TODAY’S STUDY: States Step In On Utilities' Energy Plans
State Engagement in Electric Distribution System Planning
Juliet Homer, Alan Cooke, et. al., December 2017 (Grid Modernization Laboratory Consortium of U.S. Department of Energy national laboratories)
Electric distribution system planning is focused on assessing needed physical and operational changes to the local grid to maintain safe, reliable, and affordable service. While electric utilities have always engaged in this activity, the planning horizon has typically been short and involvement by state utility regulators minimal.
Safety, reliability, and affordability remain top objectives for deeper state engagement in longer-term distribution system planning. Other drivers are proposed utility investments to replace aging infrastructure and modernize grids, opportunities to improve distribution system efficiency, enabling consumers to have greater control over energy costs and sources, and integrating higher levels of distributed energy resources (DERs) such as rooftop solar, distributed energy storage, and price-responsive demand.
This report provides a snapshot of current state engagement in distribution system planning:
• Part 1 describes activities in states that have adopted some advanced elements of integrated distribution system planning and analysis (see Figure S-1): California, Hawaii, Massachusetts, Minnesota, and New York.3 It summarizes the impetus for early action, goals, regulatory requirements, additional state activities related to distribution system planning, and next steps.
• Part 2 covers a broader array of state approaches. For example, some of these states have longstanding distribution reliability and performance codes, requiring regulated utilities to report regularly on poor-performing circuits and propose investments for improvements. Other states require regulated utilities to make filings related to proposed grid modernization investments.
A growing number of states are beginning to consider comprehensive distribution system planning processes. This report documents activities in eight states with statutory or public utility commission requirements for electric distribution system or grid modernization plans, plus four jurisdictions with proceedings on such requirements underway or planned. We also cover activities in several additional states to provide a more accurate picture of the significant variation in approaches, in part stemming from differences in electricity market structure — states with restructured markets versus states where all utilities remain vertically integrated. Table S-1 provides a summary of these approaches.
Table S-1 provides examples of states with longstanding requirements for utilities to report on reliability and resilience metrics and plans to improve on these measures, as well as states with storm-hardening requirements. Common emerging distribution system planning elements include DER forecasting, assessing DER locational value, analyzing hosting capacity, assessing non-wires alternatives, and engaging stakeholders (including third-party service providers) to comment on proposed planning processes and filed utility plans and help identify least-cost solutions to distribution system needs. Some states also are exploring new procurement mechanisms, such as competitive solicitations, to consider DERs as non-wires alternatives for load relief and other distribution system needs.
Among the specific reasons PUCs are adopting these new planning and procurement practices are to facilitate higher penetration levels of DERs, harness these resources to provide grid services for customers, enable greater consumer engagement, and improve review of utility investments in distribution systems, particularly with respect to grid modernization.
States can learn from each other and tailor successful approaches to their unique circumstances. Reviewing the broad range of legislative and public utility commission activities described in this report is a useful starting point…
While most states have not yet begun to directly engage in longer-term (five to 10 year) planning for electric distribution systems, New York, California, Hawaii, Massachusetts, and Minnesota are early adopters. Several additional states, such as those featured in this report, are beginning to adopt long-term distribution system planning requirements for regulated utilities or are exploring such requirements. These efforts are building on existing distribution reliability and performance codes and PUC reviews of grid modernization investments proposed by regulated utilities.
Beyond universal PUC interest in affordability and reliability, drivers for improved and more transparent distribution system planning processes include interest in more efficient operation of the distribution system, enabling greater consumer engagement, the need to replace aging infrastructure, opportunities to adopt grid modernization technologies for the benefit of consumers, addressing higher levels of DERs due primarily to cost reductions and public policies, and potential net benefits to customers for grid services provided by these resources.
Approaches to state engagement in distribution system planning and grid modernization planning vary widely. They range from a cohesive set of requirements laid out in state statute or PUC orders, to an ad hoc requirement in a general rate case decision for the utility to file an initial long-term distribution system plan or grid modernization plan.
Some PUC distribution planning processes are tied to greater utility assurance of cost recovery for proposed distribution investments that are included in approved plans.
Common emerging distribution system planning elements include DER forecasting, assessing DER locational value, analyzing hosting capacity, assessing non-wires alternatives, and engaging stakeholders (including third-party service providers) in proposed planning processes and filed utility plans to help identify solutions to distribution system needs.
Some states also are exploring new procurement mechanisms, such as competitive solicitations, and pricing programs to consider DERs as non-wires alternatives to meet certain distribution system needs (e.g., load relief) and ways to modify the utilities’ annual capital planning process to account for these options.
Integration of distribution planning with other electric grid planning processes, including integrated resource planning (in states with vertically integrated utilities), transmission planning, and demand-side management planning, is of increasing interest. Such efforts are still nascent. Some early steps may include consistency in inputs, such as forecasts for loads and types and levels of distributed energy resources, scenarios, and modeling methods—updated in time—across these planning processes. The regulatory landscape is changing rapidly in this area. This report provides a snapshot of the early phase of adoption of new distribution system planning processes.