Utilities' ability to protect reliability in today's rapid transition to variable, distributed generation faces two key barriers and regulators' help is needed to overcome them.
Advanced demand response (DR) can use the flexibility of customer-owned technologies to meet the balancing challenges of the changing supply mix, regulators and utility executives agreed during an Oct. 20 symposium hosted by The Brattle Group. Utility pilots are revealing what works, but also showing how technology and incentive structures are keeping flexible loads, such as customer-owned solar and smart thermostats, from supporting reliability.
"Load flexibility can shift energy use to when it costs less, shape energy use to match renewables' availability, and to allow them to meet other system needs," said Minnesota Public Service Matt Schuerger during the symposium. "And it can be a cost-effective solution for reliability by offsetting other investments in generation with lower-cost customer-owned distributed technologies."
That cost-effectiveness may soon make the flexibility of advanced DR valuable.
"As transportation and building electrification initiatives grow, flexibility might become necessary for utilities to manage cost," said symposium co-chair and Brattle Group Principal Ryan Hledik. In fact, "the regulatory approval of grid modernization investments to support electrification, decarbonization, and increase utility revenues could be justified by the cost-effectiveness of flexibility."
Utility advanced DR pilots are growing, but regulators have only begun to resolve the two key barriers of finding technologies to manage distribution systems and creating incentives for stakeholders, Brattle's symposium revealed. Inadequate system controls and compensation mechanisms have left load flexibility's enormous potential to meet U.S. reliability needs little used, participants agreed.
The potential of advanced DR
Almost 70% of today's approximately 60 GW of U.S. DR capability comes from traditional commercial-industrial load management, according to a June 2019 Brattle study. But new demand-side smart technologies, utility control and communications technologies could transfer market dominance to residential customers within the next ten years, according to Brattle.
The resulting nearly 200 GW of cost-effective load flexibility from existing and new DR could meet up to 20% of the estimated 2030 U.S. peak load, avoiding over $15 billion annually in system costs, Brattle found. Existing incentives and technologies can deliver an estimated 40% of the new load flexibility capacity, but the other 60% will require new technology and incentive solutions.
"The question is no longer whether load flexibility is reliable, but whether utilities, regulators and stakeholders want to do it."
Ryan Hledik
Principal, The Brattle Group
The bulk of the 2030 value will be in avoided capital expenditures for new generation, Brattle estimated. Avoided expenditures for transmission and distribution infrastructure and for ancillary services will also add value.
Regulators can advance load flexibility in two key ways, symposium participants agreed. Regulators can approve trials to improve hardware and software, like advanced distribution management systems (ADMS) and distributed energy resource management systems (DERMS), needed for utilities to manage customer-owned smart devices.
They can also give utilities the incentive to move away from investments in generation and other system infrastructure by allowing them comparable returns for investments in customer-sited flexible technologies, the symposium speakers said.
Driven by competition from distributed energy resources (DER) providers, new utility programs have shown load flexibility can be reliable. "The question is no longer whether load flexibility is reliable, but whether utilities, regulators and stakeholders want to do it," Brattle's Hledik said. "Some are starting to understand how demand-side resources can lower system costs and increase their systems' flexibility."
Utilities and regulators are demonstrating that new understanding through pilots.
The technology barrier
Pilots are a way to break down the technology barriers, utilities and regulators told the symposium.
Xcel Energy Minnesota is developing a variety of DER-based peak reduction programs that allow customers to give the utility control of smart thermostats and appliances. But Xcel-commissioned research by Brattle showed a limited value proposition in peak shaving and grid services until utility control-room management of the flexibility from DERs improves, Xcel Senior Regulatory Analyst Jessica Peterson told the symposium.
Since 2015, Xcel's strategy to expand use of DERs has been to evolve "toward flexibility" by gradually introducing advanced practices like controlling customer thermostats and devices, Peterson said. With its learning, it has set higher goals for advanced DR programs using customer-sited resources.
But distribution system control "technology is a huge challenge right now because it needs to evolve more to meet utilities' needs," she said. Xcel chose a DERMS system that it found could not connect to all its customer's devices. "We need to be able to connect with and control any equipment a customer or third party may want to use and we're still looking for that technology."
A big step forward would be streamlining the regulatory approval process "so we can move more quickly to trials of unproven new technologies," she added.
Minnesota's utility commission acknowledged Xcel's concerns in its 2017 order approving the company's last integrated resource plan, Commissioner Schuerger said. The order required 400 MW of additional DR by 2023, a full and thorough cost effectiveness study, and an evaluation of new advanced DR and load flexibility technologies.
Minnesota's resource mix is changing rapidly, Commissioner Schuerger said. To support an expected 45% or higher renewables penetration by 2030, the commission is evaluating investments in distribution grid modernization and focusing on "overcoming technology barriers," he added.
"The technologies load flexibility depends on may be acceptable for cell phones but not for electric system reliability."
Phil Markham
Smart Buildings Research and Development Manager, Southern Company
Portland General Electric (PGE) was an early leader in testing load flexibility.
It began with limited smart thermostat, residential storage, grid integrated water heating, and smart EV charging programs, its Manager of the Customer Program Portfolio Jason Salmi Klotz told the symposium.
Its proposed smart grid test bed program would pilot smart devices and appliances controlled through new communications technologies, Salmi Klotz said. The program aims to better understand the values and services flexibility can offer to the distribution and bulk electric systems. It will also explore customer rate design preferences and other factors impacting customer participation.
But there are challenges ahead, PGE Director of Retail Technology Strategy Conrad Eustis told Utility Dive in 2019. The lack of customer devices with the needed communications capabilities may prevent Brattle's 200 GW load flexibility forecast for 2030 from being realized until 2050.
