Distributed Energy Resource Growth

Aggregators of distributed energy resources, known as DERs, will need to find “alternative methods” to deploy their products as long as barriers remain to the full implementation of FERC Order 2222, according to a new paper from Guidehouse Insights.

The Federal Energy Regulatory Commission issued the landmark decision in 2020, directing grid operators to enable DER aggregations to participate in wholesale markets. At the time, Order 2222 “was hailed as a game changer for DER,” according to Guidehouse. But in the three years since, “its full impact seems to be more mixed,” the white paper said.

Implementation timelines vary between regions, and experts say there are technology challenges that must be addressed for utilities to have resource visibility and access to market signals of what services are required.

Alternative approaches to integrating aggregated DERs into wholesale markets could include distribution-level programs or local flexibility markets, Guidehouse said. The firm noted a half dozen implementation challenges for FERC Order 2222, varying between regions, including minimum sizes for individual DERs to be able to participate in a DER aggregation that may keep some asset types on the sidelines, and single-node aggregation rules that require all DERs in an aggregation to be located within the same pricing node.

And some states simply do not allow third-party aggregations of demand response to participate in the wholesale electricity market, which can limit DER participation despite Order 2222. FERC in 2008 passed Order 719, which aimed to increase market participation of demand response, or DR, and which allowed states to determine whether retail aggregations of DR could participate in regional markets.

Thirteen states, mostly within the Midcontinent Independent System Operator territory, “restrict or fully prohibit”  participation, Guidehouse said.

“Third-party DR aggregations are essential to unlocking the full potential of aggregated DER,” the white paper said. But it is possible that a third-party, non-utility DER aggregation “created under the new FERC Order 2222 frameworks that includes DR could be prevented from participating in a wholesale market, even if it contains other resources for which states are not allowed to opt out.”

FERC is considering the possibility of removing the opt-out provision but that could come with unintended consequences, said Mike DeSocio, founder and CEO of Luminary Energy, a consulting firm focused on wholesale markets.

“Ultimately, removing any opt-out removes the states' control over DER jurisdiction for regulating the programs that impact their residents and could result in cost shifts to customers who are less well-off and unable to benefit from DER due to their housing/economic situation,” DeSocio said in an email.

DeSocio said there are costs that are incurred by utilities to support customer participation in wholesale markets including reliability analysis, metering configuration and support and coordination of customers' or aggregators' activities.

“The current electric wholesale and retail regulatory structure must operate in the best interest of the customers and FERC and state commissions must continue to demonstrate cooperative federalism for that to happen. Eliminating the 'opt-out' may just undermine that,” DeSocio said.

While challenges to DER integration are being worked out, Guidehouse’s paper said aggregators may be best served by looking to “alternative” ways the resources can participate in the energy system.

“Local flexibility markets” operating at specific points on the distribution grid could help to manage grid operations. Under such a system, an aggregator enrolls asset owners and submits bids to the marketplace to provide certain localized services, Guidehouse said.

“Local flexibility markets can facilitate competition among DER aggregators while maintaining grid reliability and lowering costs for operators and customers,” Guidehouse said. “The concept has been deployed by numerous distribution companies in Canada and Europe and is gaining traction with utilities in the US.”

In New York, National Grid is working with London-based Piclo on an “independent marketplace” that streamlines the ability of DERs to provide flexibility services, also known as non-wires alternatives.

Piclo and National Grid launched the system in 2022 and expanded their partnership in December. National Grid is seeking more than 100 MW of system-wide load relief solutions as well as 9.4 MW of “rapid load relief solutions” at specific local locations, according to the announcement last month.

California’s rooftop solar industry saw sweeping job losses last year, following a controversial regulatory decision reducing the compensation customers receive for energy that they export back to the grid from their solar panels.

State solar and storage companies have, or planned to, cut 17,000 jobs by the end of 2023, thanks to the state’s new net energy metering framework — dubbed NEM 3.0 — a survey in late November by the California Solar and Storage Association found. This represents 22% of all solar jobs in the state, and more than half of the contractors surveyed anticipate further layoffs down the line. 

The impacts of the California Public Utilities Commission decision have been “devastating, far-reaching, and they will be long-lasting at this point. We haven’t hit bottom, I’m afraid,” Bernadette Del Chiaro, CALSSA’s executive director, said.

The distributed solar industry in California and across the country is also facing broader economic challenges, experts say: high interest rates, inflation and concerns about a potential recession. At the same time, there are some positive factors for the industry — in particular, the fact that retail electricity rates continue to be high in parts of the country, incentivizing customers to install rooftop solar.

“There’s still so much potential with residential solar — I think some of the talk recently has been like this is the end of residential solar, and that is not the case at all,” said Zoë Gaston, principal analyst with Wood Mackenzie. 

Wood Mackenzie expects 15% growth in installed capacity for the national residential solar market in 2025, as the industry recovers slightly from California’s transition to a new framework, and interest rates potentially decline.

“In the longer term, we expect 8% average annual growth between 2026 and 2028 [nationally], and I think the [Inflation Reduction Act] will continue to fuel growth, especially in emerging markets,” Gaston said. 

An ‘unfolding downturn’ in California 

California’s NEM 3.0 net billing tariff was approved by state regulators at the end of 2022, and came into effect for distributed solar interconnection applications submitted on or after April 15. Regulators intended the new framework to encourage customers to pair battery storage with their solar systems, allowing them to store energy and export it back to the grid during times when it is valued more highly. 

