Report Integrated Resource Planning: A Primer for State Legislators

Introduction

Electric distribution systems across the U.S. are experiencing rapid change. State goals for renewable energy, increased weather events, and aging electricity infrastructure have created challenges for utilities, planners and the electricity system. Integrated distribution planning (IDP) can help meet and overcome these challenges as the U.S. works toward modernizing the electric grid.

IDP is a holistic planning process to make distribution system decision based on a range of factors. This process is unlike the planning model where least-cost investments are made based on projected growth. Instead, IDP uses stakeholder engagement, energy and decarbonization goals, equity, new technologies, data, and other policy objectives while making distribution planning decisions. This process aims to help decision-makers provide reliable, safe, and affordable electricity while approaching the complexity of the evolving distribution system.

A key component of IDP is the use of distributed energy resources (DERs), technologies sited at or near customer sites to manage, generate or store power. DERs can include devices like rooftop solar panels, electric vehicles, batteries, emergency generators, grid-interactive appliances and microgrids composed of multiple DERs. The technology can be purchased and used directly by consumers or communities and can also be owned and operated by utilities and third-party technologies, depending on the state. As their penetration to the grid increases, DERs can create challenges without proper planning and necessary grid improvements. IDP evaluates a wide range of future scenarios and expected grid demand to better plan for, design and implement grid investment projects.

 IDP requires collaboration between PUCs, state energy offices, consumers, utilities, third-party service providers and other stakeholders. To facilitate a collaborative planning process and DER deployment, legislation can set both broad planning goals and specific planning requirements and responsibilities. IDP goals may include safety, reliability, and affordability as well as newer policy goals like transportation electrification, renewable resources, and improved integration and use of DERs. Specific planning requirements in legislation can include planning timelines, requirements for public and stakeholder involvement, requirements for planning decision criteria, and cost recovery for utility investments that meet policy objectives. Successful IDP requires ongoing collaboration and communication about the state of the energy grid, available technologies, and ensuring that planning steps are informed by all parties involved to move energy goals forward.

Distributed Energy Resources  

The electric system is unidirectional. Generated power is transmitted over long distances until reaching a substation. After electricity reaches a substation, it connects to a distribution system that delivers power to homes and businesses. Power is generated, transmitted and distributed to end-users almost instantaneously. This model of energy production and transmission is optimized to connect the U.S.’ large, remote generation plants with towns, cities and industrial centers.

DERs, however, offer technology that allows individuals, businesses and third-party providers the opportunity to send excess electricity to the grid. While long-range transmission remains vital to powering the U.S., advances in technology in DER and local distribution technologies provide an opportunity to meet needs more efficiently, decreasing stress on the transmission system and increasing reliability.  

Types of DERs 

Distributed energy resources are increasingly popular as they offer solutions to meet energy goals, may align with customer demands and fulfill grid modernization goals. They offer potential benefits including an increased use of renewable energy, increased resilience against outages, and giving consumers more control and transparency over their energy use and generation sources.  

Energy Generation 

Technologies that generate energy to deliver power within the distribution system, like solar panels, are what most people think of when hearing the term DER. This type of technology can be modular or large-scale. DERs for generation can be installed both behind the meter on the customer side or owned and managed by third-party companies, utilities or communities. Generation technologies are often paired with other resources, like storage, to work more efficiently and meet the needs of the consumer. For example, a resident's rooftop solar array is often paired with a battery system so the household can be powered when there is no sun to produce energy. 

Demand-Side Management  

Another category of DER technology is demand-side management (DSM) or demand response. Consumers often use power on a predictable schedule, with peak times reoccurring daily. Some utilities use strategies like price tiers to incentivize or change the timing of high-consumption activities, like using a clothing dryer or air conditioner. DER technology can complement programs that aim to conserve energy by shifting energy use to maximize efficiency and decrease the strain on the distribution system. As the U.S. transitions to a greater focus on renewable energy, demand-side technologies help provide needed grid flexibility to meet power needs.  

