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. 

Utilities are preparing for unprecedented demand growth from electric vehicles but say it is a “misconception” that the power grid will be overloaded and become unstable. New system planning and load management tools must be developed, but EVs are a flexible load that experts say can improve grid resilience.

A policy brief published July 24 by the Zero Emission Transportation Association examines key energy considerations associated with the rise of electric transportation, and provides case studies of how major utilities are approaching the EV transition.

In California, Pacific Gas & Electric has almost 500,000 electric vehicles in its territory and anticipates 3 million by 2030. They are a “critical piece” of PG&E’s strategy going forward, Nick Morelli, a strategic analyst of decarbonization strategies at the utility, said July 24 in a discussion hosted by ZETA.

PG&E expects system demand to increase up to 70% over the next two decades as more EVs are added. To meet that demand efficiently, the utility developed a forecasting tool and integrated it into its distribution planning processes.

“A common misconception that we hear a lot is that the grid is not ready, or that increased loading from electric vehicles will overload the system,” Morelli said. “It's definitely true that electric vehicles will represent unprecedented load growth,” but the flexibility of EV charging “actually provides a great opportunity to improve resilience.”

EVs in the United States consumed 6.1 TWh of electricity in 2021, according to ZETA, a group advocating for full EV adoption by 2030. An additional 15-27 TWh of annual new power generation will be needed between now and 2050 to meet growing demand from electric transportation.

“History has proven increases of this magnitude to be accomplishable,” according to the group’s policy brief. New renewable and zero-emitting generation resources will be needed, along with strategies to manage load and the streamlining of regulatory processes to interconnect resources.

PG&E initially relied on customer applications to understand where additional capacity was needed, but has since developed more proactive tools, said Morelli.

“The reactive approach worked relatively well for utilities in the past as you avoid stranded assets,” Morelli said. “But just due to the speed that loads materialize ... instead of taking that peanut butter approach of just spreading and disaggregating load across our system, we individually analyzed the most common segments of electric vehicle charging and we developed an adaptable forecasting tool.”

Of the 3 million EVs expected on its system, PG&E says 2 million will be integrated with the grid: participating in time-of-use rates, managed charging or vehicle-to-grid bidirectional charging programs.

South of PG&E’s territory, Southern California Edison officials also say EVs represent an opportunity. The utility has more than 430,000 EVs in its service area.

“One of the big misconceptions I hear ... is that EVs will negatively impact grid resilience,” said Chanel Parson, director of SCE’s building and transportation electrification programs. But a typical passenger vehicle is only operating a fraction of the day, leaving up to 23 hours when it could be charging or discharging back to the grid, she said.

“Flexible load can help utilities balance the natural daily peaks on the grid, and make the grid more resilient by exporting load to the grid or removing home and building load,” Parson said. Today, SCE utilizes vehicle-to-grid applications in emergencies but is “setting the groundwork” to make it a common strategy, she said.

The utility also offers infrastructure programs to fund and install utility and customer-side infrastructure, vehicle rebate programs and customer advisory services, she said.

But to continue advancing the transition, utilities say they need greater certainty around the state and federal government’s commitment to EVs in order to advance grid upgrades and build out capacity. And persistent supply chain issues must be addressed.

“We are seeing long lead times and exponentially higher costs for critical equipment that support grid stability and EV infrastructure,” Parson said.

Regulatory frameworks that allow utilities to invest “proactively” are important, said Cliff Baratta, Consolidated Edison’s electric vehicle strategy and markers section manager. The utility serves New York City and is preparing for 230,000 EVs in its territory by 2025. Since 2017 it has been working to encourage grid-beneficial charging through its SmartCharge program, which offers incentives for drivers to avoid charging during peak times.

“Here in New York, we're meeting all electric service requests for EV chargers and the impact on the grid has been limited so far,” Baratta said. “When we look out several years, it's going to become a challenge. We anticipate extremely large loads coming.”

The North American Electric Reliability Corp. on May 15 issued its highest alert level ever, urging generators and transmission owners to take measures to prepare for winter.

