Colorado is Poised to Boost DERs Through Distribution System Planning

In most parts of the country, how utilities plan their distribution systems – the network of poles, wires and other equipment designed to support electricity delivery at the local level – is something of a “black box.” But now, with the continued proliferation of distributed energy resources (DERs) – ranging from rooftop solar to onsite battery storage and demand response – available to help manage electric supply and demand at the distribution level, that black box needs to be opened. Colorado is doing just that by joining a growing number of states that are implementing distribution system planning (DSP) rules for the first time.

Colorado’s rules, which are expected to increase transparency around utility distribution system investments and facilitate new opportunities for deployment of DERs, provide one example of how states can support a cleaner, more flexible, more reliable grid. That has certainly been the direction AEE has been pushing in its engagement in this proceeding as well as others in California, New York, and Michigan.

In 2019, the Colorado legislature passed Senate Bill 19-236, which required the Public Utilities Commission (PUC) to develop regulations that would provide greater visibility into utility distribution systems and provide new pathways for DERs to meet system needs. After concluding an investigatory proceeding on distribution system planning, the PUC opened a formal rulemaking in December 2020 to develop the DSP rules. The Commission worked to consider stakeholder input throughout the first half of 2021 before issuing a decision on the regulations in early September.

In its DSP rules, Colorado has taken a comprehensive approach to considering how the distribution system can evolve to meet future grid and customer needs. Here are some of the highlights:

• Integration with state policy goals: The rules recognize that the distribution system plays an instrumental role in achieving state policy goals, including those related to decarbonization. That’s why the Commission, in response to recommendations put forward by AEE and other parties, included language that requires distribution system planning be done in alignment with these goals.

• Distribution system forecasts: Within a 10-year planning period, utilities must provide to regulators a wealth of information on how their systems are expected to change over time, including expected future electricity demand and DER growth. Critically, utilities must develop scenarios that consider the amount of DERs that could meet, or exceed, state policy goals.

• Hosting capacity analyses: Distribution system plans must include detailed hosting capacity analyses (HCAs), which allow customers and DER companies to identify areas of the grid that can accommodate more DERs capable of exporting power back to the grid, including distributed solar and storage. 

• Grid needs assessments: The DSP rules also require a full checkup of each utility’s distribution system to see what constraints lie ahead over a 10-year period. The grid needs assessment (GNA) will tag critical infrastructure, including substations and major feeders, that will likely need to be replaced to accommodate future electricity demand. 

• Non-wires alternatives: Once utilities identify major grid constraints that could be addressed by additional DER deployment, utilities are required to issue solicitations for non-wires alternatives (NWAs). These NWAs will consist of DERs or aggregations of DERs that can cost-effectively provide the grid capacity needed to meet local peak demands and avoid the need for more costly capital investments. If utilities receive NWA bids that are less expensive than building new distribution infrastructure and able to meet future reliability needs, those NWA solutions would be implemented, saving customers money while enhancing grid flexibility.

• DER Pilots and Programs: The DSP rules also provide utilities with the opportunity to leverage DERs to address smaller grid constraints that don’t meet the threshold of a major grid constraint, which would otherwise potentially be subject to an NWA solicitation. These efforts can further demonstrate the value that DERs can provide to the distribution system and lay the groundwork for more targeted utility DER programs in the future.

The Commission opted to include several recommendations put forward by AEE and other partner organizations, including increased stakeholder engagement requirements for utilities prior to filing DSPs, clarification of the grid benefits and services DERs can provide, process improvements to support fair and competitive NWA solicitations, a requirement for utilities to develop a final Action Plan laying out near-term distribution system investments and programs, and more. These modifications strengthen the DSP process and help ensure DSPs achieve the intended goals of supporting grid reliability and preparing the distribution system for a high-DER future.

Now that the rules are finalized, utilities are expected to file DSPs every two years; Xcel Energy’s first DSP will be submitted for PUC review by early 2022. Although issues surrounding HCA data updates, NWA cost-benefit analysis methodologies, and NWA solicitations will require additional focus in utilities’ individual DSP applications, the final DSP rules set in place a robust framework for more transparent, cost-effective grid planning that unlock more of the value that DERs can provide to the system. It’s time for more states to follow suit and view distribution system planning as a foundational step in developing a cleaner, more flexible, more affordable energy future.

AEE has published a set of seven issue briefs on key topics in utility regulation in a changing electric power system, including distribution system planning. Download any or all of the issue brief by clicking below.