Cost-effectively achieving clean energy policy goals requires integrating a rising number of distributed energy resources, or DER, into a whole system planning strategy, utilities and analysts agree.

New data analytics show power system planners can affordably and reliably use customer-owned DER to meet demand spikes instead of fossil fuels or infrastructure upgrades, many stakeholders said. And Federal Energy Regulatory Commission Order 2222, which requires integration of DER into wholesale markets, makes planning for DER growth critical, they also agree.

But there are barriers to effective distribution system planning, or DSP, and to merging its analytic insights into comprehensive electricity planning, analysts and stakeholders said. 

“Planning is only as accurate as the data input” and today’s power system planning tools cannot address the “exponentially more complex datasets” of today’s resource mix transitions to more clean and distributed energy, said Xcel Energy Senior Vice President, System Strategy and Chief Planning Officer, Alice Jackson. The “yellow brick road to affordable, reliable power” is “new technologies that integrate distribution and bulk system planning,” she added.

Traditional infrastructure “cannot be built fast enough to meet the coming electrification load” by reacting as utilities now do “to customer interconnection requests,” added Julieta Giraldez, director of grid planning, for data analytics specialist Kevala. “Proactive and coordinated” distribution and bulk system planning is necessary “because you can't do one efficiently without the other,” she added.

But there are critical challenges to addressing the new planning complexities, stakeholders said. Advanced data analytics and modeling must be more widely used for planning insights about customer adoption and use of DER, utilities and analysts said. And utilities and system operators must be convinced that probabilistic data can reliably inform a new integrated distribution and bulk system planning paradigm, they added.

The new distribution system planning

“Monumental shifts in consumer needs and expectations” make innovative solutions for distribution system planning necessary, according to a November 2022 assessment of current utility planning practices from the National Renewable Energy Laboratory, or NREL.

Electrification loads are forcing a “rethinking” of planning for the distribution system “and for the need to include DER into load management,” said NREL Researcher Jeremy Keen, the paper’s lead author.

With better DSP practices, utilities can identify “cost-effective solutions” to the “uncertainty in the size, location, and timing of future load growth,” the NREL report said. Better practices include “more granular modeling and forecasting, deeper modeling of transmission and distribution system interactions, and improved modeling of uncertainty and risk,” NREL added.

Versions of DSP are required by 26 states, according to a June 2022 report from the Department of Energy’s Grid Modernization Laboratory Consortium. And in Q2 2023, 22 states considered new or revised DSP policies, according to the most recent North Carolina Clean Energy Technology Center, or NCCETC, Grid Modernization policy update.

DOE’s 2020 DSP initiative “is an example of a more systematic planning process that begins with identifying the utility’s values and objectives” and leads to “the most cost-effective investments,” Keen said. 

Planning innovations are needed because electrification “could increase distribution system loads exponentially, making them the binding reliability constraint,” said Marissa Hummon, chief technology officer for distribution system data specialist Utilidata.

Meeting those new loads will require “hyper-granular locational and temporal DER data analytics” to inform planning from the customer level up,” added Kevala’s Giraldez, an NREL paper co-author.

But with advanced analytic tools allowing better DER forecasting, “DER flexibility can be used to help meet system reliability needs,” said Commissioner Matt Schuerger of the Minnesota Public Utilities Commission. Led by the commission, Xcel Minnesota “is planning for significant DER growth” and “is evolving modeling granularity to meet coming electrification loads,” he added.

Bulk system integrated resource planning, or IRP, “is no longer enough” because variable renewables and dynamic distribution system loads “make reliability a challenge all 8,760 hours of the year,” Schuerger said. And FERC Order 2222 will accelerate the need to recognize DER in distribution and bulk system planning, he added.

The Order 2222-driven integration of DER into organized power markets will take planning a step further, stakeholders agree.

FERC Order 2222

FERC Order 2222 is intended to remove barriers to DER competing in regional systems’ “organized capacity, energy and ancillary services markets,” according to a commission fact sheet.

For many utilities working on DSP, Order 2222 is still “in the background,” said Environmental Law and Policy Center Senior Attorney Bradley Klein. But new planning approaches can help state regulators decide if DER growth will benefit the power system and if increased ratepayer costs for technologies to manage DER growth are worth those benefits, he added.

Distribution system technologies “can orchestrate electron flows at millions of nodes but a holistic view of the hundred-year-old power system’s transformation is needed,” said Duquesne Light Company Director, Advanced Grid Systems and Grid Modernization, Elizabeth Cook. “FERC Order 2222 highlights the need for an integrated planning approach to that whole power system solution,” she said.

By driving DSP and IRP integration, “Order 2222 could have significant impacts on larger market fundamentals and drivers,” and “change the economics of aggregated DER,” added Andy Eiden, Portland General Electric principal planning and strategy analyst and NREL paper contributor.

Utilities are already proposing capital expenditures for DER Management Systems, or DERMS, “which increase distribution system visibility,” Kevala’s Giraldez added. But DERMS will not provide capabilities needed to comply with Order 2222 like proactive premises-level behavioral analysis and modeling of customer DER adoption to develop time and location forecasts,” she said.

Xcel is integrating enabling technologies to increase control room intelligence and outage management, said Jackson. But DERMS technologies are not yet available to meet all of the Order 2222 planning requirements, she agreed with Giraldez.

Due to Order 2222, the Midcontinent Independent System Operator, or MISO, “recognized it has to have greater visibility of DER to forecast where loads will be and what reliability resources will be needed,” Commissioner Schuerger said. But MISO found technology integration necessities “required pushing implementation of its Order 2222 plan for deploying systems to monitor DER out to 2029,” he added.