In its first Level 3 Essential Actions alert, NERC cited three “extreme winter weather events between 2018 and 2022. Severely cold winter weather knocked power plants offline in 2018 in the South Central U.S., in 2021 in Winter Storm Uri and last year in Winter Storm Elliott, leading to power shortages and outages, NERC said.

“When cold weather events such as Winter Storm Uri occur, system operators may need to shed firm customer load to prevent uncontrolled load shedding and cascading outages which may not only result in major disruption but also have very real human consequences,” the grid watchdog organization said.

The alert asks power plant owners to calculate the “extreme cold weather temperature,” or ECWT, for their generating units and include that number — the lowest 0.2 percentile of the hourly temperatures measured in December, January and February since 2000 — in their winter preparedness plans.

Generators should identify which units need additional freeze protection measures to operate at the ECWT and put them in place before the winter season if possible. Power plant owners also should identify critical components of their facilities and the steps they took to protect them from winter weather, according to the alert.

The alert calls on transmission operators to update their operating plan to include provisions such as minimizing the overlap of circuits that are designated for manual load shed and circuits that serve designated critical loads.

The operating plans should also include provisions for manual load shedding that can occur quickly enough to ease an emergency, according to the alert.

Balancing authorities, which maintain electric supply and demand in their areas, should update their operating plans to manage generating resources in their area to address various issues, including fuel supply and inventory concerns, and fuel switching capabilities, according to the alert.

Organizations won’t be fined for failing to implement the alert’s recommended actions, according to NERC.

The electric system is becoming more reliant on variable energy resources, such as wind and solar, and on natural gas, according to NERC.

“Extreme winter weather events have stressed the supply of traditional fuels and the dependability of new resources,” NERC said. “Preparation of resources for operation during extreme winter weather and situational awareness in both planning and operations by applicable registered entities is necessary for optimal reliability.”

Despite previous warnings, U.S. power plants remain vulnerable to not working during bitter cold, according to an initial assessment of Winter Storm Elliott prepared by the Federal Energy Regulatory Commission and the North American Electric Reliability Corp.

About 70,000 MW was unable to run in frigid weather in late December across the Midwest and Eastern United States, leading to rolling power outages of more than 5,000 MW in the Southeast, according to a presentation at FERC’s monthly meeting June 15.

The majority of power plant outages during the cold snap were caused by problems with freezing, fuel supply, and mechanical and electrical issues, FERC staff said, noting those problems occurred in the last five major extreme cold spells that have happened in the U.S. since 2011.

Like in Winter Storm Elliott, there was a sharp drop in natural gas production and electric use was higher than forecast in some areas during some of those cold events, according to the presentation.

The need to weatherize power plants and other recommendations issued after previous cold weather events remain valid and if they had been fully implemented would have eased the problems during Winter Storm Elliott, FERC staff said.

"We're seeing the same three causes, so therefore we think that it makes all the sense in the world to continue full steam ahead on implementing prior recommendations," Heather Polzin, reliability coordinator for FERC’s enforcement office, said about power plant outages.

Anticipating grid vulnerabilities is becoming harder in the face of extreme weather, according to FERC Commissioner Allison Clements.

“It shows that reserve margins are an increasingly inadequate tool to predict winter sufficiency,” she said. “Two of the regions that suffered rolling outages during Winter Storm Elliott — TVA and Duke [Energy] — were not even identified in NERC’s 2022-23 winter assessment as anything more than a low risk of load shed.”

FERC Commissioner Mark Christie said weatherizing power plants raises market issues.

"It's fine to mandate weatherization, but you can't separate that issue from the issue of market design, and how do you pay for it?" Christie said. "Weatherization requires capital expenditures. Energy markets don't compensate for capital expenditures. That's what the capacity market was set up to do."

NERC oversees grid reliability, but no entity is responsible for making sure the gas system is reliable, FERC acting Chairman Willie Phillips said.

"I believe this is a reliability gap," Phillips said during a media briefing. "I, once again, call for some entity to have responsibility for the gas system's reliability. It doesn't have to be FERC, but someone needs to have responsibility for that."

With support from FERC and NERC, the North American Energy Standards Board is considering options for better harmonizing the electric and natural gas systems.