Utilities and commissioners have every right to be concerned about inadequate system controls, but "we can develop any technology to meet customer needs," Salmi Klotz said. Though PGE's test bed will demonstrate new ADMS and DERMS breakthroughs, he shares Xcel's concerns about the lack of interoperability and open standards that prevent visibility and management of all customer technologies, and have already imposed costs on PGE customers.
"Closing the communications standards gap would accelerate our ability to develop and deliver cost effective solutions," he said. Technology is a baseline issue, but Oregon regulators are working with PGE "to open that discussion about solutions."
"The technologies load flexibility depends on may be acceptable for cell phones but not for electric system reliability," said Phil Markham, smart buildings research and development manager for Southern Company and its subsidiaries in Alabama, Mississippi and Georgia. Flexibility "could be a threat to grid stability" without "granular control," he added.
But because load flexibility is a part of decarbonization, it offers "opportunities to make capital investments in electrification," he added. Regulators need to support research on "communications with open standards to allow utilities to connect through a reliable communications network with the range of customer technologies," he said, endorsing the Xcel and PGE position.
"Regulators need to create the space for utilities and third parties to innovate and create financial rewards."
Jennifer Davidson
CFO, Sacramento Municipal Utility District
Streamlining the development of new technologies like energy management systems is "essential" to adding load flexibility, spokesperson Craig Bell for Southern Company subsidiary Georgia Power agreed. That is the "goal" of the load flexibility pilots it has proposed to Georgia's regulators.
"I'm hired to understand and prepare Georgia for what will be needed in the future," Georgia Public Service Commission Vice Chair Tim Echols told the symposium. The legislatively mandated integrated resource planning process includes "a pilot project opportunity" that allows regulators to green light load flexibility trials and the commission has multiple innovation sandboxes on DER ongoing.
"Regulators need to create the space for utilities and third parties to innovate and create financial rewards," Sacramento Municipal Utility District CFO Jennifer Davidson told the symposium. "We cannot do it alone. The need for innovation is too big."
But Hledik said the technology barrier is already being addressed. "Utility pilots and small programs are using technologies to communicate with customer-owned smart devices and DER," he insisted. "It may not be the level of sophistication some utilities would like, but it's been enough to meet system needs."
The other barrier to load flexibility is the disincentive in the state regulatory model to utility investment in flexibility technologies, but that can be addressed, Hledik said.
The incentive barrier
Breaking down the incentive barrier may be more complicated.
PGE's test bed may allow trials of innovative transactive or subscription rates that provide compensation to customers for allowing the utility to use their DER for load flexibility, but if they are scaled, they would have to be worked into the traditional regulatory model, Salmi Klotz said.
There are also discussions with Oregon regulators to address the incentive barrier through a new specially designed compensation rate to participants in load flexibility programs based on the value of the service they provide, he added.
It is possible the test bed could trial direct monetary incentives to customers, but PGE is still working on how to structure them, Salmi Klotz said. It will likely require "layering incentives" to get adequately high "levels of engagement and participation."
The other approach is compensation to utilities that offset their losses of guaranteed returns for infrastructure investments, he said. That could be through performance-based regulation incentivizing load flexibility additions, or adjusting the utility's rate of return to make using flexibility as beneficial to the utility bottom line as capital expenditures on central generation.
Introducing those kinds of changes "does not have to be a barrier if the utility's approach is customer-centric," Salmi Klotz said. "The regulatory compact is based on service in the public interest and load flexibility is in the public interest because it gives customers a way to lower their bills and makes the utility a tool for policy implementation, which justifies a rate of return for supporting flexibility."
"There is a real danger of letting the perfect be the enemy of the good. To protect ratepayers, we have to develop new programs, learn from them, and move forward."
Matt Schuerger
Commissioner, Minnesota Public Utilities Commission
The Minnesota commission has been "actively evaluating and advancing" performance-based regulation, Commissioner Schuerger said. The objective is developing performance metrics that "cost-effectively align generation with load and reduce peak demand."
Xcel is already working under a multi-year rate plan and, with stakeholder input, has identified performance-based goals, outcomes and metrics, he added. "Xcel's Q1 2021 report on its performance, using those metrics for the first time, is expected to lead to data-based performance incentives for advanced DR and load flexibility."
But the new metrics, and the incentives they could lead to, "are intended to improve and evolve the traditional cost of service ratemaking paradigm, not replace it," Schuerger stressed. "They can also evolve traditional DR into more flexible advanced DR," he said.
The next big question
Regulators and utilities must break down these barriers, but they also must take the next big step, Brattle's Hledik said.
Through 2030, load flexibility will "get smarter" and then "get bigger," growth will be led by residential customers with new access to smart devices, and regulators will support pilots, Brattle predicted in its 2019 paper.
But a lot of pilots, which are important when they test new and unproven features of flexibility, "will never become full-scale programs," Hledik said. "They are being done without planning for full-scale deployment, and without that planning, there is a strong possibility there will be no further deployment."
That is an indicator of "the bigger problems" of mistrust of technologies and of not addressing the disincentive to investment, he said. "Pilots have shown and are showing flexibility saves system and customer costs and they should be scaled."
Scaling flexibilty pilots is important, Commissioner Schuerger agreed during the symposium.
"There is a risk to ratepayers and to the public interest of not developing new load flexibility programs," he said. "Institutional inertia could lead to addressing reliability with investments that could become stranded, increasing costs to ratepayers."
The record before the Minnesota commission "shows advanced demand response and load flexibility are cost effective," Schuerger said. "There is a real danger of letting the perfect be the enemy of the good. To protect ratepayers, we have to develop new programs, learn from them, and move forward."