MISO’s delay is “unlikely to interfere with Minnesota’s work” to integrate distribution and bulk system planning, Schuerger said. “But MISO would benefit from getting those systems in place soon because DER penetrations continue to grow,” he added.

That makes integration of IRP and DSP the critical next step for planning, stakeholders widely agree.

The benefits of integration

Over 35 states require power providers to file IRPs or equivalent planning documents, though the requirements vary by provider “type, size, and business model,” according to a March 2021 report from DOE’s Pacific Northwest National Laboratory.

Among the 19 states that addressed IRP policy in the second quarter of 2023, Duke Energy Carolinas’ Integrated System and Operations Plan, or ISOP, was one of the most innovative tests of the value of integrating DSP and IRP planning, NCCETC Associate Director, Policy and Markets, Autumn Proudlove said.

Cumulative utility capital expenditure proposals “of more than $100 billion per year” should consider the full range of cost-effective flexible, clean energy investment options, reported a 2021 blueprint for integrated planning by a 15-state National Association of Regulatory Utility Commissioners-National Association of State Energy Officials joint task force.

“More holistic analysis” of system-wide planning processes can improve reliability, optimize resource use, avoid unnecessary costs, and support policy, it added.

The April 2022 Minnesota commission order for Xcel Energy to better synchronize its IRP and DSP was because Minnesota has "significant DER growth” and because "integrated planning is where the key decisions are made” about the future resource mix, Commissioner Schuerger said.

Multiple Minnesota stakeholders, including consumer and solar advocates, agreed the current Xcel DSP does not align with the utility’s bulk system planning, the order reported. But an improved DSP process will expand “the options to be analyzed in resource planning,” it added.

Integrated planning can more “fully and fairly value all energy resources,” and provide “a robust analysis of operational impacts and benefits of integrating DER and non-traditional solutions,” a June 2023 NREL analysis of the Duke Energy ISOP framework reported.

Duke Energy Carolinas planning teams are making “significant strides” to increase visibility into future impacts of distribution system resources, said Duke Energy Director of Integrated Optimization Mike Rib. The objective is to “help manage operations at the circuit level” and to “inform our resource needs at the system level,” he added.

But it is not yet established that a portfolio of distribution system investments “will balance competing objectives such as cost, risk, and reliability,” the NREL paper on Duke’s ISOP concluded. That analysis is “an emerging challenge” for planners, NREL added.

Many utilities recognize the challenge, and some are taking it on.

Utilities seeking data

Utilities working toward integrated power system resource planning face a significant obstacle but there are solutions, some stakeholders said.

“Today’s bulk and distribution system loads and resources are becoming more intertwined,” Xcel’s Jackson said. With growing customer dependence on electricity, that intertwining will require “a dramatic shift toward integrated planning” and “optimizing controllable, flexible, reliable DER,” she added.

There are, however, “gaps in the tools that can optimize planning” for the “dynamic and continuously changing distribution system,” Jackson acknowledged. Integrating planning is like “building a yellow brick road to the future with the technology, cost-effectiveness, and reliability questions among the many bricks to still be put in place,” but “building this road will be truly transformational,” she added.

It is not “if” DER will have a key role in meeting load, it is “when and where and which assets will be most cost-effective for utilities and customers,” agreed Duquesne’s Cook. “The solution is no longer more system hardware, it is planning to intelligently manage hundreds of millions of DER nodes in near real time by modeling with new computational power and newly accessible data, she said.

Utilities that do not trust new planning models “may remain complacent” because they do not see how distribution system analytics investments are prudent, Cook said. But utilities that use power flow analytics in integrated system planning “can change the world through enhanced awareness” of the optimal investments, she added.

With geometric growth of DER expected in its territory, Portland General Electric “recently consolidated planning functions to streamline decision-making,” Principal Planning and Strategy Analyst Eiden said. DSP and IRP teams “are now working closely under a single director toward merging modeling from both planning units to make optimal resource decisions,” Eiden added.

But merging DSP and IRP enlarges the planning process and not all stakeholders welcome the challenges that brings.

The big plan problems

Some stakeholders see integrating DSP and IRP as adding unwelcome complexity to the already complex process of planning the future resource mix

Integrating planning “is not the solution” because it would be prohibitively expensive and time consuming, said Josh Keeling, vice president, markets and programs, for battery and generator supplier Generac. “Planning could be done at the community level and system operators could shape rules to encourage market solutions,” he added.

But “power lines take 10 years to build, and the coming electrification load will constrain operations much sooner,” objected Kevala’s Giraldez. Integrated planning with “multi-objective planning analytics and customer-level data can bridge the time gap by linking DER adoption forecasts and bulk system load and supply forecasts,” she added.

Better DSP and an integrated DSP-IRP process “will be more important as demand peaks become the reliability problem,” agreed independent consultant Chris Villarreal, a former California and Minnesota public utility commission staffer. But regulatory impediments “will take years to resolve because the new approaches have to be implemented through laborious legislative and regulatory processes,” he added.

A key regulatory impediment is that “capital expenditures for infrastructure earn the utility a regulated return, but using aggregated DER to defer those expenditures reduces returns,” said Regulatory Assistance Project Principal Carl Linvill, a former Nevada utilities commissioner. Another impediment is utility and regulator skepticism that data analytics can show aggregated DER to be reliable,” he added.

“The steps to comprehensive electricity planning are, therefore, first obtain granular, transparent system data and then use it to validate DER reliability,” Linvill added.