In the first of three planned meetings, the NAESB Gas-Electric Harmonization Forum meets June 16 to discuss 19 proposed recommendations for better meshing the gas and power sectors. The recommendations call for increased information sharing between power plant operators and pipeline companies. They also call for a study to determine if the natural gas system can meet future power plant needs.

Separately, FERC approved two rules June 15 that aim to improve grid reliability during extreme weather.

One rule directs NERC to require transmission system planning for extreme heat and cold weather over wide geographical areas, including studying what would happen if power plants and transmission equipment go offline at the same time. Grid planners would have to take actions to address any issues found in their studies. 

In the other rule, the agency ordered regional transmission organizations and other transmission providers to submit one-time reports describing their current or planned policies and processes for conducting extreme weather vulnerability assessments and reducing those risks.

The PJM Interconnection aims to offer incentives for “black start” generators that have assured fuel supplies, while allowing wind, solar and energy storage to qualify for that category of power plant, according to a proposal filed May 12 with the Federal Energy Regulatory Commission.

Black start units are used to re-energize the grid during widespread blackouts, but PJM doesn’t require them to have secure fuel supplies, according to the grid operator.

During widespread outages on the bulk electric system, grid operators restore power by running black start units, building “cranking paths” to other key power plants, forming “islands” of restored service, which are synchronized, and connecting to neighbors, PJM said.

Nearly half of PJM’s black start units lack fuel assurance and the distribution of fuel-assured units is spread unevenly, potentially extending outages on the bulk electric system, the grid operator said.

Power plant fuel supply could be disrupted by natural gas pipeline outages, equipment failures at compressor stations or cyber attacks on pipeline systems, PJM said.

“Fuel supply availability could be a very real concern during the type of severe and widespread disruption to the [bulk electric system] that triggers a need for black start generation,” PJM said.

PJM proposed establishing Fuel Assured Black Start Units as a new category of black start resources. They would need to meet minimum commitment periods, performance requirements and testing requirements.

The black start units must be able to run for 16 hours without grid-supplied power.

Eligible gas-fired power plants without on-site storage would have to connect to two interstate pipelines or have a direct connection to a gas-gathering system.

The proposal helps address a need for additional diversity in the types of resources that can qualify as a black start unit by establishing qualification rules for wind, solar, run-of-river hydro and battery storage resources, PJM said.

As an incentive, black start units that recover their costs through base formula rates would receive 10% more revenue.

PJM intends to require one fuel-assured black start unit in each of its 21 transmission zones, supplemented by additional “high impact” units that are needed to quickly restore power, according to the filing.

PJM asked FERC that its proposal take effect by July 11 so it can issue a request for proposals for black start resources this summer. The proposal was widely supported by PJM’s stakeholders, the grid operator said.

The physical security rule in place now for critical substations “appropriately focuses limited industry resources” and should not be expanded to a broader set of assets on the bulk power system, or BPS, the North American Electric Reliability Corp. concluded in a report published April 14. 

However, NERC also found a need to “evaluate additional reliability, resiliency and security measures” following a rise in substation attacks last year. The reliability organization and the Federal Energy Regulatory Commission are planning a technical conference “to further study appropriate levels of physical protections.”

NERC’s physical security reliability standard, known as CIP-014, will likely eventually be modified, according to Mike Hamilton, chief information security officer of Critical Insight, a cybersecurity firm. But that process could be lengthy and “the gist of this announcement is that operators must conduct physical risk assessments of substations. Now,” he said.

The scope of the North American grid is extensive, with tens of thousands of substations in remote areas. NERC’s physical security rules focus on assets that are critical to the reliable operation of the BPS.

The criteria for a substation to fall under the CIP-014 rule is “broad enough” to capture critical facilities, the report said. “NERC did not find evidence that an expansion of the applicability criteria would identify additional substations that would qualify as ‘critical’ substations.”

While NERC stopped short of recommending a broad expansion of its physical security rule, it did acknowledge the growing threat and need for additional study and action.

“Given the increase in physical security attacks on BPS substations, there is a need to evaluate additional reliability, resiliency, and security measures designed to mitigate the risks associated with those physical security attacks,” NERC said.

Nearly 1,700 physical security incidents were reported to the Electricity Information Sharing and Analysis Center in 2022, up 10.5% from 2021. The majority of reported incidents were categorized as gunfire, ballistic damage, intrusion or tampering and vandalism.

