TODAY’S STUDY: How To Value Distributed Energy Resources
What Is It Worth? The State of the Art in Valuing Distributed Energy Resources
John Larsen and Whitney Herndon, January 2017 Rhodium Group (prepared for the U.S. Department of Energy)
The U.S. electric power sector is in the midst of a significant transition. For much of its ~140 year existence, the U.S. electric system has been based on a foundation of large, centralized baseload power generators connected by transmission and distribution lines to demand loads. During this time electricity flow moved exclusively in one direction, from generators to consumers. The status quo is shifting towards a more decentralized and dynamic two-way system, with increasing amounts of utility-scale and distributed renewable generation. This shift is due to a variety of factors including slowing demand for electricity, persistently low natural gas prices, federal and state environmental regulations, and rapidly declining costs of renewable energy resources, as well as the growth of distributed energy resources (DERs) on the consumer side of the meter. The U.S. Department of Energy (DOE) commissioned Rhodium Group (RHG) to focus on this last driver of change in this report.
DERs have played a relatively minor role in the U.S. power system historically, but their place in the network is changing rapidly. Improvements in technology costs and capabilities, public policy support, and an array of new energy service providers have led to rapid customer adoption and substantial penetration of DERs—in particular solar photovoltaics (PV)—in some markets such as Hawaii and California. In these markets DERs are having tangible effects on distribution system operations and are posing new challenges and opportunities for distribution utilities, regulators, and incumbent market participants. If employed strategically DERs have the potential to help lower costs and improve the reliability of the U.S. electric system. If they are not deployed and integrated properly, DERs could impose new system costs and challenges to reliability. Currently, DERs are not incentivized to provide energy services on the distribution grid in a comprehensive way, nor do they compete on a level playing field with conventional utility- scale technologies. One of the key challenges facing both regulators and market participants associated with DERs is determining what services DERs can or should provide, determining the value of those services, and compensating them accordingly. As more DERs come on line, resolving these issues becomes increasingly critical for planning and operation of the distribution system.
This report explores the latest peer-reviewed literature to provide a broad view of the DER landscape with a focus on current and cutting-edge efforts to value the services that DERs provide to distribution systems and the bulk power system. The goal is to give state and federal regulators, and electric power stakeholders, a deeper understanding of what DERs are, what services they can provide, the options available for quantifying the net value of these services, and regulatory frameworks that could accommodate or potentially hasten the transition to a cleaner and more resilient power system. This report is intended to serve as a resource for power sector decision makers as they wrestle with the ascent of DERs and the broader power sector transition. Based on the research conducted in this report the following key findings were identified:
DERs can contribute to the development of a more flexible, cleaner, and affordable electric power system if they are fairly compensated for the net value of the services they provide, and that net value is fully considered in distribution utility planning and operations. See Chapter 2 for further discussion.
Different DER technologies can provide different electric services of value to utilities and customers. Where DERs can provide these services at lower net cost than conventional utility investments and practices they could lower costs for utilities and consumers while maintaining a similar or improved level of service.
A more flexible and cleaner distribution grid supported by DERs and optimized by system planners could enable long-term deep decarbonization of the U.S. electric power system and broader energy systems.
Current distribution utility regulatory and oversight frameworks either do not value all DER services or do so through inconsistent and incomplete administrative valuation and compensation procedures. Technology neutral, market-based valuation approaches can enable more complete and dynamic assessments of value and appropriate compensation, and could establish a level playing field where DERs can compete alongside other grid resources. See Chapter 3 for further discussion.
Different valuation and compensation methods are used for different DERs in different contexts. For example, demand response (DR) is often valued through competitive wholesale markets and receives compensation for multiple grid services while energy efficiency (EE) programs are subject to a series of administrative benefit costs tests. Meanwhile, solar PV is compensated primarily through administrative frameworks such as net energy metering (NEM) or sometimes Value of Solar (VOS) tariffs.
Most administrative valuation and compensation frameworks employ a variation on an avoided cost approach. This leads to over and undervaluation of DERs compared to their actual contribution of grid services and may not lead to the most cost-effective deployment of energy resources from a system-wide perspective.
The value of and compensation for services provided by DERs can change with different levels of DER penetration. For example, the value of energy generated by solar PV declines as penetration increases because this particular technology tends to put downward pressure on peak wholesale prices. Depending on their design market-based valuation approaches can account for the locational, temporal, and technological profiles of specific DERs. Moving away from administrative compensation and towards market-based approaches will be an important step in establishing price signals that can direct the deployment of DERs to where they are most valuable on the distribution system and can adjust for changing grid dynamics as deployment increases.
While there is no one-size-fits-all solution, examples of market-based valuation and compensation models currently in use or under development include competitive utility procurement of solar PV energy services, the use of the Infrastructure-as-a-service (IaS) model, and the design and implementation of a Distribution System Operator (DSO) or Independent DSO (IDSO) model that would allow for competitive markets for a variety of energy services within the distribution system.
Revisions to the traditional cost-of-service utility regulatory model may be required to properly value DERs and fully incorporate them into distribution system planning and operations. See Chapter 4 for further discussion.
The trends behind the surge in DER penetration may continue and could accelerate, leading to a distribution grid that must accommodate two-way flows of electricity. This is a departure from the traditional one-way flow of electricity from central generators to customers. This transition will take years or possibly decades. States experiencing relatively fast penetration of DERs are likely to lead in the area of regulatory reforms.
The traditional cost-of-service utility regulatory model generally does not place DERs within the core functions of distribution utilities. DERs can erode the two traditional utility revenue sources: rates of return on capital investments and electricity sales. Most state regulatory actions concerning DERs to date have focused on incremental changes to regulatory models to handle specific conflicts with utility cost-of-service revenue streams. However, a handful of states are working on comprehensive revisions that could better accommodate DERs.
There are several possible options for revising the regulatory model in ways that can place DERs within the core functions of the utility and lead to marketbased valuation and fair compensation of DERs. These options include allowing utilities to receive new revenue streams from providing value added services or by incentivizing utilities to create more value from existing and new assets. The ultimate pathway for revising regulatory models will be subject to a particular state’s legal and administrative constructs.
Additional research in several areas related to DER valuation and utility regulatory frameworks could provide new and innovative options for utilities and regulators as they consider optimal pathways for integrating DERs into the electric power system.
DERs are one of several challenges facing utilities and regulators. Other challenges include improving system resilience, protecting the electric power system from cyber and physical security threats, and federal and state policies to reduce power sector CO2 emissions. Research on planning, operations, and regulatory options for holistically addressing all or most of these issues alongside DER integration could be valuable to a variety of stakeholders.
The benefits of market-based approaches to DER valuation are clear, but outside of organized markets and competitive procurement few options are currently available to utilities and regulators. Research into the design of new and innovative methods for market-based valuation of DERs could expand the options available and potentially increase adoption of these approaches
Alternative regulatory frameworks explored in this report are very different from the typical cost-of-service framework used throughout the US. Identifying intermediate steps in the implementation of revisions to regulatory frameworks and options for easing the transition between steps could minimize friction between stakeholders and potentially increase the adoption of regulatory reforms