. Special considerations are needed for energy storage, which can act as a load or a generator. Because of this, we include a separate chapter covering some of the unique aspects of storage interconnection. Although some of the practices in this report may be relevant to microgrids, we do not explicitly consider all the unique aspects related to this technology, including interconnection and operating practices for microgrids in interconnected or islanded modes. We cover interconnection of both BTM and FTM systems connected to the distribution system. The distribution system consists of mediumand low-voltage circuits, typically between 4 kV and 46 kV. We do not cover energy efficiency, demand response, or electric vehicles, because these resources do not go through an interconnection process.
Interconnection Considerations and Their Relation to the Guidebook Chapters
Figure 2 shows the typical interconnection process for DERs. First, an application for interconnection is submitted; processing and management of these applications is discussed in Chapter 1. If the project is below a specified size threshold, the utility then conducts a series of technical screens to evaluate the potential impact of the PV on its system. The number and type of screens a given project undergoes depend on the characteristics of the project. Technical screens and studies for DER interconnection are discussed in Chapter 2. If any negative system impacts—for example on voltage, power quality, or protection—are identified during the screening process, strategies for mitigating those impacts are identified by the utility. There is a variety of options for mitigating these impacts, including, but not limited to, downsizing the PV system, using advanced inverter functions (for inverter-based DERs), or upgrading the distribution network. We discuss how advanced inverters can be used to mitigate violations in Chapter 3. The ability of inverters to provide advanced functionality is constrained by the capabilities of the inverters and the ability to exercise those capabilities, which is defined by standards. The Institute of Electrical and Electronics Engineers (IEEE) 1547 family of standards is the critical foundation for DER interconnection, and it establishes criteria and requirements related to performance, operation, testing, safety, and maintenance on the grid. This standard is discussed in Chapter 4. Other important interconnection standards and codes, and their relationship to the IEEE 1547 standard, are also mentioned in this guidebook.
Different distribution system upgrades that can alternatively, or in combination with advanced inverters, be used to mitigate impacts are discussed in Chapter 5. If a project triggers upgrades, individual customers—or in some cases a small group of developers applying for interconnection at a similar time—are then responsible for the cost of these upgrades. However, these traditional cost-allocation approaches can be problematic. Different emerging cost-allocation schemes are discussed in Chapter 6.
System upgrades that might otherwise be triggered by DERs may also be avoided—to the benefit of developers, utilities, and rate payers—if systems can be guided into low-cost, low-impact locations. One possible way to do this is through hosting-capacity maps, which provide information on locations where DERs could be located without negatively impacting the system. We provide information on hosting-capacity maps and how they might relate to different components of the interconnection application, technical screening, and planning processes.
Today, the interconnection process shown in Figure 2 is typically undertaken on a system-bysystem basis without considering future deployment of other DERs. However, several aspects of interconnection depend on the deployment of other DERs. For example, different distribution system upgrades may be preferred depending on the DER penetration levels that are anticipated in the future. The ability to predict the amount of DERs that might be interconnected to a particular circuit is also important for evaluating the potential risks and viability of different costallocation approaches. With this in mind, we provide an overview of different approaches for and current understanding around forecasting DER deployment in Chapter 7.
Another important consideration during the interconnection process is cybersecurity. Cybersecurity has become an increasing concern for society as a whole, affecting a wide range of critical systems, including banking and medical records systems, among many others. In electric power systems, concerns extend from bulk power plants, to the transmission network, to the distribution network. The deployment of DERs on the distribution network poses new questions including how to balance the growing need for increased information sharing and grid transparency with the need for ensuring sufficient protections and privacy. Standards for cybersecurity are still being developed. We discuss the current state of understanding and emerging practices related to cybersecurity and the interconnection of DERs in Chapter 8.
Finally, Figure 2 shows the general DG interconnection process, but there are special considerations for storage systems, which can act both as generation and load. Chapter 9 discusses issues related to storage and solar plus storage interconnection.
In Chapter 10, we synthesize information from the other chapters and loosely map it onto what we term an “interconnection maturity model,” which conceptualizes evolving interconnection processes and needs as a function of DER penetration and utility characteristics. Chapter 11 provides a report summary and conclusions…
Summary and Conclusion
As DER penetration levels increase, it is important to understand the key issues involved in interconnection and how interconnection processes can be tailored to adapt to this new paradigm. This document provides an overview of these issues—targeted at a utility audience—including current understanding and future needs as well as how the solutions may relate to DER penetration level and utility characteristics. It presents standards or best practices where established, while acknowledging that best practices are still unknown and under development for many aspects of interconnection. Table 4 summarizes the maturity of knowledge and standards development for different interconnection aspects covered in this report. Interconnection approaches will continue to evolve in these areas, with ongoing standards development and increased understanding of good practices as pilots and studies are completed. This is a rapidly changing space, and updates to the information in this document will be required. Table 4 also lists some living resources and projects related to interconnection that may facilitate tracking of these topics..