The failure of utilities to prepare for the surge of distributed energy resources (DER) expected to come onto their distribution systems will harm both their customers and their own bottom lines, analysts told Utility Dive.
But proactively planning for new waves of customer-sited DER can both serve growing customer demand and provide flexibility to address the rising penetrations of variable renewables.
"Most utilities have been able to model the so-far low penetrations of customers' DER on their distribution systems as a change in net load," NREL Research Scientist Kristen Ardani told Utility Dive. "It has not been consequential to bulk power system reliability and ensuring resource adequacy, but that is changing."
Now, with DER penetrations still low, "is the time to shift the focus of planning from load growth and new infrastructure to understanding what policies and investments will be needed for the more dynamic system that is coming,"
President, Plugged-In Strategies
Utilities have good reasons to avoid distribution system planning (DSP), Ardani and others said. It is more complex and unpredictable than bulk system integrated resource planning (IRP). And making more customer-owned DER possible may limit revenue-generating utility infrastructure spending and reduce kWh sales.
But now, with DER penetrations still low, "is the time to shift the focus of planning from load growth and new infrastructure to understanding what policies and investments will be needed for the more dynamic system that is coming," Plugged-In Strategies President and former regulatory commission staffer Chris Villarreal told Utility Dive.
Why is DSP needed?
"Distribution planning has traditionally been about identifying the upgrades and improvements needed to serve the bulk system," NREL's Ardani said. But the distribution system's "constantly changing generation and load profiles" now requires more attention.
Traditionally, distribution system planners, bulk system planners and generation planners were focused on their own points of view, she added. "The need now is for integrated planning that incorporates DER impacts on all systems and the new data those impacts produce."
Legislative and regulatory directives for grid modernization to address customer demand for DER are driving new planning, Ardani said. As a result, "utilities are developing new tools and analyses like hosting capacity analysis (HCA), which provides detailed distribution system maps and data to streamline interconnection."
There are two levels of transparency needed in the new planning processes: integrating data and information across different planning groups, and getting that information to stakeholders, Ardani said.
"Different jurisdictions have different standards and priorities, but there are ways to both protect customer and critical infrastructure data and give access to DER providers who want to build where there is system value."
Director of Distributed Grid Strategy, ICF Consulting
Transparency is improving in DSP efforts in California, Hawaii, Massachusetts, Minnesota and New York, she said. "They are also beginning to understand DER impacts on the bulk power system. That is a huge paradigm shift for an investor-owned utility never tasked with understanding and planning for them."
Another common trait across those states is "more standardized data and analyses tailored to DER," she said. Examples are the Locational Net Benefit Analysis and the non-wires alternatives (NWA) analysis.
In response to grid modernization initiatives, utilities have begun proposing revenue-producing distribution system investments, and "state regulators want planning data and analysis to evaluate those proposals," said Plugged-In's Villarreal.
There are four elements to today's DSP, Villarreal said. Two are traditional long-term bulk system planning and the near-term distribution system assessment it typically includes. The other two are the utility's best data on DER interconnections and its HCA.
If those four elements use the same data sources, forecasting and assumptions, they align DSP and IRP, Villarreal said. "But if the data, forecasting and assumptions come from siloed utility departments, planning will likely underestimate the value of DER and over-procure transmission and generation, which is another reason regulators are increasingly interested."
Developing DSP can be a long process, he added. "Moving beyond the traditional objectives of safe, reliable, affordable electricity to things like integration of systems and transparency can require seven or eight years."
The data utilities are deriving from "advanced metering, line sensors and the like" is giving utilities "the visibility into their distribution systems" that allows them to take on planning, ICF Consulting Director of Distributed Grid Strategy Samir Succar told Utility Dive. "But there is a growing demand from the private sector for utilities to make that data public."
The "reasonable disagreement" that has emerged over whether system information should be available or guarded can be balanced, Succar said. "Different jurisdictions have different standards and priorities, but there are ways to both protect customer and critical infrastructure data and give access to DER providers who want to build where there is system value." Ardani and Villarreal agreed.
That reasonable disagreement remains unresolved, which explains the lack of progress on making hosting capacity data available, but the lack of progress on forecasting what customers will do and when they will do it is more complicated.
Progress on HCA
HCA combines interconnection data with distribution system capabilities to show the system's limits to interconnect DER, Interstate Renewable Energy Council (IREC) VP of Policy Sara Baldwin told Utility Dive. "Its granular assessment of the distribution system turns load forecasting and the contribution of DER into a combined equation that is a new paradigm for utilities and state commissions."
"Forecasting customer load is not an exact science, but DER forecasting is even trickier," she added. "Over the next couple of years, HCA best practices will be clarified as early mapping and data analysis from utilities in California, Nevada and other leading states is better understood."
One best practice is clear from California utilities' HCA efforts, Baldwin said. "The use case must be identified at the outset because HCA is an analytical tool. The use case, which in California is streamlining interconnections, leads to the analytical methodology."
The Southern California Edison (SCE) online portal's "easy login" and "simple, straightforward color coding" also demonstrates HCA best practices, she said. "It allows drilling down to the most granular level on the maps for specific PV or PV plus storage hosting capacity data."
Another important feature of SCE's tool is "technical criteria that might be violated where there is limited hosting capacity," she added. "That allows a developer to make modifications to address the potential violation."