The solar industry, however, says it caused an uncertain future for business. Some 70% of residential solar and storage contractors expressed concern about their business outlook in CALSSA’s survey, and nearly 43% — around 300 companies — said it would be difficult to stay in business over the winter. In total, the survey found rooftop solar sales were down between 66% and 83% compared to the same time in 2022. 

At the end of December, a panel of judges at California’s First Appellate District Court dismissed a challenge to NEM 3.0 filed by the Environmental Working Group, Center for Biological Diversity and Protect Our Communities Foundation.

The market will likely continue to see layoffs and other negative effects, according to Del Chiaro. In general, the distributed solar residential market is the quickest to respond to any kind of change while the commercial market for distributed solar — around 30% of the total market — will be slower, she said. 

“So we’re going to see the impacts on the commercial market more in Q2 of 2024 … this is an unfolding downturn and crisis in the California solar industry as opposed to a flash in the pan,” she said. 

Job losses in the industry will continue over the next few months, Carlos Beccar, marketing director of the Fresno-based solar company Energy Concepts Enterprises, said during a recent webinar. Many companies retained a good number of employees over the last three to five months because of the onslaught of requests for rooftop solar systems they got prior to the decision deadline, he said.

But now, “we’re coming to the end of that backlog of installations. So the job loss… is going to get worse now,” he said. 

Wood Mackenzie anticipates a 41% contraction in megawatts of distributed solar installed in California in 2024 — 1,375 MW of installed capacity, down from 2,315 MW expected by the end 2023, Gaston said.

NEM 3.0’s import rates were designed to incentivize electrification, as well as solar systems paired with storage, according to regulators. Gaston agreed — under NEM 3.0, the payback period for a solar system is eight to 10 years on average, depending on the utility, but drops to seven to eight years with a storage system attached, according to Wood Mackenzie’s analysis. That doesn’t reflect significantly in attachment rate numbers so far, “but right now, we’re still seeing installations from sales made under NEM 2.0 — so I think definitely starting in 2024, we’ll start to see that [attachment rate] jump up a bit more,” she said.

At the same time, high electricity retail rates that customers pay could offset some of the economic headwinds the state’s rooftop solar industry is experiencing, said Marlene Motyka, Deloitte's U.S. renewable energy leader. Customers might also start looking at different ways to access distributed solar power. One example is third-party owned residential solar systems, where the homeowner contracts with a different party — like a solar developer or installer — who actually owns the solar systems, and then the homeowner pays a fixed rate for energy pulled from the system, like “your own little personal power purchase agreement with them,” Motyka said. 

Nationally, a 12% contraction in 2024

On the national level as well, the distributed solar industry is facing challenging economic headwinds, like high interest rates. 

“Most recently when we updated our forecasts [in November], we did bring our expectations down for other states for 2024. In past quarters, we did expect states other than California to thrive in 2024 [and] start to see more of the benefits from the IRA,” she said. “But because of these challenges with high interest rates, we’re expecting them to outweigh some of the benefits of the IRA in the near term.”

For the first three quarters of 2023, the distributed solar industry recorded annual installation growth of 24% at the national level. While a lot of this was driven by the rush to get applications in under California’s NEM 2.0 framework, states in the Northeast and Illinois have experienced large electricity retail rate increases, which is driving growth in the distributed solar industry as well, she said. 

However, there is a lag between sales and installations, and some states — like Texas, Florida and Arizona — saw declines in installed capacity in the third quarter, she added.

“We are expecting a 12% national contraction in 2024. Of course, California is the main driver of that contraction, but if you look at all states besides California, we’re expecting 4% growth,” — much lower than the 12% growth that all states other than California experienced in 2023, and the 39% in 2022, she noted. 

In the longer term, however, experts say there is still a lot of potential for the distributed solar market, driven in part — like California — by high electricity retail rates across the country. 

“When we talk about rooftop residential solar, there have been some really big increases in some… less mature markets from a residential perspective, because they have higher retail rates,” Deloitte's Motyka said. 

States like Rhode Island, New Hampshire, Connecticut and Illinois saw estimated increases in solar deployment capacity year over year in 2023 that ranged between 35% and 40%, she said.

“[S]o I think we’ll continue to see more broadly this growth in distributed residential solar,” she said.

Sponsored content

By Peak Load Management Alliance

Where do today's load management activities - including demand response, energy efficiency, and renewable energy programs - fit in a distributed energy resource (DER) future of non-wires alternatives, storage and more? A recent publication titled “The Future of Distributed Energy Resources: A PLMA Practitioner Perspectives^TM Compendium” details eight industry initiatives where leading utilities are partnering with their customers and allies to demonstrate the path to a more integrated approach to DERs.

Peak Load Management Alliance (PLMA) members, utility companies, consultants, and vendors have deep experience in delivering practical solutions to the operational requirement to balance resources and loads. And while the first 100 years of the energy industry was focused on matching resources (generation) to loads, the next several decades will be focused on flexible loads efficiently meeting generation output at both the Transmission system and Distribution feeder level, incorporating renewable, distributed and intermittent resources. We are moving into the realm of dynamic management of the system every day. The last decade has seen a rapid increase in behind-the-meter solar installations; recent advances in battery and thermal storage, electric vehicle (EV) charging, and load flexibility resources are also indicators of the growing importance of distributed energy resources (DERs).

