High electricity rates impede crucial but costly technology investments to manage rising DER levels: utilities

The clean energy transition makes the question of how distributed energy resources, or DERs, fit in the future energy mix particularly urgent, utilities and DER advocates agree.

The technical potential of DER like rooftop solar, batteries, electric vehicles, and flexible industrial and building loads like smart water heaters and heat pumps could “play a significant role” in a 100% clean energy mix, an August Department of Energy study found.

With adequate “distribution system visibility and control” of DERs, they can “help protect system reliability and resiliency,” agreed Xcel Energy Colorado President Robert Kenney. But “the cost of new technologies to manage those resources threatens rate affordability and slows deployment because regulators and utilities face the responsibility to balance stakeholder concerns,” he added.

Integrating high DER penetrations into power system operations will ultimately require significant investments in technologies like Advanced Distribution Management Systems, or ADMS, and Distributed Energy Resource Management Systems, or DERMS, utility representatives and DER advocates acknowledged. The question is how and when those investments are made.

Transportation and building electrification, constraints on bulk system resource delivery, and consumer demand “require addressing DER growth,” Generac VP, Markets and Programs, Josh Keeling, a former Portland General Electric executive, said. But a staged deployment of technologies to manage them “can reduce their costs and burdens and benefit customers and power systems over the long term,” he said.

A “national initiative” and stakeholder dialogue can build a framework for that staged DER integration to protect affordability and reliability for customers, according to recent papers from a group of DER advocates. But advocates underestimate the urgency of investments in distribution system situational awareness for managing DER and limitations of the nation’s divided regulatory jurisdictions to approve them, utilities said.

A DER framework

A “broadly inclusive” national initiative could engage federal and state regulators, investor-owned, municipal and cooperative utilities, DER advocates, and their national associations, according to January and August 2022 papers from the Energy Systems Integration Group, or ESIG, DER Task Force, a committee of the non-profit organization focused on independent analysis of the power system’s future.

The initiative’s objectives are “a common vocabulary, framework, and vision,” for stakeholders that leads to near-term, “least-regrets strategies” and a “structured dialogue” on longer-term challenges of integrating customer-owned resources into the utility-controlled distribution system, ESIG said.

The proposed work could build on DOE’s 2019 distribution system studies, Federal Energy Regulatory Commission Order 2222 work on integrating DER into wholesale markets, and the NARUC-NASEO task force effort to make DER more useful and safer for distribution system operators, ESIG added.

DER penetrations, regulation, and goals vary by regulatory regimes, localities, and technology types but DER are transforming the meaning of reliability everywhere, ESIG said. A national initiative to safely and cost-effectively integrate DER can recognize jurisdictional autonomy and enable new stakeholder opportunities by identifying commonalities in current “disparate standards, terminology, and approaches,” the group added.

A first track would start with “relatively minor changes” to existing DER integration practices, it said. A second track would be about using current best practices to develop new national standards for integrating DER with “fundamental changes” to federal and state regulation, markets, and system planning, ESIG said.

A long-term third track could lead to new utility regulation and business models, ESIG added. The power sector is “too diverse and complex” for one solution, but a key decision point in each jurisdiction will be whether DER aggregators, load-serving entities or distribution system operators manage and coordinate DER with bulk markets and systems, ESIG said.

The initiative can “start stakeholder conversations on complicated questions like planning, ownership and operation of DER,” said GridLab Program Director and project lead author Priya Sreedharan. When each jurisdiction’s choices from the initiative’s “suite of solutions” are selected, “the hard work begins for regulators to implement stakeholders’ choices based on that jurisdiction’s parameters,” she said.

DER is “a fraction of power system resources in most large states’ economies, but Hawaii and California are demonstrating what can happen nationally” when penetrations rise, said Independent Consultant and ESIG papers co-author Fredrich Kahrl. The ESIG initiative can allow regulators, utilities and stakeholders “to coordinate bulk and distribution system operations,” he said.

In the near term, interconnection practices, DER curtailment rules, and communications from utilities to aggregators about outages “can be improved with existing software and hardware tools,” GridLab’s Sreedharan said. “That is a least-regrets strategy because it leaves decisions about major technology investments until higher penetrations of DER emerge,” she added.

Though utilities widely agreed with DER advocates about the potential value, they do not agree with ESIG’s proposals on facilitating DER integration to realize that value.

What utilities want

Postponing investments in grid modernization technologies needed to integrate the rising DER penetrations until they reach undefined higher levels “has only led to DER growth and not to more system value,” Edison Electric Institute General Counsel, Corporate Secretary, and Senior Vice President, Clean Energy, Emily Fisher said, echoing Xcel Colorado’s Kenney call for technology investment.

Utilities will need “much greater situational awareness of DER performance” to obtain system and customer benefits, agreed David Castle, senior manager of grid modernization policy, with Southern California Edison, a national DER penetration leader that has debated with regulators and stakeholders about spending on new technologies to support DER integration for several years. 

Instead of identifying the DER penetration at which new technologies will be needed, “proponents kick questions about those investments down the road,” Fisher said. “That is not a useful way of addressing any issue, especially when it is clear investments to protect reliability are important.”

“ESIG intentionally did not define a penetration at which more distribution system visibility, monitoring, and control capabilities will be needed,” responded ESIG co-author Kahrl. It will depend on specifics that are left to each jurisdiction like whether DER aggregators, load-serving entities, or distribution system operators manage and coordinate DER, he said.

