The New Era of Distribution Resource Planning: Part 1
Jan 23, 2017
In this two part series, we look at how distribution resource planning is flipping from top-down to bottom-up due to the influx of DERs. The transition can be disruptive, but we explore the strategies and tools that today’s utilities and their commissions are successfully applying to stay on top of the challenges and capitalize on opportunities.
While you were distracted - what happened to DRP in 2016
Electric utility resource planning is not a subject that tends to lend itself to headlines that get shared across social media. Even those of us who have a strong interest in staying abreast of energy industry news likely paid more attention to other headlines throughout 2016. Meanwhile, a quiet revolution is happening in the way utilities are planning to keep the lights on. Distributed energy resources (DERs), such as wind, utility-scale and residential solar, and various storage technologies, now figure prominently in a new distributed resource planning (DRP) approaches that explicitly seek to optimize the integration of DERs on the grid. At Nexant, we have been calling this “DRP 2.0”.
DRP 2.0 is a recognition that, due to the growing influx of DERs on a utility’s grid, traditional top-down resource planning no longer offers the highest-value for providing for distribution capacity relief, nor is it the best method to plan for customers’ future energy needs. Whereas traditional resource planning needed only to forecast future load growth and ensure the grid was equipped to deliver that load safely and reliably, utilities in many states must now account for and project into their planning process the location, size, type, and generation characteristics of thousands of customer-sited resources and precisely balance those resources with their traditional generation sources – while still safely and reliably providing for all customer load demands.
DER Integration is looming on the policy landscape
Regulatory proceedings are now underway in over 20 states and legislation has been introduced or passed in over a dozen states aiming to find how best to integrate DERs into the grid. The efforts currently underway in California and New York, two leading states in DERs and DER integration, provide a good indication of where others may soon be headed. A recent report by SEPA, 51st State Perspectives: Distributed Energy Resources Integration, compares their approaches. Below are some of the key takeaways from that report:
Starting place: California already has high penetrations of DERs, including nearly 600,000 residential PV installations, and has mandates for additional resources, such as storage. In New York, DER penetration is significantly less with approximately 58,000 residential PV installations. In California, multiple proceedings and demonstration projects are currently underway that seek to find solutions for increased DER integration, while New York’s governor and the Public Service Commission have declared that DERs are critical to the energy future of the state and are creating a policy and regulatory framework to further DER proliferation.
Goals: While many of their goals overlap, New York and California are using different mechanisms to achieve those goals. Both seek to increase DER penetration and both have set environmental or greenhouse gas reduction goals. However, New York’s process is being driven by their Public Service Commission under the single Reforming the Energy Vision (REV) proceeding. California has various regulatory and legislative initiatives; many impacting both DERs and other renewables and storage – with many approaches being piloted simultaneously by different utilities across the State.
Grid Constraints: Integrating DERs requires improved interconnection into the grid. Both New York and California are seeking to improve the interconnection process by providing transparency for DER developers and increasing the efficiency of the application process. Both states are also actively pursuing enhanced hosting capacity analysis that will eventually need to consider the changing configuration and loading of distribution-level feeders and equipment. The Distributed Resource Plans (DRPs) in California and the Distributed System Implementation Plans (DSIPs) in New York are the first attempts to provide clarity and transparency into hosting capacity, and these efforts are continuing to evolve.
Resource Planning: Utilities in California and New York must now include DERs into more granular forecasts and develop infrastructure plans to manage the impact of these resources on operations and safety. There is also a move toward the use of DERs to offset traditional Transmission and Distribution (T&D) capital infrastructure improvements – often called non-wires alternatives (NWAs). The most notable of these efforts is ConEd’s Brooklyn-Queens Demand Management Program, which is seeking to defer a $1.2 Billion substation improvement, and California’s Demand Response Auction Mechanism (DRAM), which seeks to use aggregated DR resources to smooth a variety of grid issues.
Benefit-Cost Analysis (BCA): The BCA processes in New York and California are very similar in purpose - both seek to build transparent, consistent methodologies to appropriately recognize and value DERs to offset traditional utility investments in distribution infrastructures. In determining the benefits of DERs, California is initially focusing on valuing benefits with locational granularity with provisioning of maps that highlight relative value. In New York, the joint utilities have flagged locational value as an area to address after analyzing hosting capacity constraints. (See a prior blog post about Nexant’s stochastic methodology being adopted by the joint utilities for further analysis.)
Data Sharing: Access by third parties to system and customer data provides those parties the opportunity to actively participate in deploying NWAs, to identify the most beneficial (and least costly) part of the grid in which to install DERs, and to develop products and services that are of most interest to utility customers. Both California and New York are seeking how to provide this data access while protecting their customers.
Rate Reform and Utility Incentives: California and New York are taking different approaches, though both are moving beyond Net Energy Metering (NEM) to more properly value the benefits provided by DERs. New York has been explicit in its goals to reshape the utility business model, while California’s Integrated Distributed Energy Resources (IDER) proceeding and related pilot programs launched in 2016 represents a move toward changing utility incentives and aligning them with new behaviors.
ISO Interface: The New York and California Independent System Operators (ISOs) are crucial to the integration of greater amounts of DERs because they provide markets within which DERs are valued. In California, FERC approved the Distributed Energy Resource Provider (DERP) role in June 2016 that allows a third party to aggregate DERs and bid them into the CAISO wholesale market. And CAISO has introduced an initiative called Energy Storage and DER (ESDER) that will allow developers to use storage to offset load behind the meter that could then be bid as demand response services into the wholesale market. The NYISO has programs that facilitate the participation of DERs in the wholesale market and have proposed that distribution service providers (DSPs) and energy service companies (ESCOs) serve as aggregators of dispatchable DERs that can then be bid into the wholesale market.
There is no “best way” to integrate DERs into the grid. Each utility will need to assess their unique situation and develop their own pathway to DRP 2.0. California and New York may be at the forefront of seeking a strategy for the integration and optimization of DERs with the grid but they are not alone in their efforts. States including Arizona, Nevada, Oregon, Washington, Louisiana, Mississippi, Florida, Michigan, Illinois, Missouri, Texas, Nebraska, Ohio, Rhode Island, Vermont, Hawaii and others are actively seeking ways to value distributed resources, align their costs and benefits with new rate designs, and/or determine how various approaches to DERs will affect their deployment, grid impacts, and customer behavior.
Alana Lemarchand, Rate Strategies for DERs, May 2016
In the next post we will discuss how utilities can prepare for the coming influx of DERs on their grid and benefit from a DRP 2.0 perspective.