Supplementary data “could show that additional substation configurations would warrant assessment” under the rule, NERC said.

NERC said it would work with FERC staff to hold a technical conference to “identify the type of substation configurations that should be studied to determine whether any additional substations should be included in the applicability criteria.” 

FERC called for NERC to consider expanding CIP-014 applicability in December, following a North Carolina firearms attack that knocked power out to about 45,000 Duke Energy customers. Later that month, multiple substations in Washington were damaged, leading to more than 14,000 outages on the Tacoma Power and Puget Sound Energy systems. 

But NERC’s report concluded establishing a “uniform, bright line set of minimum physical security protections” for all BPS substations and associated primary controls centers “is unlikely to be an effective approach to mitigating physical security risks and their potential impacts” because it “fails to provide for a methodical approach necessary to address site-specific threats or objectives.”

“NERC finds that this more holistic approach will provide greater long-term flexibility and minimize the impacts of physical attacks on BPS reliability,” the report concluded. NERC is recommending “further evaluation of the appropriate combination of reliability, resiliency and security measures that would be effective in helping to mitigate the impact of physical security attacks.”

Critical Insight’s Hamilton said he found NERC’s recommendation against expanding CIP-014 “curious,” but that new security rules were likely coming — as they have for other critical sectors. The health, aviation, pipeline and water sectors have all received new requirements within the last six weeks, he said.

CIP-014 “will likely be modified to reflect the increased scrutiny of substation physical security and document potential compensating controls,” he said. But waiting for a rulemaking and comment period “is not sufficiently rapid to counter a known and prevalent threat.”

“NERC is playing ‘catch up’ to address recent physical attacks and not waiting for the bureaucracy,” Hamilton said.

The National Renewable Energy Laboratory will test the ability of real-time meter data to coordinate rapid energy restoration in remote communities in a $3 million partnership with Copper Labs, a Boulder, Colorado-based manufacturer of real-time meter data collection technology.

The partnership will first identify and define community needs. It will eventually see the creation of a plan to automate power restoration during outages and the development of a virtual emergency operations center. The location for the project has not yet been announced but will be in either Colorado or New Mexico, according to Copper Labs.

Real-time meter data will become increasingly important to utilities and customers as the percentage of solar and other renewable resources on the grid grows, Copper Labs CEO Dan Forman said, because it will help align demand with the availability of intermittent resources.

A new cooperative project funded by the Department of Energy is set to find out whether modern interventions could help remote communities get the lights back on more quickly after power outages.

NREL, Copper Labs and other partners will install and use sensors and advanced distribution management systems in a trial project to test whether the equipment can improve community resilience, according to Fei Ding, the project’s principal investigator from NREL. According to Copper Labs’, the company’s data-reading hardware will be installed at some 20 sites at an as-yet unannounced community in the Holy Cross Energy, Connexus or United Power service territories. The hardware will be used to provide greater behind-the-meter visibility, Ding said.

Copper Labs makes data collectors that can read gas, water and electric meters every 30 seconds. This gives electric utilities more immediate insight into who is experiencing a power outage, and what resources might be available to help restore power, Forman said.

“In outlying areas, the faster you can get them online, the better it is for health, safety and comfort,” he said.

As larger percentages of solar and other renewable resources dominate the grid, Forman said, access to real-time data will become more important for avoiding outages and maintaining reliability.

Real-time meter data could also help communities take greater advantage of demand-side management programs, he said. Case studies by the company have found that making real-time data available to customers results in greater customer engagement and has twice the impact on peak load as demand management programs that lacked a real-time data web portal.

Although the NREL project will focus on installing hardware at customers’ homes, Copper Labs also has a version of its device that can be attached to a fixed point such as a utility pole to read the meters from an entire neighborhood. The device can use cellular data, Ethernet or fiber connections. This eliminates the need for wi-fi, which is often a barrier to smart meter devices and programs in remote and rural communities, Forman said.

The Federal Energy Regulatory Commission on Feb. 16 approved two extreme cold weather reliability standards for U.S. generators in response to Winter Storm Uri in 2021, when about 4.5 million Texans lost power because power plants were unable to run.