Energy Storage  

Energy storage is a quickly evolving technology that is crucial for modernizing the grid and reliably meeting renewable demands. Wind and solar technologies produce energy when there is wind and sun, but some of the energy produced may need to be stored until consumers need power. Energy storage helps take full advantage of renewable energy by absorbing excess energy to use later when demand is high. This shift can increase reliability not only during normal demand fluctuations but also during unexpected outages or catastrophic events. 

Storage technology today largely consists of large-scale battery systems used by utilities and smaller battery systems used by households, businesses or industry consumers, typically together with solar panels. Electric vehicle batteries can also serve as energy storage. Some EVs can be used as a source of backup power or, when attached to a charging station, can send energy back to the distribution system to be used elsewhere. These storage technologies require smart systems to communicate with the distribution system and to send power. IDP ensures that the distribution system is prepared for upgrades like the use of storage and EVs as a source of energy.  

Microgrids  

A microgrid is a group of interconnected loads and DERs within clearly defined electrical boundaries that acts as a single controllable entity with respect to the grid. In addition to providing electricity to consumers during normal grid operation, microgrids can disconnect from the distribution grid to operate autonomously and locally while the distribution grid is down. They also can function as a grid resource for faster grid response and recovery.  

Microgrids are composed of the DERs most suitable for a given service area, ranging in type of generation resource and storage capability. There are multiple advantages of microgrids, but primary motivators include increased resilience and reliability, the use of renewable resources, and the ability to service areas that are remote or often affected by outages from the bulk power grid. The close physical proximity to consumers and the self-sufficiency of microgrids make them suitable for disaster response.  

DER Integration Challenges

In some cases, integrating distributed PV systems and EV chargers requires local grid upgrades — typically paid for by the interconnecting customer. But as penetration of these and other types of DERs increases, broader upgrades to distribution infrastructure and systems are needed. These upgrades require comprehensive planning and may require policy support. In addition, integration procedures should be designed to meet national technical standards and achieve state policy goals. By initiating an IDP process, states can lower barriers to distribution improvements and comprehensively assess how to approach forecasted challenges for DER integration. 

Technical Barriers

Technical barriers to DER integration include the physical capabilities of distribution grids to connect and host additional DERs as sizes and penetration levels grow while ensuring safe distribution system operation. In addition, it can be challenging to adapt grid modernization innovations to existing grid components. Infrastructure upgrades are needed to fully embrace new DER capabilities, including multi-way communication and real-time visibility and control.  

One example of a technical challenge is variable output from some types of distributed generation, like solar. A responsive grid system is needed to ensure continuous delivery of power to customers. DERs like automated demand response technologies and energy storage are part of the solution. Safety and reliability are another example of a technical challenge when grid voltages vary. As distributed generation increases, voltage may become more unpredictable and unstable without proper planning and interconnection provisions. Regulatory frameworks for interconnection, DER procurement, and grid technology requirements are needed to build a system that can optimize the use of DER technologies. 

Policy Barriers

DER integration is largely motivated by customer demand and policy objectives. Policymakers are tasked with ensuring that policy and administrative planning decisions match desired grid capabilities while working alongside utilities, stakeholders, and the public. Policy barriers can include regulations and processes that determine how DERs can be connected to the grid, costs associated with connection, and a lack of administrative capacity for regulatory oversight.  

Foundational policies that reduce barriers to DER adoption and integration may include financial incentives and billing or compensation programs, interconnection standards, and DER technology goals, as discussed later in this paper. Policies need to define which DERs are included, reflect the energy needs of the state and consumers, and plan for foreseeable changes and challenges.

Integrated Distribution Planning 

While all utilities conduct planning to maintain and operate their distribution system, states have only recently begun requiring utilities to file distribution plans for PUC and stakeholder review. In addition, required elements in the filed plans, level of detail and stakeholder engagement vary widely.  

State legislatures may establish goals and broad guidelines for IDP, but typically the PUC determines specific elements, like the length of time addressed by the plan (e.g., 10 years) and the specific analyses and data required. A primary goal of IDP is to help utilities, state agencies, communities and other stakeholders better integrate DERs and prepare for the impact DERs will have on the grid as penetration increases and new technologies become available. DER-related analyses that may be required in filed utility plans include DER forecasting, hosting capacity analysis, locational value assessment, and non-wires alternative (NWA) assessment.

