Reliability

The North American Electric Reliability Corp. last week released a nearly three-year plan for developing reliability standards for inverter-based resources, or IBRs, such as wind, solar and battery storage facilities.

The work plan responds to an October decision by the Federal Energy Regulatory Commission directing NERC to develop new and revised reliability standards for IBRs to address concerns they have been tripping offline during grid disturbances.

“NERC has long recognized the reliability risks associated with the rapid growth of IBRs on the bulk-power system,” the grid watchdog organization said in its Jan. 17 filing with FERC. “Addressing these risks through agile, risk-based, and objective-based reliability standards is a high priority of NERC.”

In response to FERC’s order, NERC in the first half of this year plans to establish clear definitions for “IBRs” and “distributed energy resource” for its standard-setting process, according to the organization’s work plan.

By Nov. 4, NERC plans to file proposed reliability standards to address performance requirements and post-event performance validation for registered IBRs.

By November 2025, it plans to file proposed reliability standards to address data sharing and model validation for all IBRs, NERC said.

To finish its work on the IBR standards, NERC aims to file a proposal setting standards for planning and operational study requirements for all IBRs by Nov. 4, 2026, according to the work plan.

NERC said it may adjust the scope of ongoing standard-setting initiatives in response to its IBR initiative. Also the work plan may evolve, according to the organization.

The effort comes amid a surge in wind, solar and storage development. Those resources use inverters to convert the direct current electricity they produce to alternating current electricity used on the grid.

Synchronous generators, such as natural gas-fired power plants, typically ride through grid disturbances while IBRs must be programmed to do so.

Since 2016, IBRs have tripped offline at least 12 times, with an average loss of about 1,000 MW, demonstrating the risk that grid planners and operators must account for, FERC Acting Chairman Willie Phillips said in October when the agency issued its IBR order.

Rising peak demand and the planned retirement of 83 GW of fossil fuel and nuclear generation over the next 10 years create blackout risks for most of the United States, the North American Electric Reliability Corp. said Dec. 13 in its annual Long-Term Reliability Assessment.

While most regions should have sufficient electricity supply in normal weather, both the Northeast and western half of the U.S. face an elevated risk of blackouts in extreme conditions. And parts of the Midwest and central South areas could see power supply shortfalls during normal peak operations.

To address the growing risk, NERC said new gas capacity is needed, the nation’s transmission network must be expanded and grid planners must develop processes to better account for variable resources and the interconnected nature of the power and gas sectors.

The power grid is increasingly unreliable, and NERC officials say it is not clear how the trend will be reversed.

“In recent years, we’ve witnessed a decline in reliability, and the future projection does not offer a clear path to securing the reliable electricity supply that is essential for the health, safety, and prosperity of our communities,” John Moura, NERC’s director of reliability assessment and performance analysis, said in a statement.

“We are facing an absolute step change in the risk environment surrounding reliability and energy assurance,” Moura said.

The Midcontinent Independent System Operator faces a projected 4.7 GW shortfall beginning in 2028 “if expected generator retirements occur,” NERC found. The grid operator is adding more than 12 GW to shore up a previously identified reserve deficit but more will be needed.

NERC also noted that there are 50 GW of generation in MISO with signed generation interconnection agreements that are not yet online, “and another 200+ GW of new resources within the interconnection queue that are still being evaluated.”

A spokesperson for MISO said the grid operator “concurs with NERC’s key conclusions and recommendations,” and is taking steps to address potential resource shortfalls. A new seasonal resource adequacy construct, changes to resource accreditation, development of a long-range transmission plan and adoption of a reliability-based demand curve will help, they said.

In the Southeastern Electric Reliability Council-Central region, NERC identified a potential shortfall in planned reserves over the 2025 to 2027 period, “as demand forecasts increase faster than the transitioning resource mix grows.” The region is adding gas and solar generation, and retiring coal plants.

“The period of projected shortfall is occurring in a mid-point of the assessment period from generator retirements that are currently slated to take place before new resources are added,” NERC said.

NERC’s reliability assessment is “deeply troubling,” said Michelle Bloodworth, president and CEO of America’s Power, which represents coal generators.