The PLMA community has a history of sharing experiences that enable others in the industry to understand, learn, and embrace industry change. In keeping with this mission, PLMA asked its membership to share case studies about current DER activities and projects. The initiatives detailed in the Compendium are:

• Planning/Foundational Category – Defined as those utilities taking bold steps to leapfrog pilots/technology straight to integrative planning and procuring, and change management.
  • Hawaiian Electric's Integrated Grid Planning, Hawaiian Electric Company
  • Distributed Resource & Flexible Load Study, Portland General Electric and Navigant
  • Integrating DER Planning, Research and Program Development, Tacoma Power
• “DR Plus” Category – Defined as customer-sited assets (with or without the involvement of an aggregator) to monetize DER operations for utility/grid benefits to a growing spectrum of network problems.
  • Deriving New Wholesale Market Revenue Opportunities and Maximizing Customer Utility Savings with Behind-the-Meter Distributed Energy Resources, Center for Sustainable Energy, Tesla, Conectric Networks, and Olivine
  • Expanding National Grid’s ConnectedSolutions Program to Include Energy Storage, Sunrun, EnergyHub, and National Grid
• Microgrids Category – Defined as customer-sited assets that have great degrees of flexibility and opportunity for monetization.
  • Microgrid Enables Military Facility to Participate in Utility Services, Eaton
  • Energy Storage and Microgrid Performance in Non-Wires Solutions and Other Demand Management Programs, Enel X
• International Category
  • First Movers in DER in Colombia, U.S. Energy Association

If management is asking "where do today's load management activities (including DR, EE, and renewable energy programs) fit in a distributed energy resource (DER) future?" the eight case studies in the Compendium offer a glimpse into the future that is unfolding today. If imitation is the sincerest form of flattery, then now is the time to embrace progress through plagiarism. Here, PLMA members provide the blueprints for utilities, regulators and service providers to follow. Read the Compendium at www.peakload.org/plma-publishes-future-of-der-compendium.

Regional transmission organizations and independent system operators are making progress to integrate distributed energy resources, or DERs, into wholesale markets but face a host of “open questions” regarding technology, process and timing, panelists said Oct. 11 at the American Council on Renewable Energy’s Grid Forum.

In a landmark 2020 decision, Order 2222, FERC directed RTOs and ISOs to remove barriers to DER aggregations participating in wholesale power markets. The aggregated resources can include rooftop solar, energy storage, electric vehicle chargers and other technologies.

Since then, grid operators have been developing implementation plans but they are on different timelines. New York ISO, for instance, is hoping to be fully compliant by 2026 while other regional operators are on track for 2029, said Mike DeSocio, founder and CEO of Luminary Energy, a new consulting firm focused on wholesale markets.

“Normally ISOs and RTOs have somewhere between 500 and maybe 1,000 employees. They're not designed to deal with every customer and consumer on the grid,” said DeSocio, who until recently worked with NYISO, overseeing its market design group. “There's challenges with that technology-wise, and there's challenges with it process- and administration-wise.”

But despite the challenges, there is an opportunity to deploy DERs quickly, “especially if the incentives are right,” DeSocio said.

Technology is a major issue challenge to implementing Order 2222, said Karen Wayland CEO of GridWise Alliance. The group represents utilities, grid operators and other stakeholders, and is preparing to release a white paper on the investments that will be necessary to ensure DER aggregations can help maintain grid reliability.

“Both the RTOs and the utilities, and likely third-party aggregators, are going to need a suite of technologies that allow them the visibility, the controls and the market signals to really connect customers to the wholesale market,” Wayland said.

GridWise Alliance’s white paper, which is expected to be released in the coming weeks, will help utilities make the case to regulators for digital technologies such as voltage optimization, submetering solutions, smart inverters, advanced communications and field area networks that are necessary to aggregate DERs, she said.

“You cannot do this without an advanced meter,” Wayland said. But “we know that when utilities come before commissions or their boards to look for approvals for investments, they have to make the case for these investments. And we are seeing a lot of our member utilities have trouble getting advanced metering infrastructure approved through the rate case.”

Even with the technology in place, DER aggregation still presents risks associated with rate and program design and revenue opportunities, said Kelli Joseph, vice president of electricity markets and policy credit risk at Fifth Third Bank.

“In order to enable some of these assets to provide load shifting or to actually provide some of the benefits that everybody talks about, it requires entirely new rate design,” Joseph said. However, “we are financing [projects] under existing rate designs today.”

Joseph’s work with the regional bank entails understanding the credit risks of investments being made in the energy sector.

“I have concerns about the incentives to remain in some of these contracts ... especially for individual consumers who can opt out at any point,” Joseph said. The potential benefits of aggregated DERs are clear, “but from a financial perspective, from an investor who's putting money into these projects, you have to understand that there are a lot of risks.”

Texas regulators want to expand an 80 MW distributed energy resource pilot launched last year, concluding that virtual power plants are helping improve grid reliability and more customer batteries should be harnessed across the Electric Reliability Council of Texas market.

The aggregated distributed energy resource pilot, or ADER, was approved by the Public Utility Commission of Texas in November 2023 and has been “a significant success for Texas,” Commissioner Will McAdams said at the commission’s open meeting on Dec. 14.

Other proposed changes to the ADER program include updates to its telemetry validation methodology and clarifications to procedures for checking whether resources are already enrolled in other ERCOT programs. McAdams also said he would like to see greater participation in the program from electric cooperatives and municipally-owned utilities.

McAdams, who helped spearhead the ADER pilot, announced his retirement from the commission at the Dec. 14 meeting. He was the first commissioner appointed to the reconstituted PUCT after its members resigned in 2021 following Winter Storm Uri.

The February storm resulted in widespread blackouts and almost 250 deaths, and ultimately spawned efforts to redesign Texas’ energy markets and strengthen the electric grid, including the integration of distributed energy resources.

McAdams said he is leaving the agency after assessing his “work-life balance” but also feels this is “a time for new blood to come in and continue the momentum that we have and started here.” That will include the ADER pilot and development of more virtual power plants in Texas, which will be overseen by Commissioner Jimmy Glotfelty.