IDP can look different across states, depending on needs and challenges, but a few essential elements define the process compared to traditional distribution planning. 

First, IDP takes a holistic approach to distribution planning. The traditional distribution planning process reflects a time when utilities largely owned and operated most resources. Electric utility restructuring in many states and increasing penetration of DERs are changing this paradigm. IDP strives to reflect this changing landscape. Plans include reliability and resilience analyses including threat-based risk assessments and an asset management strategy, a grid modernization strategy and roadmap, DER analyses, and other elements, depending on the state context. In vertically integrated states, solutions can be optimized across distribution and bulk power systems.  

Second, IDP requires a more collaborative planning process and is an essential part of understanding perspectives beyond utilities and state officials. Stakeholder engagement can include open dialogue with the public, utility customers, DER developers, disaster and climate experts, city planners and cybersecurity experts, community organizations, and environmental justice groups, among others. Conversations related to IDP can range from soliciting feedback on user experience on the DER interconnection application process to input from planners on major real estate development that will increase electricity demand. Stakeholder engagement is not only crucial to improving the quality of information utilities and regulators have, but it also increases transparency and access to the IDP process and can result in higher customer satisfaction and greater procedural justice. Many states opt to create working groups that consist of different types of stakeholders. These working groups may meet to work through various challenges and report discussions and findings to the PUC, state policymakers and utilities. 

IDP includes a focus on DER integration and considers a range of DER scenarios across forecasted timelines. While specific planning requirements vary by state, utilities may consider scenarios with respect to customer adoption rates, technological developments, policy and regulatory changes, and market and incentive impacts on DER growth. PUCs and policy officials determine the types of assessments utilities must perform and the types of data that must be reported in distribution plans. Stakeholders can provide input into the scenarios.  

Hosting capacity analysis (HCA) is a common requirement in states with a public-facing distribution planning process. Hosting capacity is the amount of DERs that can be interconnected to a specific point on the distribution grid without compromising power quality or reliability, and without needing upgrades to current control, protection systems, or infrastructure. HCA informs utilities, DER developers, and utility customers where DER interconnection costs may be lower. It also can be used as an interconnection technical screen and in distribution planning to identify grid constraints. 

Locational value assessment compares the potential benefits of DERs placed at various locations to understand where they may be most impactful. Utilities may be required to routinely assess locational value and incorporate findings into decisions about grid investments and DER programs.  

NWA assessment identifies opportunities to use DERs to cost-effectively defer or avoid grid upgrades. Such DERs may include a single large battery or a portfolio of different kinds of DERs, including geotargeted energy efficiency, demand response, distributed generation and storage. States may require utilities to identify planned utility upgrade projects that can be satisfied with the use of an NWA.  

These examples, while not exhaustive, highlight the type of assessments states may require utilities to study transparently in the IDP process to prepare for future grid investments. 

Actors in the IDP Process 

The Role of Utilities  

While the IDP process aligns state and utility goals for grid infrastructure investments, utilities maintain responsibility for the planning process. That includes developing and filing plans, determining grid infrastructure needs, making grid investments, and ensuring reliable power delivery.  

As energy technologies continue to evolve, the role of utilities will likely evolve to include a major focus on DER coordination. As a distribution system operator (DSO), utilities may be responsible for monitoring, managing, coordinating, and optimizing DERs owned and operated by utility customers and third parties. This transition to a DSO role can happen organically with the rapid growth of DERs or through new mandates expanding the responsibilities of utilities.  

As demand-side management is a feature of DER integration, utilities may also be relied upon for new DSM initiatives. DSM can vary based on available technologies, customer will and preference, and regulatory goals, but considering possible strategies is important in load and DER forecasting. Utilities are also the key players in grid and customer data management and analysis. Utilities are responsible for assessing and sharing information grid and customer data, under provisions set by state regulators. This role is vital since data is essential to the IDP process, as well as DER adoption and use.  

In addition, utilities have a direct relationship with their customers. The utility's role in stakeholder engagement is crucial before and after plan filings, including keeping customers informed of progress on plan implementation and infrastructure performance.  