“Despite several years of warnings about the possibility of electricity shortages in many parts of the country, the risk of electricity shortages has grown worse,” she said, pointing to coal retirements, policies developed by the Environmental Protection Agency, and “dangerous subsidies for unreliable sources of energy” as the cause.

The National Mining Association said coal retirements are “leaving grids across the country short of the fuel-secure, dispatchable generation they so desperately need.”

“Surging power demand, the rapid loss of dispatchable generating capacity, and the towering hurdles to connecting reliable alternatives and their enabling infrastructure are the on-the-ground reality that should shape our energy policy,” NMA President and CEO Rich Nolan said in a statement.

Cooperative utilities echoed the concern over EPA policies. In May, the agency proposed greenhouse gas emissions limits for coal-, gas- and oil-fired power plants, with initial requirements beginning in 2030 for coal-fired generators.

“NERC’s latest assessment paints another grim picture of our nation’s energy future as demand for electricity soars and the supply of always-available generation declines,” said Jim Matheson, CEO of the National Rural Electric Cooperative Association.

“Nine states saw rolling blackouts last December as the demand for electricity exceeded available supply. And proposals like the EPA’s power plant rule will greatly compound the problem,” he said. “Absent a major shift in state and federal energy policy, this is the reality we will face for years to come.” 

NERC’s report noted the threat of “environmental regulations and energy policies that are overly rigid.”

If regulations lack provisions for electric grid reliability, they can “influence generators to seek deactivation despite a projected resource adequacy or operating reliability risk; this can potentially [jeopardize] the orderly transition of the resource mix,” the report said. “For this reason, regulators and policymakers need to consider effects on the electric grid in their rules and policies and design provisions that safeguard grid reliability.”

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By Overstory

Every day, utility operators are being asked to do more with less. Demands from EVs and consumer expectations are soaring along with pressure to decarbonize, modernize and meet new regulatory requirements. Rising costs and labor shortages make those demands an even taller order. 

In this era of increasing grid complexity, vegetation management—one of the biggest operations budget line items and drivers of outages—plays a critical role in utilities’ ability to deliver affordable, reliable energy.

The Rising Cost of Vegetation Vulnerabilities

Traditionally, grid operators have relied on manual inspections and cycle trimming to address vegetation-related risks and keep network reliability high. And traditionally, they worked.

According to one 2022 study, however, “roadside trees cause almost 90% of the power outages in the forested Northeastern US” today. Risk has changed.

Increasingly frequent wildfires, storms, insect infestations and tree failures have caused more power outages around the US over the last two decades than ever before, putting more pressure on utilities to make strategic changes to their vegetation management programs.

In 2020, Con Edison “allocated $13 million for tree trimming and $1.5 million for hazardous tree removal to prevent trees from interfering with overhead power lines” as part of their storm hardening initiative. In the last three years, PG&E and Southern California Edison were expected to have spent almost $20 billion on wildfire prevention.

Operations teams are, understandably, under intense scrutiny to manage budgets wisely.

A Strategic Shift to Data-Driven Vegetation Management

Typically, vegetation on a small percentage of a utility’s network accounts for the majority of its outage minutes. By strategically reducing risk on those high-priority spans, utilities can stretch their budgets in the short term—minimizing asset failure and safety risks—without sacrificing long-term reliability.

In the past, the time and expense of foot and helicopter inspections have made this objective, strategic approach impossible. 

Today, companies like Overstory combine remote sensing and machine learning technologies to give operations teams actionable, data-driven vegetation insights that are accessible on any platform. Configuring these insights based on unique network requirements and parameters (tree health, species of interest, encroachment proximity, wildfire, etc.) enables utilities to scale their operations, cost-effectively reducing risk without losing the local expertise of their trusted arborists and contractors.

Turning Vegetation Insights into Reliability Gains

Rather than completely upending their approach to vegetation management, industry-leading investor-owned utilities, municipalities and cooperatives alike are incorporating this intelligence into their programs one step at a time.