“We have not yet achieved the potential of what these things can do,” Glotfelty said. Expanding the program is “critical if we want to grow these into major reliability tools. ...the retail providers and the others that are creating [virtual power plants] need critical mass ... otherwise they're spending marketing dollars on just a few customers.”

The ADER project was launched after Tesla expressed interest in aggregating Powerwall batteries in Texas homes. The expanded program would allow aggregated resources to participate in ERCOT’s contingency
reserve service, or ECRS, according to a joint memo filed by Glotfelty and McAdams. ERCOT launched ECRS in June to support grid reliability and address real-time operational issues.

The ADER program should also consider how to engage more “non-opt-in-entities,” or NOIEs, which are load serving entities that do not participate in the competitive retail market, typically including electric co-operatives or municipally owned utilities.

“Unlocking the business case for NOIEs will be a great benefit to the state,” McAdams said. “It will serve those rural areas and underserved areas.”

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.

In the late 2010s, a trio of companies banded together to create an apartment complex in Herriman, Utah, that could serve as a living space, a virtual power plant, and an example for other organizations that want to incorporate clean power and energy storage into construction projects.

Soleil Lofts was finished two years ago. Installing about 5 MW of rooftop solar panels and 12.6 MWh of battery storage at the 600-unit apartment complex cost $34.3 million. The building is a collaboration among Rocky Mountain Power; sonnen Inc., the U.S. division of the German energy storage and VPP company; and the Wasatch Energy Group in Orem, Utah.

Rocky Mountain Power, which provides electricity to customers in several Western states including Utah, broadly applied what it learned from the project across its service area, said William Comeau, vice president of experience and innovation at the company.

“We’re taking lessons learned from Soleil Lofts and replicating it and letting all customers in Utah and Idaho participate,” he said. “We created it as something that could be scaled, and we've scaled it. We've moved from hundreds to thousands of batteries all over Utah and into Idaho and we’re considering other states.”

Rocky Mountain Power doesn’t see the building as an ending, said Blake Richetta, chairman and CEO of sonnen, Inc., the U.S. subsidiary of sonnen Global Holdings.

“Soleil Lofts was only a blueprint,” he said.

The building has solar panels on nearly every available surface and batteries the size of a refrigerator in every apartment, which reduces energy costs and lowers electric bills for residents, Comeau said.

“On a daily basis we are charging those batteries with solar energy when there is excess solar energy on the grid,” he said. “We’re dispatching them and utilizing that energy during peak periods in the evening” when electricity from the grid is more expensive.

The building is part of Rocky Mountain Power parent company Pacificorp’s plan to add 20,000 MW of wind and solar power by 2032, and 7,400 MW of energy storage by 2029. And those goals are part of the utility’s plan to reduce its carbon emissions 70% below 2005 levels by 2030.

The project remains one of a kind, according to the developers.

“Soleil Lofts is the only community with a battery in every single apartment home,” Richetta said.

It is the largest multifamily VPP community that is dispatched by a utility daily, Oman added.

Here are a few lessons the companies learned from building the apartment complex in the Salt Lake City suburbs:

Lesson 1: Solar companies and utilities can work together

“The solar industry and the utilities haven't always gotten along,” said Jay Oman, senior vice president of Wasatch Energy Group. “Solar is pushing as much net metering as they possibly can, but the utility doesn't want any net metering. As they fight for their self interest, you get different outcomes.”

Soleil Lofts proves they can work together, he said. “And it was a win-win.”

Fighting climate change is too heavy a lift to be shouldered by a single company, Comeau said.

“We have very aggressive goals to decarbonize our grid, and to be able to do that you need programs, you need products, and you need partnerships,” he said.

Lesson 2: Customers and utilities can work together

“We’re going through a huge transformation and customers are a big, big part of that,” Comeau said.

In the case of Soleil Lofts, the utility pays customers upfront and annual incentives to use their batteries when the power grid is strained through a program called WattSmart. The program extends beyond Soleil Lofts and has about 3,000 customers, Utah Business reported last month.

But more than that, Rocky Mountain Power and its partners needed customers who were willing to take a chance on something that had never been tried before.

It turned out Utahans were eager to give the building a try. Oman said the apartments filled up almost immediately once they became available.

“Normally it takes a year or so before you get fully leased out,” he said.

Lesson 3: Virtual power plants work

With solar panels in every available spot and a storage battery in every apartment, Soleil Lofts is one large virtual power plant, and the complex proves the concept can work, Oman said.

“We think the project's been very much a success,” he said.

The complex does everything a virtual power plant is supposed to do, in that it generates power and returns excess energy to the grid.

Lesson 4: Utilities can take the lead on energy storage projects

“You can't necessarily wait,” Comeau said. “Sometimes you have to lead out and be very clear about what is needed.”

A project like Soleil Lofts will take years to come to fruition, he said. And decarbonization goals at utilities like Rocky Mountain Power mean that the sooner they get started, the better.

“It's the type of solution that's required for the transition to a sustainable future,” Comeau said. “If we don't have programs like this, it's a huge missed opportunity.”

Lesson 5: Buildings can rely on solar power and batteries, up to a point

Soleil isn’t quite self-sustaining, but it’s close, with the solar panels and batteries providing between 80% and 85% of the building’s energy needs.

“For an all-electric community, I think that's phenomenal,” Oman said.

Panels were placed in every available space, blanketing the roof and the canopies over spaces in the building’s parking lot, he said.

Lesson 6: Solar power and batteries can be a reliable backup during blackouts

“Most of the time you’re a self-consumer, matching the loads of the apartment with the power in the battery,” Oman said.