The Role of Regional Grid Operators 

Throughout much of the U.S., regional transmission organizations (RTOs) and independent system operators (ISOs) operate centrally-organized electricity markets. These regional grid operators are independent nonprofit organizations that ensure reliability and optimize supply and demand bids for wholesale electric power. They do not own grid infrastructure or generation. Under Federal Energy Regulatory Commission Order No. 2222, RTOs and ISOs must better enable DERs to participate in their electricity markets. That includes establishing coordination requirements between the regional grid operator, DER aggregators, distribution utilities, and utility regulators. FERC stated its intent that these requirements will not create undue barriers to entry for DERs and aggregators while recognizing the role of distribution utilities and state and local regulators in ensuring the safety and reliability of the local distribution system.

The Role of States 

Legislators and PUCs set distribution planning goals and requirements for regulated utilities. Examples of planning elements that states may specify are the frequency of plan filings, the term that the plan covers and required analyses such as load and DER forecasting scenarios and analysis and maps for DER hosting capacity. The details required in IDP filings inform stakeholders, including the public, on the utility's investment plans. 

DER integration objectives can be defined by states through various policy and administrative actions. For example, the legislature can establish DER deployment goals as part of renewable energy targets, establish a fund to encourage customers to purchase distributed storage systems or provide a tax credit for electric vehicle charging investments. PUC actions can include interconnection standardization and approval of incentive levels for DER programs for utility customers. State energy offices can conduct comprehensive energy plans, administer DER grant programs and conduct various types of DER studies, such as technical and economic potential. 

Importantly, states determine long-term energy goals that utility plans should be designed to achieve. Legislative and regulatory actions also can remove unwarranted barriers to DERs and grid infrastructure projects, facilitating their deployment. 

Areas of Focus for Legislators 

Financial Incentives 

Cost is an obvious obstacle for many households and businesses that want to purchase DER technologies like rooftop solar and energy storage. States, utilities and PUCs can work collaboratively to create new programs or allocate funding toward grants, rebates, and tax credits. Programs can focus on certain groups, like underserved communities or low-income households, to prioritize equitable access to new energy technologies.  

Interconnection Standards 

DER interconnection can be a time-consuming and costly process for utility customers. Interconnection standards and streamlined processes facilitate DER adoption while protecting the safety of the grid. Many states, like Minnesota, have developed interconnection frameworks and maintain a website with guidance for the public and electricity industry.  

Policies Setting Renewable Energy Standards 

DER integration can advance the use of renewable energy. Goals for certain types of resources may incentivize or require DER uptake. Legislation is one primary way states determine minimum renewable energy levels and target dates. For example, New Mexico (S.B. 489) requires 100% zero-carbon electricity sources by 2045. One benchmark in this goal is 20% solar generation by 2020. The state’s Community Solar Act, signed in 2021, defines a community solar facility, subscription requirements, administrator requirements and other aspects of the community solar initiative for the PUC and the public. This act also addresses issues like equitable and fair access to solar-generated electricity, protections for subscribers and fair disclosure about costs, and standards for solar bill credits and billing. Currently, 22 states have community solar-specific legislation.

Policies for Microgrids 

Legislation aimed at microgrid development is another opportunity for legislators to be involved in DER advancement. Recent state legislation includes setting microgrid goals and describing the importance of microgrid development. Legislation aimed at microgrid development is another opportunity for legislators to be involved in DER advancement. California has relatively substantial microgrid legislation. The state required the PUC and Energy Commission to develop standards for microgrid adoption and integration without defraying costs to ratepayers and to reduce barriers to microgrid deployment (S.B. 1339, 2018). The bill also required the two agencies to create a working group to ensure microgrids meet standards set by the California Electrical Corporation and ISO microgrid requirements. The state has since moved forward with development, and microgrid tariffs and incentives are established in the state, but rulemaking continues as utilities respond and implement PUC decisions. Rulemaking continues as utilities respond and implement PUC decisions. Other microgrid legislation examples include Colorado H.B. 1013 (2022) and Connecticut H.B. 6853 (2023). 

Policies for Storage 

Many states have enacted legislation to promote energy storage technologies to meet a variety of objectives, including improving grid reliability, resilience, and renewables. Legislation can determine goals, create programs for behind-the-meter storage, add storage as a qualifying resource for existing programs and incentivize the use of storage.  

