Integrated Distribution Planning (IDP) – What is it? and How do we Achieve It?

It’s no secret that the electric distribution grid is changing. Historically, utilities plan for scarcity and focus on meeting load growth and serving customer demand. As our industry looks to the future, we anticipate a collection of resources, diverse, distributed and variable, connecting to the grid. Shifting to this new paradigm and preparing our grid infrastructure and planning processes is a daunting task that will require commissions, utilities, and other stakeholders in the electric power industry to re-evaluate current distribution planning practices.

Growing DER adoption and electrification, coupled with an unprecedented number and magnitude of natural disasters have highlighted significant challenges to current distribution system capabilities and planning processes. As utilities and regulators react to these trends, they agree that traditional distribution planning will evolve, but differ on priorities, objectives, and approaches. The pace and scale of this planning evolution will also differ based on each utility’s circumstances.

Twenty-six states, the District of Columbia, and Puerto Rico are either investigating (18), implementing (4), or have established (6) enhanced distribution planning practices. In addition to technical challenges (e.g. visibility and control of DERs), clean energy mandates and grid modernization proceedings have driven increased movement towards integrated distribution planning (IDP). As more states consider IDP, our industry will need to bridge the gap between regulators and utilities in understanding the technical and implementation challenges utilities face.

This is where SEPA can help. Over the past year, SEPA conducted a series of interviews with utilities and other industry experts to understand and document these key challenges and considerations. Insights from the report, Integrated Distribution Planning: A Framework for the Future follow.

What is Integrated Distribution Planning?
IDP is characterized by two key traits in SEPA’s study:

• Integration of internal elements and processes within the utility to enhance distribution planning, and
• Integration of distribution planning within transmission and generation (as it applies).

The report describes the key differences between traditional and integrated distribution planning, and the primary distinctions include:

• Expanded requirements and objectives (beyond safe, reliable and affordable electricity for all). Think clean energy goals and increased customer options.
• Transition from internal to more transparent and inclusive processes. A decade ago, few cared about how a utility conducted distribution planning. This is changing with the emergence of new DER capabilities, and as stakeholders increasingly want to understand why their proposed projects may be seen as causing technical challenges along the grid.
• Data, data, data. Traditional planning processes are based on historical and more deterministic forecasts. Planning for a more complex, distributed grid requires increasingly complex forecasting, and assumes grid planners will have access and capabilities to analyze massive amounts of data along the system.
• Proactive approach to DERs and other non-traditional solutions. IDP increases opportunities to identify where DERs and other non-traditional solutions can optimally benefit the grid.
• Greater integration between distribution, transmission, and generation. As DER adoption increases, it has the potential to impact not just distribution, but also transmission and generation planning. Following FERC’s recent Order 2222, coordinating between transmission, distribution, and generation planning will become more important. ISOs and RTOs will look to increase DER aggregation participation in the wholesale markets as a significant portion of aggregated DER resources will be located on the distribution side.

During a SEPA interview earlier this year, Colton Ching, senior vice president of planning and technology at Hawaiian Electric Company (HECO), stressed the importance of engaging with others in the industry, noting that best practices he’s found have come from conversations with peers, including “Utility planners who are thinking ahead about what utilities will need to do in the future.”

The SEPA approach to IDP (see below) identifies three “Core” IDP elements as central to the transition from traditional distribution planning to IDP, and three “Additional” IDP elements which may play a prominent role in IDP depending on the circumstances and goals of the utility and stakeholders.

The SEPA IDP Framework
As part of the study, SEPA developed an IDP Framework to illustrate the phased progression of each IDP element (core and additional), starting from a traditional planning process, and advancing to an aspirational future state of IDP.

With this framework, utilities and their stakeholders may identify the key elements relevant to them, where they are (e.g., Phase 2 of Forecasting), and the future state they are seeking to achieve (e.g., Phase 3 of Forecasting). A utility may be in different phases across elements (e.g., Phase 2 of Forecasting, Phase 3 of Interconnection), and their targeted future state may vary.

Challenges and Opportunities Ahead
Distribution planning sits at the center of our industry’s complex transition towards a clean and modern grid. Getting to more advanced phases of IDP will require support from regulators, innovation and leadership from utilities, and greater collaboration between industry stakeholders. Dana Cabbell, Director of Integrated System Strategy at Southern California Edison (SCE) noted, “to make [distribution resource planning] all come together and work properly, it is important to have the right tools and processes in place. Investment in software tools specifically has enabled [SCE] to meet the obligations and goals set forth by the Distribution Resource Planning process.”

Additional considerations include:

• Bridging technology gaps: Current tools and grid capabilities are limited in the level of granularity, visibility, and control they provide to distribution planners and operators. The industry will need to bridge these existing technology gaps and make foundational grid investments.
• Data, data, data: Investing and building competencies in big data analytics will grow in importance as utilities advance towards more complex phases of IDP.
• Anticipating lead times: Utilities, regulators, and stakeholders should allow appropriate lead time to invest in, and implement necessary tools, staff training and grid capabilities to enable advanced planning.
• Change management and integration of systems, groups, processes: A considerable amount of time and effort will be required to integrate disparate systems, tools, and groups within a utility. Utility staff will also need increased training and talent acquisition to navigate an increasingly technically complex distribution grid.
• Determining value of DERs for grid services: Utilities face challenges in assessing and assigning numerical locational and temporal values for DERs. Further research and investment to streamline this analysis will be required to enable more advanced integrated planning in the future.
• New Regulatory Constructs: Existing regulatory constructs may limit the ability for utilities to advance to more mature phases of IDP. These regulatory constructs likely need to evolve to lay the groundwork for IDP and other new grid business models.

This SEPA report provides a framework to guide the transition towards IDP, while identifying the challenges we as an industry must address today to facilitate progress.

For a more in-depth exploration of IDP, the SEPA framework, and challenges ahead, download the full free report here: