The three keys to distributed energy resources’ value to a utility's distribution system are the same as the keys to real estate's value – location, location, location.
In New York and California, which are leading the work to value distributed energy resources (DER), distribution system planning is a growth industry. Determining DER's locational value is that industry’s key target, which explains why “hosting capacity analysis” (HCA) have become the buzzwords heard more and more in locational analysis debates.
The initial purpose of HCA, called integration capacity analysis (ICA) in California, was to make DER interconnections faster and more efficient. If a utility could know the feeder-level DER penetrations throughout its distribution system, it could immediately approve an application for a new DER installation. Or it could inform the applicant a distribution system infrastructure upgrade is needed to accommodate new DER.
That granular knowledge of the distribution system is something very different to key stakeholders. To DER advocates, it is the holy grail and should be implemented yesterday because it opens access to right-now marketing. To utilities, it is an unprecedented incursion into their systems, warranted by customer demand but to be implemented judiciously and methodically.
Utilities should seize this opportunity, according to Sky Stanfield, lead author of the just-released “Optimizing the Grid: A Regulator's Guide to Hosting Capacity Analyses for Distributed Energy Resources,” from the Interstate Renewable Energy Council (IREC).
At the center of the different views about HCA is a debate about how it is calculated. IREC's paper describes three methodologies, each with a different application and level of computational complexity. Many utilities use a fourth, the Distribution Resource Integration and Value Estimation (DRIVE) Tool developed by the Electric Power Research Institute (EPRI).
HCA is part of “the bigger conversation about utility business models,” Stanfield told Utility Dive. “Under the traditional framework, utilities could make rate-based investments to meet load, but not to accommodate DER. That’s where the shift is.”
HCA can help utilities identify investment opportunities and can help regulators see that the investments are reasonable and prudent and, therefore, should be rate-based, she said.
Hosting capacity is “the amount of DERs that can be accommodated on the distribution system at a given time and at a given location under existing grid conditions and operations,” according to IREC's paper. There is capacity to host new DER if it does not threaten "safety, power quality, reliability or other operational criteria” and it does not require “significant infrastructure upgrades.”
The IREC paper takes on three controversial topics. First, it identifies the three main HCA use cases, which are DER interconnection, distribution system planning, and defining DER locational value. Second, it describes the methodologies used to do the analysis. Third, it recommends ways to advance HCA implementation.
Southern California Edison (SCE) Director of Electric System Planning and Grid Modernization Eric Takayesu said the paper offers “good information” but is “premature.” Much of what it describes has not yet been implemented and “likely will undergo changes along the way to implementation,” he said.
Data on which to base final decisions are "not provided by current metering technologies,” Takayesu said. Before final choices about HCA can be made, output from distribution system operations must be compared to the assumptions and models used in the analysis.
Pacific Gas and Electric (PG&E) Director of Integrated Grid Planning, Grid Integration and Innovation Mark Esguerra agreed. The paper “is a good guide for regulators, but we’ll probably have more breakthroughs once we start gathering actual data and comparing it with what we’ve computed.”
IREC’s Stanfield said it is time to deal with HCA because its first use case is allowing interconnection of the higher volumes of DER that customer demand is now driving at utilities, while limiting impacts on staff time and budget.
The next HCA use case is distribution system planning, she said. With more granular system insight, utilities can interconnect projects with more certainty that their systems will not be disrupted, Stanfield said. And they will be able to direct projects to locations where they will benefit the system and be eligible for cost recovery.
“That’s the carrot,” Stanfield said. “The stick is regulators' demand that utilities go beyond interconnecting DER to integrating them.”
That third use case identifies the locational value of DER. HCA is not the entire solution “but a location-specific understanding of the state of the grid is necessary to know where DER should go,” Stanfield said.
Where HCA reveals future system constraints, price signals can mitigate or prevent the constraints, she said. “Getting the right price signal “will be complicated, but that’s where this is headed.”
The paper’s first recommendation to regulators is that they work with a full range of stakeholders, including utilities and customers, to identify what HCA will be used for, Stanfield said. “They will determine the right methodology.”
A meaningful stakeholder process can help regulators identify the HCA that will achieve state policy, she added. The process should be open, transparent and “agnostic” to DER technologies. It should include demonstration projects that validate the accuracy of the HCA periodically through real world testing. And it should take advantage of lessons learned by other states and utilities.
But the paper is not intended to show that HCA is difficult, Stanfield insisted. It is intended to show that, with attention to the details, implementing HCA is doable.
The debate about methodologies
“A well-considered methodology for determining hosting capacity is necessary, given the variety of factors that affect the grid’s ability to host a wide range of DERs,” the paper argues. Regulators and stakeholders should understand the three basic categories of HCA methodologies, their function, their capabilities and their limitations, it adds.
IREC and the utilities agree that none of the HCA methodologies is adequate.
The “streamlined” method uses “simplified algorithms,” IREC reports. It is the fastest method because it approximates system variables to determine DER limits at distribution system nodes.
The “iterative” method is the slowest, most detailed, and most computationally demanding. It “directly models DERs on the distribution grid to identify hosting capacity limitations,” IREC reports. “A power flow simulation is run iteratively at each node” until “one of the four power system limitations” is reached.