Because of this, Soleil Lofts was one of the few buildings in Herriman that retained power during a recent blackout, Richetta said.

The solar power, in concert with storage batteries, provided enough electricity, even as the building received nothing from the grid.

“We can cycle the battery every day,” Oman said. “And they can be a grid resource, and other ancillary services can be provided to the local utility.”

Lesson 7: Soleil Lofts can be replicated

“Batteries are performing grid services throughout the state,” Richetta said. “None of that program would have happened if not for Soleil Lofts.”

“It really is one piece of a much larger puzzle,” he said.

Incorporating the building into the grid required a software program that Rocky Mountain Power uses across its coverage area, Comeau said. Thanks to Soleil, the company knows the program works.

“We have a robust behind-the-meter battery demand response program that is fully integrated with the utility and dispatched from the utility,” Comeau said.

“To replicate Soleil is not as difficult as one might think,” Richetta said. 

Sonnen and the Wasatch Group, for example, partnered on the Heron Pointe Apartment complex in Fresno California, which was announced in 2020 and includes 1.3 MW of rooftop solar along with 1.9 MWh of storage capacity.

The PJM Interconnection’s revised plan for integrating distributed energy resources into its markets contains measures that effectively block virtual power plants, known as VPPs, Tesla said in a filing with the Federal Energy Regulatory Commission.

Tesla offered pathways it said would eliminate the barriers so residential aggregations in VPPs in PJM’s wholesale market “can be achieved at scale and provide transformative reliability value and reduce consumer energy costs.”

Through its Order 2222 issued three years ago, FERC directed regional transmission organizations and independent system operators to ensure DER aggregations can participate in wholesale markets. The aggregations could include resources such as rooftop solar, energy storage and electric vehicle chargers.

Virtual power plants are groups of distributed resources such as rooftop solar and batteries that can act as a single resource.

Tesla has set up virtual power plants that provide services to wholesale markets in South Australia and in a pilot project in Texas. The VPPs combine Tesla customers’ solar and co-located Tesla 5-kW, 2.5-hour Powerwall batteries, which are deployed mainly for residential customers, according to the company.

FERC in March ordered PJM to revise many elements of its initial Order 2222 compliance plan. On Sept. 22, Tesla, clean energy trade groups, utilities and some state utility regulators called for changes to the grid operator’s latest plan filed on Sept. 1.

The development of VPPs is especially important given lengthy interconnection timelines for new generation, aging grid infrastructure, peaking power plant retirements, supply chain roadblocks for high-voltage system replacements and expansions along with load growth because of electrification, Tesla said.

Tesla said it aims to develop VPP models that can provide wholesale services such as regulation, frequency and balancing, capacity, and system strength services.

“These are the services that the U.S. electric grid will need within the next 10 years and will not be readily available to ensure grid reliability unless distributed assets can quickly step in to provide equivalent or better value than retiring peak generation,” Tesla said.

Tesla urged FERC to require PJM to allow residential batteries on net energy metering premises to aggregate and provide ancillary services with device-level submetering. “Device-level metering is the pathway to scaling dispatchable resources that can be easily separated from NEM resources located on the same premise,” the company said.

Also, FERC should reject PJM’s proposal to require separate utility meter accounts for net energy metering co-located batteries or other submetered devices to participate in grid services, Tesla said.

Finally, PJM’s plan for nodal pricing settlements, instead of zonal pricing, is premature, according to Tesla. “Erecting unnecessary roadblocks up front, such as a nodal settlement requirement will hinder, if not completely handicap, the development of DER aggregations of residential and small commercial customers,” Tesla said.

Two clean energy trade groups — Advanced Energy United and the Solar Energy Industries Association — also raised concerns about PJM’s nodal settlement framework.

“PJM has failed to ensure that its nodal energy market participation framework is the only ‘technically feasible’ option for DER aggregation participation at scale,” the groups told FERC.

PJM’s proposal to allow limited multi-nodal aggregation is an improvement over its initial plan, but it contains limitations that will constrain its usefulness, the groups said.

Utilities generally supported PJM’s proposal, but warned there may not be enough time to put it in place under the grid operator’s current schedule for implementing it by Feb. 2, 2026.

PJM expects it will take 24 months to incorporate software changes into its platform and test them to make sure they don’t harm other programs, including its day-ahead and real-time energy market clearing engines, according to the utilities, which included Exelon, FirstEnergy AES Ohio and PPL Electric.

PJM expects that by May 1 it will either ask FERC to approve specific capacity market provisions related to DER aggregations or provide an updated status report on its implementation efforts and a projected effective date, the utilities said.

Other parties raising concerns with PJM’s latest compliance plan include the Pennsylvania Public Utilities Commission, the Public Utilities Commission of Ohio and the Advanced Energy Management Alliance.

EVs could drive a 38% rise in U.S. electricity consumption by 2050, according to National Renewable Energy Laboratory estimates. The demand will provide utilities with new revenues, but it will also require distribution system upgrades and load management strategies to ensure charging vehicles help maintain grid reliability rather than overload local electricity systems, experts say. 

To understand where to make grid upgrades, when to purchase more renewable energy and how to ensure customer satisfaction doesn’t suffer, utilities increasingly are working with a variety of participants in the automotive sector, including vehicle manufacturers, car dealerships and ride-hailing services.

“Because we don't make the cars, and we don't sell the cars, we know partnerships are absolutely critical,” said Nadia El Mallakh, Xcel Energy’s vice president of clean transportation and strategic partnerships.