• Cycle Optimization: Many teams have started using vegetation intelligence to better plan which circuits should be prioritized in a given year. By pushing spans that don’t need immediate attention out of this year’s cycle plan, they can redirect allocated dollars to more impactful work elsewhere. This shift enables teams to optimize their budgets by proactively eliminating much more risk per dollar, getting ahead of annual trimming schedules, and demonstrating a clear return on investment.
• Hazard Trees: As droughts and infestations intensify, total tree failures outside the right of way have become increasingly common. And while it’s nearly impossible to find every strike, danger or hazard tree in the field on foot, AI-powered health, height and species analysis can give vegetation teams timely insights into where those outside-ROW outages are most likely to occur. “The results were surprisingly accurate in-field validation. Trees with 20% crown dieback or more were consistently labeled as declining.” said the program manager of one investor-owned utility on the accuracy of the technology.
• Mid-Cycle Trimming: Vegetation intelligence can also pinpoint hotspots that need to be tackled off-cycle to maintain reliability. If a contractor is already performing responsive work on one span, some teams maximize their resources by directing further trimming to nearby high-priority spans to mitigate risk proactively.
• Wildfire Mitigation: Climate models predict a doubling in annual high-fire days in some parts of the Western United States by 2050, so timely information on species, health and distribution of trees in vulnerable areas has become crucial. Teams like Holy Cross Energy and CORE Electric Cooperative use this to make informed decisions on must-trim spans, mitigating the devastating impacts of wildfires while fostering healthy forest ecosystems and safe communities. 

The Future of Grid Reliability

The imperative to meet growing demands, navigate environmental challenges and adhere to growing regulations has propelled a strategic shift to innovative utility operations.

“As we evaluated different vegetation intelligence platforms, Overstory stood out because they partnered with us to work together on a solution. It was a collaborative effort from the start. Throughout the pilot, they brought in functionality that supported our existing workflows, helping us solve these shared challenges together.” - Vegetation Management Supervisor, Top 10 US Investor-Owned Utility

The integration of vegetation intelligence technology like Overstory’s into vegetation management marks a measured transformation, offering a promising path forward for utilities striving to balance cost-effectiveness with long-term reliability. 

To learn more about how vegetation intelligence can help future-proof grid reliability for your network, reach out to the Overstory team at overstory.com/demo.

A critical technology is needed to sustain the U.S. energy transition’s momentum, according to engineers focused on power system reliability and clean energy.

Inverters with “grid-forming” capabilities, or GFM, are needed to support the growing penetration of inverter-based resources, or IBRs, like wind and solar, according to engineers with the North American Electric Reliability Corporation, or NERC, and engineers with the Energy Systems Integration Group, or ESIG, which advocates for integrating and managing higher levels of renewables.

Inverters convert renewables-generated energy into the alternating current flowing through the U.S. transmission system.

“The power system’s heartbeat is a 60 Hertz, or cycles per second, current to which all generation on the grid must synchronize,” said NERC Senior Vice President and Chief Engineer Mark Lauby. “As long as variable renewables’ inverters synchronize their generation with that 60 Hertz heartbeat, they can deliver power into the system without concern about system faults,” 

But faults causing current fluctuations go uncorrected by today’s renewables’ limiting “grid-following” inverter capabilities, making deployment of GFM with new IBRs urgent, engineers agreed. 

The U.S. does not have unified comprehensive standards requiring grid following inverters, which took 20 years to develop in Europe, said Energy Systems Integration Group, or ESIG, Chief Engineer Julia Matevosyan. “And we don't have another 20 years to develop GFM standards to avoid reliability failures,” she added.

Fluctuations in the power system’s heartbeat that threaten reliability have been stabilized by traditional power plants, called synchronous machines, but they are retiring, engineers said.

To drive GFM deployment, pilots are needed to test GFM performance, engineers agree. Standards defining GFM requirements based on the pilot results must then be set by NERC and system operators, and market incentives for protecting reliability should be provided to reward those who deploy GFMs, the engineers said.

What GFMs do

Coal, natural gas, nuclear and hydropower plants are designed to drive spinning turbines that generate electricity at the heartbeat rate of 60 hertz, according to a National Renewable Energy Laboratory November 2020 GFM Roadmap. The “spinning mass” of those synchronized machines has a momentum, called inertia, that automatically corrects frequency fluctuations, it added.