The “stochastic” method uses a model of the existing distribution system and adds in DER at “randomly selected” feeders, IREC reports. It estimates a hosting capacity “range” based on data from the tested feeders.
Each methodology will produce a hosting capacity that is limited by its model of the system and its assumptions. Each, therefore, has limited "usefulness," the paper reports.
SCE’s Takayesu said IREC’s evaluation of methodologies is “adequate” at “a high level” but lacks real world data that proves its conclusions.
PG&E’s Esguerra said his utility was ordered by the California Public Utilities Commission (CPUC) to focus on the iterative methodology and the interconnection use case. The streamlined method is “more for overall long-term planning because it only requires a forecast for a certain amount of generation in a range of areas.”
The IREC paper’s stochastic method is what PG&E describes as an “iterative stochastic” methodology, Esguerra said.
A fourth is a “streamlined stochastic” methodology incorporated into the EPRI Drive Tool and used by utilities outside California, he added.
EPRI DRIVE tool
Consolidated Edison (ConEd) Director for Distributed Resource Integration Damian Sciano told Utility Dive ConEd selected the EPRI DRIVE Tool for two reasons. “It was the closest thing to a national standard,” Sciano said. “And it incorporates lessons learned in California and elsewhere.”
EPRI VP Mark McGranaghan told Utility Dive the IREC paper is “very welcome.” It “provides an excellent framework for discussion” about HCA’s importance and its potential roles in locational value and integrated distribution system planning, he added. But its evaluation of the DRIVE Tool is, in some ways, “simply not true.”
The DRIVE Tool was chosen by New York state utilities and Minnesota’s Xcel Energy, IREC's paper acknowledged. It has an “off-the-shelf” appeal and “computational efficiency relative to iterative methods.”
California’s demonstration projects showed a streamlined methodology based on a version of DRIVE “was not appropriate for certain use cases, particularly interconnection,” IREC reported. And because of DRIVE’s limitations, “Xcel did not include in its analysis existing or forecasted DERs, and it did not apply mitigations to determine if hosting capacity could be increased.”
McGranaghan said California chose the iterative methodology because they evaluated an earlier version of DRIVE. “We recently did a project with San Diego Gas and Electric that got the same results with the DRIVE tool and the iterative method.”
IREC argues “it is not yet clear whether any differences between the streamlined method used in California and the one deployed by EPRI result in appreciably different outcomes.”
McGranaghan insisted DRIVE does address the interconnection use case and IREC “just got that wrong.” Further, “DRIVE is not one of IREC’s three categories, it is a fourth category by itself,” he said.
The IREC paper also fails to recognize the more important “impact factors” that enable HCA “to forecast customer load and characteristics in the future,” McGranaghan argued.
“Impact factors include the effects of energy efficiency, transportation electrification, demand response and new rate structures,” he said. They also include new distribution system technologies and customer response to the factors.
McGranaghan endorsed some IREC recommendations. He agreed that data requirements should be simplified and the analysis should phase in more detail. He also agreed HCA should manage multiple customer scenarios, like those that foresee high adoption of EVs, new rate structures and other impact factors.
He agreed that HCA should model more of the distribution system and, at the same time, be capable of more frequent updating. And he agreed HCA should be technology neutral and transparent.
McGranaghan, Stanfield and all the utility experts agreed HCA will evolve and become more accurate with less computation complexity.
But McGranaghan, Takayesu and Esguerra objected to IREC’s recommendation that regulators select one of the methodologies and move ahead with implementation.
That “stifles innovation” and limits the emergence of “new solutions” to address the growing complexity of distribution systems, McGranaghan said.
SCE’s Takayesu noted that methodologies to address all use cases “will improve over time,” while PG&E’s Esguerra said HCA “is still a relatively new concept.” Before integrating HCA into distribution system processes, “we need actual data and a pilot,” Esguerra said. “And at what cost?”
Before introducing HCA, he added, “we would like to add new visibility and monitoring of our distribution system."
ConEd’s Sciano said DRIVE is sufficient while New York’s DER penetration is 2% to 3%. “The next level is identifying where non-wires solutions can earn greater returns because of locational value,” he said. And getting to a granular value of DER takes HCA “to a third level,” he added.
“Eventually it gets to the transactive energy marketplace, but that’s probably quite some time off," Sciano said. "Right now, the EPRI tool is working just fine and is constantly evolving.” IREC is looking for “more granular and more dynamic calculations and pushing the technology and the analysis as far as it can go,” he added.
Stanfield said IREC wants to adopt and improve a version of the iterative method to prepare utilities to manage the coming customer-driven wave of DER interconnections. "But this is still evolving and we are going to find ways to better manage the data," she agreed.
Utilities are understandably uncomfortable with HCA because it makes much of their proprietary information public, which raises privacy and accuracy issues and workload concerns, she acknowledged. “Many utilities are deploying a version of this internally but not publicly. But if the information is shared in a meaningful form, DER developers can bring solutions to utilities.”
DER demand is growing because customers want to engage with their energy bills and move to distributed generation, Stanfield said. “HCA will enable DER deployment in a way that benefits customers, avoids system impacts and can have system benefits.”