FERC approved the standards proposed by the North American Electric Reliability Corp. even though they included “undefined terms, broad limitations, exceptions and exemptions and prolonged compliance periods.” FERC ordered NERC to address those issues within a year.

FERC also directed NERC to monitor and assess power plant owners’ implementation of the new requirements. NERC is preparing to propose a second set of cold weather standards late this year to address remaining recommendations from the FERC-NERC inquiry into Winter Storm Uri.

The just-approved reliability standards come less than two months after widespread power plant outages during Winter Storm Elliott, including outages by Duke Energy and the Tennessee Valley Authority in the Southeast.

The Midcontinent Independent System Operator reported it had 50,000 MW in unplanned power plant outages during the late-December cold snap. About 45,950 MW, or 23% of PJM’s generating fleet, was unexpectedly offline on Dec. 24 while ISO New England had about 2,275 MW in unplanned outages that day.

One standard addresses emergency operations. FERC said it will improve how transmission operators account for the overlap of manual load shed and automatic load shed in their emergency operating plans while addressing the need to minimize the use of manual load shed that could make emergencies worse and threaten system reliability.

The other standard covers extreme cold weather preparedness and operations. The standard requires generator owners to put in place freeze protection measures, develop enhanced cold weather preparedness plans, conduct annual training and implement corrective action plans to address freezing issues.

Generators must also provide certain cold weather operating parameters to reliability coordinators, transmission operators and balancing authorities for their analysis and planning, FERC said.

“We believe that these measures begin to address many of the issues identified as contributing to generating unit failures during extreme cold weather conditions,” FERC said.

NERC’s proposed weatherization requirements were “not up to the task,” FERC Commissioner Allison Clements said during the agency’s monthly meeting, noting the harm caused during Winter Storm Uri, with at least 210 deaths in Texas and up to $130 billion in losses there.

The proposal, for example, requires power plant owners to weatherize generators so they can operate for one hour in extreme cold temperatures beginning in April 2027, she noted.

“Yes – one hour – in 2027, over four years from now,” Clements said. “Needless to say, that doesn’t bring comfort that we can get through a multi-day winter event like Winter Storm Uri, and waiting for four additional winters before weatherization requirements kick in does not reflect the urgency we feel.”

FERC said the one-hour requirement was too short and ordered NERC to extend it, but was not specific.

FERC rejected arguments by the Electric Power Supply Association, the PJM Power Providers Group and Invenergy that the agency and NERC lack the authority to set some of the requirements in the standards.

Also, FERC said concerns about how generators would recover their costs in meeting the standards was outside the scope of the proceeding.

A U.S. Department of Energy national laboratory has shown how blockchain technology can be used to secure the grid in what it says is a first-of-its-kind demonstration of a new power system communications framework.

“This framework gives us a totally new capability to rapidly respond to anomalies,” Raymond Borges Hink, who led the research team at the Oak Ridge National Laboratory, said in a statement. Borges Hink is a cyber security research scientist at the lab.

A blockchain is a distributed ledger more commonly associated with crypto currencies, but he said his team has shown it can be used to “more quickly identify an unauthorized system change, find its source and provide more trustworthy failure analysis. The goal is to limit the damage caused by a cyberattack or equipment failure.”

The blockchain-based communications framework was demonstrated at the Grid Research Integration and Deployment Center at Oak Ridge this year. According to an August study of the project it utilized measurement, communication and protection devices that electric utilities commonly employ.

In order to ensure grid components were properly functioning, the communications framework would verify that configuration data on devices had not been illegitimately modified from the last known correct settings by comparing it “with the last known correct baselines.”

“Our system helps determine in near real-time whether a fault was triggered by a cyberattack or induced by natural events,” Borges Hink said. “This is the first implementation of blockchain enabling this kind of data validation between a substation, a control center and metering infrastructure.”

While most of the energy discussion around blockchain technologies focuses on their energy use — a group of federal lawmakers is investigating the electricity consumption of bitcoin — some use cases focus on how distributed ledgers can benefit clean energy development and grid management. Decarbonization-focused non-profit RMI has been studying how distributed ledgers can be used in carbon markets.