As traditional synchronous machines with rotating mass like natural gas, coal and hydropower plants, are replaced with IBRs like wind and solar projects, system inertia is reduced, “making the risk of frequency swings higher,” NREL explained. IBRs using today’s grid following inverters do not significantly address those changes, but GFM detects them and adjusts power flow to limit them, NREL added.  

Without GFM, system operators can reliably integrate 30% to 75% IBRs by keeping synchronous generation online, ESIG’s Matevosyan told a Sept. 20 webinar. But keeping conventional generation online to protect reliability can lead to expensive renewables curtailments and a slower transition to IBRs, she added.

GFM can replace synchronous machines because it is “human programmed through power electronics, highly controllable and can provide very fast responses” to frequency fluctuations, Mahesh Morjaria, executive vice president, plant operational technology for utility-scale solar project developer Terabase Energy, told an RE+ renewables conference audience in September.

One key to the reliability provided by GFM is “frequency control,” to manage frequency fluctuations, the engineers said. Another is “voltage control,” to keep system voltage stable by increasing or lowering system output, they added.

GFM can also provide other system protections, called “stability services,” that detect “abnormal grid operating conditions,” and mitigate them through “disconnection of faulted parts,” NREL said.

“If the fault leads to a blackout, GFM can do a system ‘black start,’ by using IBR-supplied energy to restart generation and rebuild normal operations piece by piece,” Matevosyan said.

But including black start capabilities introduces design and operational challenges, said GridStor Senior Vice President of Engineering, Procurement, Construction and Technical Operations, Daniel Dedrick. And inverters designed for black start are 2% to 5% more expensive and require energy to drive the restart, he added.   

There are other questions about the cost of introducing GFM.

GFM economics

There may be increased costs for integrating GFM into IBRs but there may also be market opportunities that offset the costs, engineers and developers said.

New inverter capabilities “do not seem to be making IBRs more expensive now,” Terabase’s Morjaria said. And as market incentives emerge, IBRs with GFM “could provide lower cost reliability services that create additional revenues because they use zero cost fuel,” he added.

GFM are “basically inverter software,” and reprogramming could make GFM-equipped batteries “marginally more expensive by a few percent of the inverter’s cost,” Matevosyan said. It will, though, be significantly more cost-effective to equip new batteries with GFM before they are deployed instead of incurring administrative, engineering, and downtime costs for upgrading after deployment, she added.

“There is also a cost for inaction,” Matevosyan continued. Without GFM deployment, “there will be continued stability challenges, continued solar and wind curtailment, and the need for costly supplemental stabilizing equipment like new transmission,” she said.

“It does not appear that the costs associated with integrating GFM will take solar, wind, and batteries out of the market,” Lauby agreed. And GFM can enable the transition away from legacy synchronous machines to IBRs, he added.

The challenge is to cost-effectively introduce IBRs with GFM to meet the growing incidences of events that threaten reliability, Lauby, Matevosyan and others agreed. NERC documented three reliability-threatening events associated with high IBR penetrations in 2022 alone, following five between 2017 and 2021.

One key solution — GFM-equipped batteries — is gaining attention.

Batteries to lead GFM deployment

The growing momentum to deploy utility-scale batteries offers a unique opportunity to take advantage of the policy-driven clean energy build-out and enable GFM at scale, engineers and analysts said.

“DOE is investing tens of millions of dollars and making GFM a huge priority and the industry needs to adopt it,” Department of Energy Director, Solar Energy Technologies Office, Becca Jones-Albertus told the September RE+ audience.

And deploying GFM in batteries “is a low-hanging fruit solution,” Matevosyan’s March 2023 ESIG paper on GFM and utility-scale batteries reported. GFM can be integrated with the over 400 GW of battery capacity in U.S. interconnection queues, enabling wind and solar growth “cheaper and faster than adding new transmission to mitigate stability issues,” she said.

Energy is immediately available in charged batteries to power reliability services, Matevosyan added in a September ESIG webinar. Solar and wind might not be producing when the energy is needed or might not be able to forego generation revenues, and services from wind might cause turbines mechanical stress, she added.

