TODAY’S STUDY: How To Know Where To Put Distributed New Energy
Beyond the Meter – Addressing The Locational Valuation Challenge For Distributed Energy Resources; Establishing A Common Metric For Locational Value
Josh Bode, Alana Lemarchand, and Josh Schellenberg, September 2016 (Nexant and the Smart Electric Power Alliance)
Distributed Energy Resources (DERs) are at the center of a broad array of policy conversations across the country, propelled by potential for growing deployments of DERs to shape energy and grid investments. An explicit goal of some of the more developed efforts—such as the Renewing the Energy Vision (REV) proceeding in New York or the Distribution Resource Planning (DRP) and Integrated Distributed Energy Resources (IDER) proceedings in California—is to establish or unlock DER value through some combination of markets and regulatory innovation. Approaches considered include allowing DERs access to existing wholesale markets for energy and generation capacity and creating new economic constructs for capturing other potential value streams such as locational grid services.
In these places, utility planners are being asked to integrate DERs into distribution system planning. In order to do this it will be necessary to evaluate DERs in the context of more traditional distribution resources. All of this indicates there is a need for a common metric or approach for assessing the capacity deferral value provided by various DERs so their value can be stacked and combined. It is equally important that this metric be translatable to the traditional distribution investments, which may be deferred or avoided.
However, a universal, common methodology has yet to emerge, with DER valuation efforts largely focusing on enumerating various potential value streams, including distribution capacity deferral.1,2 This document seeks to fill that gap by laying out a methodology for evaluating this capacity deferral potential, heretofore referred to as locational capacity value. This methodology is a real world decision tool that has already been applied at multiple utilities to evaluate DER alternatives to traditional distribution investments but universal enough that it could be adopted by any utility for assessing locational capacity value.
Historical DER valuation approaches tended to center around technology specific benefit cost protocols intended for evaluating program costeffectiveness. More recently, comprehensive DER valuation frameworks and locational value demonstration projects have called out and begun to address this locational valuation methodology gap. In addition, it is increasingly apparent that approaches that seek to boil DER value down to a single benefit-cost ratio or average value per kilowatt-hour (kWh) are missing the differences in temporal and locational3 characteristics inherent in DERs. This trend is seen in the New York REV proceeding, which places DERs in their own category with their own common valuation frameworks, such as the Benefit Cost Analysis Handbook.4
This is one of several ongoing discussions, which include several proceedings in California (DRP and IDER); the EPRI Integrated Grid project5 (which has included collaboration with utilities in both New York and California6); and the Smart Electric Power Alliance (SEPA) “Distributed Energy Resources Capabilities Guide”.7
The approach covered here is a real world, working methodology that has already been applied in key deferral demonstration projects—including the Central Hudson Targeted Demand Response program—and was foundational to many components of the Central Hudson Distribution System Implementation Plan (DSIP) filed on June 30, 2016,8 including the assessment of DER locational value. This approach is also similar and extensible to the approach used by Southern California Edison (SCE) for their multi-year Preferred Resources Pilot (PRP), another key example demonstrating how DERs can be used to defer or avoid need by providing bulk and locational services.9 This is not the only valid approach, but is one that may spur additional discourse and share real-world experience in an area that is central to understanding DER value in the context of the electric grid.