“These are two groups of people that never had to interact before the dawn of EVs,” said Joel Levin, executive director of Plug In America. Automakers and utilities “are now partners until the end of time, whether they like it or not,” he said. Decisions made by automakers “have a huge impact on utilities, and vice versa.”

“We've seen an uptick in joint ventures across the board,” said Leilani Gonzalez, policy director for the Zero Emission Transportation Association. “Utilities are in a space where they're looking to decarbonize, and this is the pathway forward. They’re making sure we have a modern grid to handle the load fluctuations.”

To better understand how utilities are working with the automotive sector, Utility Dive has developed a tracker of partnerships and spoke with several utilities about their particular work. The partnerships span a range of subjects that include managed charging, vehicle-to-grid integration, matching demand to renewables supply and ensuring customers have a smooth transition to electric transportation.

PG&E, BMW expand partnership to explore V2X

EVs constitute about 7% of new vehicle sales today, but growing consumer interest and state and federal standards are expected to drive rapid adoption. President Joe Biden wants EVs to make up 50% of new vehicle sales by 2030. That means utilities will face a steep ramp in electricity demand for transportation, with higher peak loads potentially causing reliability issues.

“From a utility perspective, you want charging to be kind of smooth, not with big peaks,” Levin said. But automakers are building more powerful EVs with larger batteries and faster potential charging. A Level 2 home charger can draw up to 19 kW, meaning a few electric vehicles on the same block can turn into “a big surge in demand” if not effectively managed, he said.

Pacific Gas & Electric began partnering with BMW in 2015 on a smart-charging pilot with “some really basic functionality,” said Adam Langton, energy services manager at BMW of North America Group.

“We started with demand response events where we're just curtailing [vehicle charging], and then we started doing more complex things where we're actually looking at the impact on local distribution by simulating scenarios where we were testing how vehicles respond to a signal in a specific a neighborhood,” Langton said.

In May, the two companies announced they would expand their partnership to also study an EV’s potential to send power back to the electric grid or to power a home or other building. Interest in vehicle-to-everything technologies, known as V2X, is growing as utilities see EVs as something akin to mobile distributed energy resources.

“We need these kinds of partnerships for this to work,” said Amy Costadone, principal product manager for PG&E. The utility is also working with Ford and General Motors on bidirectional charging.

The research partnerships are “critical” for EVs to be used as grid assets, Costadone said. “We need everyone to win if we want this to be scalable, and not just for one EV” manufacturer, she said.

BMW and PG&E plan to test vehicle-to-grid applications in a field trial at a BMW facility in Mountain View, California, and other V2X applications at PG&E’s Applied Technology Services Lab in San Ramon.

“We usually keep our expenses separate and work on different activities,” Langton said.

“We need to understand how the customers really want to use this,” Costadone said. “I feel good about the partnerships that we have and that the technology will get there. The engineering is possible to make this a reality.”

Consolidated Edison tests new technology with GM Energy, others

In New York City, Consolidated Edison has several partnerships allowing it to test and implement new equipment connecting EVs to the grid. In October, the utility announced it would work with GM Energy, a new energy management unit of General Motors, to test how EV chargers can track energy use and charging behavior without the need for a separate meter.

“It’s more of an arrangement of convenience,” said Joe Morreale, ConEd’s section manager for EV demonstration projects and managed charging. “Both parties have things they want to learn and test and experiment with that they can't do on their own.”

ConEd wants to learn more about GM hardware to “get a sense of what it's capable of, how it might function as a distributed energy resource,” he said. And the partnership provides GM with access to testing data and real-world grid conditions.

“It's really an opportunity for both parties to learn from the other's expertise and develop products that are tailored for the benefit of their end customers,” Morreale said.

ConEd has also partnered with the FLO charging network and the city of New York to install curbside chargers and study how they’re used and how public charging can advance EV adoption in the nation’s most populous city. Whether public or private entities are involved in EV-related partnerships, the “grand scope is much the same,” Morreale said. “Both the utility and third party recognize that there are benefits to working together, sharing information, more than if each party goes about it separately.”

In the case of curbside charging, FLO has expertise with EV charging equipment while the city holds the franchise over the streets.

“And so the result is that we get to install hardware on a city street, which is not somewhere where we normally get to install,” Morreale said. 

“It’s really a perfect union,” he said. The private business is supplying the technology while the city supplies “the laboratory” and the utility brings data, program administration and execution. “That's just not something you can do unilaterally, and we're really happy with the results so far,” he said.

Dominion maintains close ties with electric bus dealership

Dominion Energy has multiple partnerships in the EV space, but the “largest and most fully implemented” is its electric school bus program and its work with dealership Sonny Merryman, said Kate Staples, the utility’s director of electrification.

Dominion launched its program in 2019 with a competitive request for proposals, and it selected Sonny Merryman, a Virginia dealer of fleet transportation, to deliver 50 electric school buses beginning in 2020. Sonny Merryman also sells the necessary chargers to the school districts and assists in supporting the installation of those chargers, said Whitney Kopanko, EV program manager and marketing director at Sonny Merryman.

The program has two phases. In the first, Dominion installs, owns and maintains the charging infrastructure for the the school districts and also owns the battery on the school buses, Staples said.

Because electric buses are still more expensive than diesel, “we needed to provide a financial means of helping the school districts get over that hump,” Staples said. “So the school district pays for the traditional part of the bus and we pay for the increment, and so we own the battery.”

“At the end of our agreement with those school districts, we own the battery, we can take it out of the bus and we can use it as stationary storage,” she added.

The last of the 50 buses covered by Dominon’s initial RFP was sent out in 2021, but Sonny Merryman “continues to work very closely [with Dominion] on charger installation,” Kopanko said.