The Electric Reliability Council of Texas, or ERCOT, will finalize performance requirements for GFM-equipped batteries by the second quarter of 2024, Matevosyan reported. ERCOT will use the requirements to develop market incentives to drive adoption of GFM-equipped batteries at “weak grid” areas with high IBR penetrations, she said.

There is “a unique window of opportunity to procure, test and gain experience with GFM technology” while IBR levels are moderate and synchronous machines are still providing reliability services, Matevosyan said. And with well-designed policy and market incentives, IBRs with GFM could offset costs with revenues from new or existing stability services markets, Matevosyan added.

“It is recommended to start requiring and enabling GFM in all future Battery Energy Storage System projects,” a September NERC paper on GFM-enabled utility-scale battery systems concluded. It can be added to new battery systems “at a relatively low incremental controller and hardware cost” and “may only require controls changes,” it added.

Pilots, studies and standards

Simulations and pilots are needed to test GFM performance at scale, followed by multi-stakeholder processes to develop standards for GFM based on studies of the pilot results, NERC, ESIG and NREL agree.

NERC’s 2021 white paper and its September paper on GFM with battery systems both called for those next important steps to get beyond current limited experience with large-scale GFM penetrations, NERC’s Lauby said.

“Pilots are also needed to learn to manage sets of large, asynchronous generation while synchronous machines are retiring and load is growing,” Lauby continued. It is “very complicated engineering that could lead to using artificial intelligence, and it should be thoroughly modeled and simulated to understand the coordination and control implications,” he said.

“We need to have the same confidence with a system that has many grid following and grid forming inverters as we do with a system with synchronous machines,” Lauby added. But, Matevosyan responded, “everybody wants somebody else to adopt grid-forming capabilities first.”

“System operators need to think about operating the grid differently,” which is why DOE is funding 15 demonstrations of solar and wind projects providing grid services and reliability, DOE’s Jones-Albertus told the RE+ audience.  

Following research, development and field trials of GFM, standards can be established to allow synchronous machines to be replaced completely by IBRs with GFM over the following 10 years to 30 years, NREL’s roadmap said. But for “the next decade and beyond,” the power system will have both synchronous machines and GFM-enabled IBRs, it added.

Demonstrations in California in 2016 and 2017 provided reliability services, and a small Michigan installation built in 2014 continues to stabilize a “weak grid,” Matevosyan reported. Hawaii’s Kauai Island Utility Cooperative will soon pilot GFM-enabled batteries, and Florida Power and Light will use a 2,000 MW battery deployment over the next decade to assess “the performance and benefits of GFM,” other engineers added.

“But the learning from pilots needs to come faster because wind and solar penetrations are rising and synchronous machines are retiring,” Matevosyan cautioned.

The electric power and natural gas sectors should collaborate on a “blackstart system restoration plan” to bring the grid back online in the event of a widespread blackout, a joint report released Dec. 19 by the Federal Energy Regulatory Commission and North American Electric Reliability Corp. recommended.

Most large generators require electric power to begin operations, but blackstart resources are capable of starting up on their own and are critical to system recovery in the event of a grid collapse.

Most blackstart resources utilize natural gas but FERC Commissioner Allison Clements has indicated she wants to explore how inverter-based resources, or IBRs, such as wind, solar and batteries could help with grid recovery.

The joint report focuses on Texas, and arises from the 2021 Winter Storm Uri report, which identified instances where blackstart resources “were rendered unavailable during the storm,” said study authors. But the recommendations could apply to any area.

Winter Storm Uri resulted in widespread blackouts and almost 250 deaths in Texas, but not a total grid collapse. The aftermath led to efforts to redesign Texas’ energy markets and strengthen the electric grid.

The study represents an “important milestone in cooperation and collaboration among federal, regional and state groups,” FERC Chairman Willie Phillips said in a statement. “I urge all regions of the country to review it because they, too, can benefit from its recommendations and observations.”

The report’s recommendations are voluntary. Along with coordinated development of a blackstart recovery plan, it also recommended entities charged with developing the plan “examine the diversity of fuel, single points of failure, fuel arrangements, and other limitations of each blackstart resource.”