Whereas Sections 2 and 3 introduce and provide context for the methodologies by describing historical and existing approaches for evaluating DER value, highlighting a methodological gap for locational valuation, Section 4 provides a step by step guide to the approach. First, Section 4.1 explains how locational capacity value is directly driven by the characteristics of local peak loads and by the deferral of planned distribution investments. The section introduces four key concepts, which help identify when and where DERs have the potential to provide the most distribution deferral value. n Excess capacity—(or lack thereof) and the magnitude of distribution investments are key drivers of locational value;
n Projected load growth—rates and deferral benefits are closely linked;
n Load shape attributes—distribution area load shapes and the concentration and timing of peak demand vary substantially and matter; and
n Timing, duration, and magnitude of need— How many hours of relief are needed? When do they occur? For how long must production (or reductions) be sustained? How much production (or reduction) must be provided?10
The methodology for calculating a common locational capacity value metric builds on these key concepts and on a probabilistic future load growth simulation approach, and has already been used to calculate avoided transmission and distribution (T&D) costs for Central Hudson.11 Essentially, the economic metric for the locational capacity provided by DERs is the future cost of traditional distribution equipment (substation, transformer, etc.) that would otherwise be needed. The net locational capacity value of DERs is the avoided distribution cost minus the cost of the DER alternative.12
Section 4.2 describes how the allocation of locational capacity value to DERs is directly dependent upon the unique operating characteristics of individual DERs as this drives the ability to defer locational capacity investments. Three questions can help quantify DER locational value by establishing the extent to which characteristics for a given DER differ from distribution equipment, which is always available to accommodate loads:
n Is the DER tied to a specific load shape?
n Is the resource flexible?
n Are there specific operating constraints?
These questions underlie the calculation of Load Carrying Capacity Factor (LCCF): a derating factor that captures the ability of a given DER to provide effective locational capacity, when and where it is needed. As illustrated in Figure 1, alignment of characteristics such as local capacity risk profile and DER production or load profiles are central to quantifying this derating factor. While LCCF can be used to compare individual resources, the LCCF of a resource portfolio should ideally be calculated as an iterative process where the peaking risk allocation is recalculated as least cost resources are layered in to the portfolio. Such a portfolio will leverage and combine unique strengths of different resource options—including DERs and traditional distribution investments—resulting in a whole portfolio that is more effective than its individual parts.
Finally, accurately valuing DER locational capacity value is one building block toward holistically integrating DERs into various utility functions, including: distribution planning; bulk power planning; and customer strategy. However, to do so there are still many key issues that need to be resolved. The final section addresses the following four issues, which are important but by no means exhaustive.
n How can locational value be included in Integrated Benefit Cost Analysis?
n How can integrated distribution planning capability gaps be addressed?
n How can the need for contractual obligation and guarantees be reflective competitive mechanisms?
n How can distribution planning reflect uncertainty and risk planning?
While these future challenges remain unanswered, this paper helps address the locational valuation challenge by establishing a common metric and moving the conversation from exploration of concepts to discussion of real-world, quantitative approaches…
Extensive electric industry research and thought leadership has identified a whole host of system, community, and locational benefits that could be achieved through careful, targeted deployment of DERs, including the locational value of deferring traditional distribution investments through management of local loads—the subject of this paper. Some regulatory commissions are exploring potential DER integration roles that have been identified for market mechanisms and for extending integrated planning down to the distribution level. Substantial economic and engineering analysis, including the real world demonstrations discussed in this paper, are being devoted to these efforts with the goal of better understanding how to make this potential a reality.
These demonstrations are showing that it should be possible to capture this potential to leverage DERs as a tool for the electric system, a new addition to the toolkit of traditional infrastructure and evolving modern grid technologies which may enable leaner and leaner management and operation of the grid potential. Such forays are also showing that delivering holistic economic benefits by optimizing use of all the tools in this evolving toolkit will not be easy. As more possibilities are explored, more is learned about the challenges that must be faced, including those discussed toward the end of this paper.
While addressing these and other challenges may not be an easy, simple problem it is also very solvable, provided there is a focus on developing sound, clear methodologies focused on unlocking the economic potential of DERs. This paper is a step in that direction, addressing the locational valuation challenge by establishing a common metric for locational value. Such methodologies are not static, and the approach discussed in the paper continues to evolve to address current and future challenges. By rising to these challenges, it will be possible to unleash the potential of DERs in concert with the other tools in the industry toolkit and transform the electric system of the twenty first century in a strategic manner.