“We work together on actually designing [the site] and installing the chargers [with] our sales individuals, our service individuals, working with Dominion,” Kopanko said. There are site visits to discuss customer locations and needs and how the dealership and utility can support those aspirations.

“A lot of our fleet customers, historically, have been really intensive energy users. They are really complex electricity users,” Staples said. As school districts switch to electric buses, “we want to make sure that we're strengthening our relationship with them and making sure that we deliver what they need from an electricity perspective,” she said.

“That's where the partnership with the dealership comes in and is really critical. Because the dealerships understand the needs of those customers,” said Staples. Sonny Merryman “has been instrumental in connecting the utility with the customer and making sure the customer has the education that they need.”

As an increasing supply of renewable energy resources requires greater reliability and resiliency for the power grid, virtual power plants are emerging as one way to ensure the supply of electricity always meets the demand.

“In the future, grids are going to need to be much more flexible,” said Severin Borenstein, faculty director of the Energy Institute at the Haas School of Business at the University of California, Berkeley, and a board member for the California Independent System Operator. “They’re going to use a lot of intermittent renewable energy, and they’re looking for ways to allow the system to easily and smoothly adapt to those fluctuations.”

VPPs are one way to address intermittency, an issue with wind and solar energy, by storing excess energy that’s sent back to the grid when solar panels and wind turbines aren’t generating electricity.  

“If prices start to spike [or energy supplies are constrained] we can look and say ‘hey, we have a resource within this region’ and we can press a button and call on that resource,” said Reg Rudolph, chief energy innovations officer for the Tri-State Generation Association.

However, even as VPPs proliferate, pinning down the meaning behind the term “virtual power plant” is difficult. Not everyone agrees precisely on a definition of “virtual power plant,” experts and industry insiders say.

“There is a lot of ambiguity in the market as to how they are defined by different vendors,” said Alex Pratt, vice president of business development for the California-based software company AutoGrid.

Pratt provided one such definition.

“A virtual power plant is an aggregation of distributed energy resources that is utilizing software to manage and orchestrate the resources to provide, as much as possible, the same grid services that a centralized power plant would,” he said.

A VPP can be as simple as a group of households with smart thermostats that a utility can adjust when demand strains the power grid. But VPPs generally involve several storage batteries connected to solar arrays or wind turbines that can work together to send energy back to the power grid.

“The idea of a virtual power plant is that in the heat of the summer, when you’re running your generation at full bore, you can hit a button and send a signal to larger loads and create 200, 300, 500 MW of virtual capacity,” said Rudy Garza, president and CEO of CPS Energy in San Antonio, Texas.

The concept has been discussed for decades, but utilities are looking more to VPPs as the use of battery storage increases.

“Once [a household or business] has a battery in place, the grid operator is saying ‘wait a second, we could benefit if we could use that battery on the worst day of the year,’” Borenstein said. “We could know that we could dispatch that battery right when we need it.’”

Several utilities are finding ways to encourage VPPs. The Sacramento Municipal Utility District, for example, provides a subsidy for anyone with battery storage who wants to join a virtual power plant, Borenstein said.

Virtual power plants are similar to microgrids because both can generate their own power. But microgrids are designed to run separately from the power grid, while virtual power plants are part of the grid.

Microgrids are intended to keep critical facilities such as hospitals online during blackouts.

The precise number of VPPs remains a matter of debate, but advancing technology and evolving regulations means the nation will almost certainly see more of them in the coming years, experts say.

How many are there?

The number of virtual power plants in the United States depends on how the term is defined, and with no precise meaning, regulators have yet to conduct their own count.

“Many companies include or remove criteria to enable them to be part of the picture,” said Ben Hertz-Shargel, global head of grid edge for energy research and consulting firm Wood MacKenzie.

But at least one independent assessment exists.

Wood MacKenzie calls a virtual power plant an aggregation of resources. Some or all are behind-the-meter and function together to provide some type of grid service.

“They need to be dispatchable,” Hertz-Shargel said. “They don't need to be able to hit a certain price point, they can be weather-dependent and can incorporate multiple technologies.” 

By that definition, the United States has more than 500 virtual power plants, with an outsized number, about 150, in California.

“There’s a lot of stuff that’s unique to California that would necessitate this,” said Ahmed Mousa, the utility of the future manager for Public Service Electric & Gas Co. in New Jersey.

For example, the unusually high price of energy in California requires novel ways to generate and deliver inexpensive power, and frequent wildfires mean that utilities need power sources to draw from when fires cause blackouts, he said.

What does it take to make more of them?

By all accounts, VPPs will proliferate as efforts to add renewable energy to the grid take on a greater sense of urgency.

But the logistics of virtual power plants are the most daunting barrier. VPPs require power generation and storage in multiple locations and software programs capable of connecting them to the power grid.

“There's a project development phase, akin to putting steel in the ground, that’s the biggest barrier,” Pratt said. “You need assets, and you need things that can be controlled.”

What are the benefits?

When asked about the benefits of a virtual power plant, experts and industry insiders have a common refrain: A lower carbon footprint.

A power grid relying on renewable energy needs a reliable source of power when the weather doesn’t cooperate, and virtual power plants are one way to achieve that reliability.

Virtual power plants or microgrids have numerous objectives, said Santiago Grijalva, the Georgia Power Distinguished Professor for the School of Electrical and Computer Engineering at the Georgia Institute of Technology. 

“One is resilience. If power goes out, or there’s a disruption in the grid,” a VPP can provide power to a small number of customers.

By storing energy during excess generation, VPPs reduce the risk of power outages. Having more points of generation makes VPPs more reliable, Mousa said.