Utilities want the best technologies to meet their responsibility for reliability, acknowledged Generac’s Keeling. But “the ESIG initiative would first reach functional definitions of visibility and control, which can change stakeholders’ understanding of how existing technologies can be leveraged and when new investments are needed,” he said.

Power providers supplied by Guzman Energy “have found they already have sufficient visibility and control of DER to protect reliability,” said Steve Beuning, senior advisor, market design and integration, for Guzman, which supplies Holy Cross Energy and other Western cooperatives. “A sufficient level does not have to be a perfect and complicated level that prevents reducing customer costs,” he added.

New operations and technologies may not be needed immediately, but “investments are needed now so utilities can be ready when DER penetrations require it,” EEI’s Fisher responded. And “the real challenge is that DER growth will be customer-driven and not in any way orderly,” she said.

“Those DERs might be valuable to individual customers, but they will have very different system reliability benefits at different locations,” she said. “Proponents’ contention that DER have system value is undercut if they do not support investments in technologies to obtain that locationally-specific value,” she added.

Utilities need situational awareness of DER on their systems and that need will grow as federal funding accelerates deployment, acknowledged Plugged In Strategies President Chris Villarreal, a former staffer at the California and Minnesota utility commissions. But the ESIG national initiative would “identify the most efficient ways to use utility investments,” he said.

A DER integration framework “which identifies the best locations for specific DER may be theoretically possible,” Fisher responded. But “the current customer-centric regulatory approach is to accommodate customer DER additions wherever they are located, whether or not they add system value,” she said.

Current U.S. power sector regulation was designed for a centralized system, and it needs to evolve to help utilities and other stakeholders address DER integration and more decentralized solutions, Xcel Colorado’s Kenney agreed.

Utilities “understand DER integration is part of the future, and their job is to integrate and maximize the value of customers’ assets,” Fisher added. “But that will increase distribution system complexity by orders of magnitude, while high electricity rates from inflation and natural gas prices keep regulators from approving expenditures for technologies to manage it,” she said.

But a threat may await regulators and utilities that do not take on that distribution system complexity, DER advocates said.

Preparation vs. defection

A "DER integration framework is required” for a “higher performing, lower cost electric system” that meets customer needs, acknowledged SCE Principal Manager of Grid Strategy Devin Rauss.

And impeding DER ignores “customer desires” and “cost-effectiveness trends” and creates incentives for “financially capable customers to defect from the grid,” added electric policy and market design consultant Lorenzo Kristov, who previously worked at the California Energy Commission and California Independent System Operator, in recent Xcel Minnesota rate case testimony.

If customers use DER to supply their own electricity, rates will go up and DER costs will fall, making grid defection more affordable and accelerating it, Kristov wrote. But DER can provide the system with flexibility, voltage control, congestion management, frequency control, energy, capacity, and net load flattening, he added.

“Widespread grid defection would be detrimental to society” because it reduces the system benefits of customer-owned DER, he wrote. It would also “worsen energy injustice” because DER is largely accessible “to customers with financial resources,” leaving less affluent customers to pay for system costs, Kristov added.

DER integration can, though, also lead to a “partnership” between the bulk and distribution systems, leading to “estimated savings on the order of $500 billion” through 2050, Kristov testified in the Minnesota case, citing 2021 Vibrant Clean Energy modeling.

Demand for Generac’s off-grid solutions has grown with recent rising electricity rates, Generac’s Keeling said. And it is causing the cost shift Kristov described, “because installations are done by the more affluent” and because “inefficient operation of batteries” is offsetting those customers’ usage instead of flattening system peaks, he added.

The higher rates may also “slow electrification,” or cause “some customers to switch to lower cost fossil fuel generators,” which would impede societal goals to reduce greenhouse gas emissions, Keeling said. 

ESIG’s national initiative is to provide “a framework built on existing best practices” that allows each jurisdiction “to develop DER integration that is good for their system, customers, and utilities,” he added.

In many jurisdictions, regulators and utilities are doing only the minimum to leverage and optimize existing assets, said Plugged In Strategies’ Villarreal. But now is the time “to develop policies, goals, objectives and a vision for what they want their distribution utilities to become,” he said.

Many may not realize the importance of distribution system planning initiatives, Villarreal added. “But distribution assets are aging even as demands on the system’s capability to leverage DER are evolving,” he said.

ESIG’s proposal recognizes “consumers will buy EVs and rooftop solar if it is cost-effective for them, whether it benefits the system or not,” Villarreal said. “Utilities can try to slow that or create market opportunities for consumers to partner with them in ways that postpone or reduce technology investments because market signals provide the system visibility they need,” Villarreal said.

It happens fast

The main question regulators face is “whether to approve technology investments in expectation of DER growth or to approve them only as DER penetrations rise,” ESIG’s Kahrl said.

Most utilities are planning “the foundational grid modernization investments in ADMS, DERMS, and advanced meters and communication platforms to enable greater DER penetrations,” Xcel Colorado’s Kenney said. “But technology continues to evolve, and there could potentially be technologies that emerge that will also be important,” he recognized.

“Utilities do need the best distribution system technologies, but they cannot design the future, they can only enable it,” which is why ESIG proposed “an evolutionary process,” said Generac’s Keeling, who worked on distribution system development at Portland General Electric. “Trying to solve all problems at once often leads to a longer process that is out of date before it is completed,” he added.

But “utilities without a long-term vision for DER integration don’t realize their peril,” Kahrl added. “Some utilities have learned over the past decade that when DER penetrations rise, it happens really fast.”

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