Maryland was among the first states to adopt and specify incentives for distributed storage resources through their income tax credit program (S.B. 215, 2022). Residents who purchase and install a residential storage system may claim a credit against state income tax owed for the total installed cost. They may receive up to $5,000 or 30% of the total installed cost. The tax credit is also available to businesses and commercial buildings. Owners of these systems may receive up to $150,000. The state’s income tax credit program for energy storage has a $750,000 cap.  

Applications for the tax credit are processed in the order they are received.  

In 2018 Colorado passed legislation designed to protect individual consumers who install and interconnect energy storage and instructed the state PUC to adopt rules and standards for storage interconnection. S.B. 009 declared that penalties and unnecessary burdens or restrictions like fees and special rates cannot be used to discriminate against consumers who use and interconnect storage systems. The bill instructs the PUC to develop rules that limit barriers to installation and interconnection, design a streamlined process for interconnection applications, and ensure meter requirements are aligned with existing net metering rules, without requiring consumers to install a new meter solely for the storage system. The legislation did not include a deadline for the PUC’s new regulations.  

Policies for Interconnection Standards 

State legislation can require the PUC to develop interconnection standards and streamline interconnection procedures and create commissions to make DER and planning-related decisions, or other similar administrative actions. For example, in 2021 Hawaii (S.R. 207) required the PUC to develop and adopt reliability standards and interconnection requirements with a goal to bring new projects online sooner, meet renewable portfolio standard goals and decrease costs by increasing project certainty. Then, in 2022 the state required the PUC to study interconnection and interconnection timelines for consumers, to inform the establishment of interconnection and reliability standards. The legislation allowed the use of a contractor to conduct the study. 

Maine (L.D. 327) created an interconnection ombudsman to assist customers with interconnection applications, reduce timelines, manage disputes, and facilitate feedback from interconnection stakeholders. The ombudsman is funded primarily by interconnection fees and federal funds. The act also refines language that requires interconnection rules in the state to reflect best practices, specifying those established by the Interstate Renewable Energy Council, and prioritizing consumer-owned solar and storage systems that serve on-site loads. Maine’s legislation also requires an interconnection working group, which submits annual reports on their activities, with a final report due in December 2025. The objectives of the working group are to develop interconnection processes and solicit feedback on the process for consumers. Interconnection requirements were last updated in May of 2023 and can be found here.  

Policies for Distribution Planning  

Legislation may specify grid modernization and distribution planning goals as well as required components for utility distribution plan filings. Currently, 19 states and the District of Columbia require regulated utilities to file distribution plans, though they vary in required content. In some states, legislation requires such plans; in other states, PUCs establish planning requirements using existing authority.  

States may require utilities to file distribution system improvement plans, as in Indiana and Pennsylvania, or allow utilities to file a grid modernization plan for expedited cost recovery, as in New Mexico. But an integrated distribution planning process is more comprehensive and incorporates advanced planning elements. States with the most advanced planning requirements include California, Hawaii, Massachusetts, Minnesota and New York.  

S.B. 146 Nevada (2017) requires regulated utilities to file distributed resource plans with the PUC every three years, together with an integrated resource plan. The bill requires elements of evaluation of the locational benefits of DERs, proposed tariffs or mechanisms for cost-effective DER deployment, DER forecasting, and potential barriers for non-wires alternatives. The bill also requires public hearings and lists the components required to demonstrate plan adequacy. In 2018, the state PUC adopted rules for utilities filing distribution plans under these rules.  

S.B. 236 Colorado (2019) required the state’s PUC to increase transparency and draft distribution system planning rules. The PUC issued final revisions in 2021, improving DER planning in the state. The language in the legislation specifies that distribution plans must, at the minimum, contain system and substation historical data, peak demand, adoption of DERs, and distribution investments. Plans must also detail new planned service areas, load forecasts, DER forecast, cyber and physical security protocol, a proposed cost recovery method for NWAs, evaluation of proposed NWAs, and an estimate of when DER growth merits an analysis of NWA projects. The PUC requires utilities to file a DSP every two years.