Rapid improvements in advanced energy technologies, increased customer adoption of distributed energy resources (DER), and changing public policy goals are driving change in our electric grid. Utilities historically have not taken DER - such as solar PV, demand response, energy efficiency, energy storage, or electric vehicles (EVs) - into consideration in their resource planning. The result is a business-as-usual resource plan, as if no DER were deployed. Cost savings in utility distribution system spending may be going unrealized because of excess capacity or because of investments in equipment for grid services that could be provided by DER at a lower cost. Getting utilities to consider DER in competition with traditional investments can lead to a more flexible, reliable, resilient, and clean grid, all while saving money for customers. The question is: how to do it?

In order for DER to support rather than stress our electric grid, policymakers and utilities should change how utilities undertake distribution system planning. This means building a system that can integrate increasing penetrations of DER, developing a regulatory structure that properly values and compensates DER, and providing access to information that would lead to DER deployment in the most high-value areas.

This is not entirely virgin territory: Some best practices are described in: Distribution Systems In A High Distributed Energy Resources Future by Lawrence Berkeley National Laboratory (LBNL); More Than Smart: A Framework to Make the Distribution Grid More Open, Efficient and Resilient by the Resnick Institute; and Planning the Distributed Energy Future by Black & Veatch and SEPA.  

That said, there is no one-size-fits-all solution to distribution planning that incorporates the DER available now or in the foreseeable future. Still, we can lay out today a practical framework that policymakers could use to prepare themselves for the DER future that is coming:

• Establish a process for utilities and third party providers to learn about their existing distribution system and identify foundational investments needed to achieve objectives
• Develop a regulatory structure to realize the value of DER
• Create rules and organizational structures that clarify roles for utilities and/or third party providers

For starters, utilities should map out their existing systems through an engineering assessment and identify infrastructure changes that may be needed to fully realize the value of DER. This could include identifying stressed areas of the grid and determining the maximum DER penetration that different sections of the grid can accommodate. This mapping could show where additional DER would most benefit the system and specify investments necessary  to enable an integrated grid (e.g. advanced metering infrastructure or smart inverters).

Next, a regulatory structure should be developed to properly value and source DERs. This includes appropriate compensation mechanisms that incorporate localized incentives targeted at areas of the grid where DER can provide the most value and a competitive solicitation framework to bring on DER at the lowest cost.  

Finally, rules should be established to create a distribution-level marketplace that consumers, “prosumers” (i.e., customers that want to actively participate in energy markets), third party assets and services, and the incumbent utility can participate in. For this to be successful, a clear line needs to be established between the competitive market and regulated utility functions. In addition, utilities would have to provide access to customer and system data for third party DER providers so that they, too, can identify areas where DER provides the greatest value and propose alternative investments.

All of this would be a big change from the status quo, but it is starting to happen already. California and New York are two states that have already begun to change how utilities go about distribution system planning, specifically with the aim of utilizing and integrating utility and third party DER in the grid.

The California Public Utilities Commission’s (CPUC) Distribution Resource Plan (DRP) proceeding is focused on how the state's investor-owned utilities find the value of DER, identify the areas of greatest need, and define the services that may be bought and sold to meet those needs. Meanwhile, CPUC’s Integrated Demand-Side Resource (IDER) proceeding is focused on how best to source, integrate, and incentivize the adoption of cost-effective DER needed by utilities.

In addition, on April 4, CPUC Commissioner Florio put forth a proposal in the IDER proceeding to address utility business model issues that will arise with the increased deployment of DER. Florio would like to test the effect of incentives on utility sourcing of DER and address the potential conflict between the Commission's policy objectives and the utilities' financial requirements. Specifically, the pilot would offer a shareholder incentive for the deployment of cost-effective DER that displace or defer a utility expenditure.

Meanwhile, in New York, the Reforming the Energy Vision (REV) proceeding is two years into fundamentally redefining the role of the distribution utility as an enabling platform to facilitate the widespread use of DERs. That proceeding is currently exploring changes in how utilities earn a return on expenditures, creating a transition plan for moving from net metering to DER valuation (decision by the end of 2016), and establishing a process for determining a full value of DER. Utilities are required to file distribution system improvement plans by June 30, as well as a joint filing two months later on distributed system planning to promote common processes and market design. These would include pricing mechanisms for the costs and benefits of DER, standards for determining hosting capacity for DER, and lessons learned from demonstration projects thus far.

California and New York are leading the way, but several other states are not far behind. On April 1, the New Hampshire Public Utilities Commission initiated a working group process in their grid modernization proceeding to explore distribution system planning, customer engagement with DER (advanced metering functionality, rate design, customer data, and customer education), and utility cost recovery and financial incentives. The Washington, D.C., Public Service Commission will hold a workshop on April 28, in their grid modernization proceeding, focused on the legal and regulatory framework that will facilitate and support a modern energy system that includes distributed resources. On March 24, the Minnesota Public Utilities Commission staff released a report with next steps in their grid modernization proceeding, which included plans for integrated distribution planning, hosting capacity analysis, smart inverters, advanced metering infrastructure (AMI), customer usage information, third party aggregation, and time varying rates (TVR).

As these leading states have shown, improving  the way utilities consider investments in their distribution system planning to incorporate distributed resources is no easy task. Outside of identifying, valuing, and sourcing DER there will also be a need to create a utility regulatory framework that ensures the viability of the utility business model while maximizing the many benefits of DER. But, if done properly, a sustainable framework will be developed that will lead to a more flexible, reliable, resilient, cost-effective, and clean electricity grid.