“You have to have some contingency,” he said. “You can’t rely on three customers, because what if they are not available?”

Another objective, Grijalva said, is sustainability. Packaging solar panels with storage batteries — as many VPPs do — makes solar more valuable, encouraging more utilities to use them and providing more power with fewer emissions of planet-warming gases.

The benefits to customers depend on where they live. Net metering rules that pay rooftop solar users for excess power change from state to state, but households who install solar panels almost always stand to benefit when those panels produce more power than they need.

“Our customers sign contracts through our demand response program,” Garza said. “We pay them what the market price is for power like we would when we go out and buy power in the market.”

How FERC order 2222 will help

Regulations are changing at the state and federal levels to clear the way for more virtual power plants

For example, in 2020, the Federal Energy Regulatory Commission ordered regional transmission organizations and independent system operators to let distributed energy resources participate directly in wholesale markets by 2026.

“And they allowed aggregation,” Mousa said. “All of us can work together to make up the virtual power plant.”

Once fully implemented, the order will be a boon for virtual power plants, which fall under the definition of distributed energy resources, experts say.

“It’s going to be a gamechanger,” Mousa said.     

Visuals Editor Shaun Lucas contributed to this story. 

A pair of laws passed by the North Carolina legislature in 2017 and 2021 set an end date for net metering, which pays rooftop solar users for electricity they don’t need and send back to the grid. Seeking to preserve incentives for solar use, a group of stakeholders that included environmental groups, industry associations and Duke Energy worked out an agreement that was presented to the North Carolina Utilities Commission.

The North Carolina Utilities Commission accepted a section of the deal involving net metering, replacing a credit worth between 9 and 13 cents per kilowatt hour with a variable payment rate that changes based on overall electricity demand on the grid.

The commission rejected a proposed incentive program that would have paid solar users who install a smart thermostat that lets Duke adjust household temperatures by a few degrees in times of peak demand to reduce energy consumption and prevent a grid failure.

Environmentalists, industry groups and energy providers in North Carolina are happy that the state’s utilities commission preserved net metering for rooftop solar users, especially with so many other states going in the opposite direction.

The decision handed down by the commission on March 23 seemed to satisfy most parties involved, even if no one was entirely happy with it.

“It's a pretty contentious issue and it felt good that we got an agreement,” said Duke spokesperson Randy Wheeless. “We thought it was a very constructive ruling. I think we're very pleased with it.”

The utilities commission agreed to replace an existing net metering credit with a variable rate. However, the commission rejected a rebate program that would offset some of the initial costs to install rooftop solar, instead asking the parties involved to develop an incentive program involving battery storage.

“This is part way there, maybe more than half, and on balance we think it's a good thing,” said Nick Jimenez, a senior attorney with the Southern Environmental Law Center.

But some groups involved in the negotiation were disheartened by the split decision.

“It’s very disappointing in my opinion, and not what we as a group came up with,” said Jake Duncan, southeast regulatory director for Vote Solar. Duncan had hoped net metering would work in concert with the smart thermostat incentive program to encourage more households to install solar panels.

The order comes just months after California slashed net metering rates by 75%, in a move that environmentalists and solar industry representatives said would discourage Californians from installing solar panels. 

States like Nevada and Arizona have made similar moves, and some environmentalists along with solar industry representatives consider North Carolina’s decision a better alternative and a model other states can follow.

North Carolina’s agreement also prevents future clashes between utilities and environmentalists, stakeholders said.

More than 36,000 customers took advantage of net metering in North Carolina last year, up from from roughly 900 in 2013, according to figures provided by the North Carolina Sustainable Energy Association.

It’s not clear if rooftop solar users will make more or less money under a variable rate for net metering. The utilities commission tasked Duke Energy with creating a bill calculator to help customers better understand net metering’s benefits.

Duke Energy, for its part, is satisfied with the move because the company can pay customers at a lower rate when it doesn’t need extra power.

Under the old system “the utility might be paying a full retail rate for electricity at a time or day or season when we didn't need it,” Wheeless said.

But environmentalists and industry groups had hoped the commission would give North Carolinians a greater financial incentive to install rooftop solar panels. They proposed tying those incentives with the installation of a smart thermostat that Duke Energy could adjust in times of peak demand. The commission instead asked the stakeholders to develop an incentive tying rooftop solar panels with battery storage.

Negotiators wanted to develop an incentive involving battery storage eventually, and the commission effectively asked them to skip the smart thermostat step, said Lon Huber, senior vice president of pricing and customer solutions for Duke Energy.

The utilities commission provided a framework for a battery incentive and gave the stakeholders 90 days to work out the specifics.

While Huber stressed the commission’s decision is a “good first step,” he said smart thermostats are simpler to install.

“A smart thermostat is an easier sell than installing a battery system,” he said. “There’s a lot more electrical work” involved in installing batteries.

The commission said the battery incentive should be worth 36 cents per watt, but incentives are capped at 20 MW and are only available to customers installing battery storage and solar panels for the first time, Duncan noted, limiting the number of people who can participate.

“I think the pilot is going to be a lot less accessible to the wider potential rooftop solar marketplace,” he said.

Other groups were happy that the utilities commission approved some kind of incentive for North Carolinians considering solar panels.

“There is potential to get the upfront storage incentive right and reach a broad swath of solar adopters,” said Taylor Jones, senior regulatory counsel for the North Carolina Sustainable Energy Association. “It creates an opportunity instead of closing the door on an upfront rebate for solar.”

A representative of the utilities commission declined to comment on the record, instead referring to the commission’s March 23 order