States and utilities with high DER penetrations are already doing DSP and HCA, but nascent and emerging market states can start thinking about how and when DSP can benefit them, she added. The first step can be looking for lessons learned elsewhere.
"Two years ago, Nevada started the process and essentially adopted its own version of California's framework," Baldwin said. "They saved themselves a good five years and they are moving forward on developing HCA and NWA criteria."
Propensity to adopt
For DER to change how energy is used, new, more detailed DER forecasting is also needed, Baldwin said. "It is the piece of the planning process most in need of attention, because wrong assumptions about what will come onto the system leads to flawed planning."
Today, most utilities' adoption curves simply combine historic and current interconnection requests with things like technology advances and cost declines, Villarreal said.
But leading utilities are leveraging new sources of data to understand customers' propensity to adopt DER, ICF's Succar said. They are shifting from a "top-down" to a "bottom-up" approach that incorporates detailed data on demographics and behaviors.
"As foundational investments on the distribution system increase and give rise to the capability for more complex grid functions ... it may be appropriate for the distribution plans to increase in complexity."
VP for Regulation, Pacific Power
That "bottom-up" approach is called "propensity to adopt," ICF Director for analytics and customer insight Tim Hillman told Utility Dive. "It looks for correlations between utility customer actions and characteristics like usage patterns, demographic profiles, and housing, building and business types."
Customer actions might include participation in a new program, adopting a new rate plan, or purchasing a new technology. "The correlations are used to build models based on predictive analytics," Hillman said. "They assign a probability for what a set of customers will or will not do."
Utilities commonly leverage predictive analytics developed for mainstream marketing in direct management of customer facing programs, he added. But using it to understand customers' propensity to adopt DER is "not very prevalent at all in grid planning."
It is not clear why it is not being more widely used, Hillman said. "It may not be perceived to provide value in planning, or it may be that DER penetrations are still too low."
But "where penetrations are low, utilities can collect data to leverage in future planning because the paradigm is changing and the adoption curve will shift over time," he added.
The remaining question is when utilities will see the opportunity as worth the effort.
Will utilities play?
The Minnesota DSP framework is among the best, according to Ardani, Villarreal and Succar. But to integrate fully with resource planning, DSP must "become even more granular" to "address the challenges — and harness the benefits — of DER," Minnesota's newest plan reports.
The "nuts and bolts" of the first DSP filed in Minnesota, from Xcel Energy, is its HCA, Xcel Director of Regulatory Analysis Bria Shea told Utility Dive. The mandated annual filing includes five-year and ten-year budgets, DER forecasts based on state mandates, and an NWA analysis for any project that would cost over $2 million.
But the NWA analysis reported that solving distribution system issues with DER can be twice as expensive as traditional infrastructure upgrades, Shea said. It also showed that adequate tools for HCA and DER forecasting are lacking.
"DER will not significantly impact the bulk system for the next five years because Minnesota's DER penetration is so low," Shea said. It will "definitely have its time and place, but this DSP's biggest value may be in showing stakeholders that the utility has a finite budget and planning must prioritize limited dollars."
Filings by Portland General Electric (PGE) and Pacific Power in Oregon's DSP docket (UM 2005) similarly describe a premature process.
"For now, commitment to specific quantitative criteria is unnecessary," PGE Director for Rates and Regulatory Affairs Jay Tinker wrote. And DSP should, for now, be kept separate from IRP because the distribution and bulk power systems are "functionally distinct."
"Utilities with the highest penetrations of DER are the ones that tend to understand the value of planning their system in a manner that streamlines and optimizes the integration of more DERs."
VP for Policy, Interstate Renewable Energy Council
Though results of HCA should be publicly available, private and proprietary data must be protected, he added. And NWA analysis still needs "a discussion of alternative incentive mechanisms" that would "mitigate possible asymmetries between parties bearing risk and those bearing financial upside."
Establishing DSP principles is the "critical first step," Pacific Power VP for Regulation Etta Lockey wrote. But "any meaningful distribution planning process will require the Commission to provide clear guidance to utilities" that recognizes each utility's unique characteristics, which means principles should probably be "somewhat broad."
Initial metrics "should be simple," Lockey added. "As foundational investments on the distribution system increase and give rise to the capability for more complex grid functions, and as utilities and the Commission increase their understanding of the appropriate regulatory process and goals of distribution planning, it may be appropriate for the distribution plans to increase in complexity."
These observations by PGE and Pacific Power show a lack of urgency to take on the challenges of distribution planning described by Baldwin, Villarreal, Succar and others. Best practices in HCA already being put to work by SCE seem to come from a recognition that planning must begin now.
"Five years ago, we determined the need for distribution system infrastructure with minimal consideration of how DER could be utilized," SCE Manager of Integrated System Planning Roger Salas told Utility Dive. "Now, our HCA to streamline DER interconnection is ready."
Stakeholders and utilities also agree that a DSP is "a priority," though they continue to debate its components, Salas said.
With DER penetrations rising, California's utilities "continue to have little visibility of the distribution system," he added. "We need better tools because adequate planning is difficult if we cannot see the DER and how they impact load."
That is important. "Utilities with the highest penetrations of DER are the ones that tend to understand the value of planning their system in a manner that streamlines and optimizes the integration of more DERs," Baldwin said.