The gas and electric sectors should work collaboratively “to develop this plan and should prioritize the natural gas infrastructure required to supply natural gas to the blackstart, next-start, and other essential resources,” Mark Henry, chief engineer and director of reliability outreach for Texas RE, told FERC in a Dec. 19 presentation of the report. Texas RE is the NERC regional entity for the area served by the Electric Reliability Council of Texas.

The report also recommended recovery plans “evaluate and incorporate, where feasible, a wide variety of options” including inverter-based resources, high voltage direct current ties, variable frequency transformers and other resources.

None of the blackstart resources in Texas’ recovery plan were wind, solar or battery resources, the report noted.

“I am interested in how IBRs could be used for blackstart preparedness and in finding solutions to support all resources with the capabilities to bolster grid resiliency,” Clements wrote on X, formerly known as Twitter.

“We want to make sure this commission is thinking about how we allow for these resources ... to provide this critical grid service,” she said during the meeting.

Batteries could be used as backup power systems to energize critical equipment at power plants, the report said.

“The team believes that with ongoing improvements in battery technology, batteries could make valuable contributions in emergency operations by providing support early in the blackstart system restoration as a power source, as a controllable load, and as a tool to maintain frequency and voltage,” the report said.

It goes on to recommend state and other authorities “assess the impact of a blackout on the natural gas supply chain” and develop an electric grid restoration plan “that meets the needs of both the electric and natural gas industries.”

“The natural gas supply chain may be severely stressed or completely unavailable during a blackstart system restoration scenario,” the report warns. “Stored natural gas may increase the likelihood of blackstart and next-start resources being able to secure fuel more quickly and reliably in the event of a blackout, which may be necessary to start system restoration.”

“Effective blackstart system restoration requires the necessary electric and natural gas entities to work collaboratively across multiple jurisdictions and functional responsibilities to restore the system,” Robert Clark, FERC co-lead of the joint study team, told the commission Dec. 19. The report’s recommendations “are tailored to apply to all entities that play a role in blackstart system restoration,” he said.

Owners and operators of some inverter-based resources, or IBRs, like wind, solar and storage are not following voluntary operational guidelines, which increases reliability risks to the bulk power system, the North American Electric Reliability Corp. concluded in a Nov. 30 report.

About 5,200 MW of bulk electric system solar IBRs have voltage and frequency protection settings within NERC’s “no trip zones,” meaning they are at greater risk of going offline in the event of a grid disturbance, according to the report.

NERC recommended development of two reliability standard projects to improve IBR performance, as directed by the Federal Energy Regulatory Commission in October, and said it intends to issue an alert in early 2024 to gather additional modeling information from generators and transmission owners.

NERC is tracking a growing list of examples where IBRs have tripped offline or reduced output in response to grid disturbances, and in March it issued an alert and recommendations for solar resources connected to the bulk power system. But the report published Nov. 30 finds those recommendations “are not being implemented.”

The March alert required owners of bulk power system-connected solar facilities to provide site-specific information by June 30 via a data submission worksheet. Many generators “indicated that they did not have the requested facility data readily available,” NERC said. “The information requested in the worksheet is fundamental equipment information that NERC expects would be retained and easily accessible with some assistance from equipment manufacturers if necessary.”

Responses also showed more than 5 GW of solar IBRs on the bulk power system have voltage and frequency protection settings within the “no trip zone” NERC set in PRC-024, the protection and control standards for generators.

NERC recommends that all IBRs “have parameterized protection settings outside of the ‘no trip zones’ based on maximum equipment capabilities” in order to ensure the resources do not trip offline when when they are needed to preserve reliability, according to the report.

But about a quarter of reporting facilities use a protection system “that results in an increased likelihood of inadvertent tripping during normally cleared grid faults,” NERC said. And because of the way these protections are modeled, the “risks would not be captured in interconnection studies or during annual planning assessments.”

About a quarter of facilities “use a fault ride-through mode that does not adequately support BPS reliability,” NERC added. And about a third use power capability modeling that indicates the potential for “a significant amount of underused reactive power capability” which can negatively impact reliability services like voltage regulation.

“For many years, NERC has been working collaboratively with industry to produce world class recommended practices to help ensure reliability around this evolving technology,” Ryan Quint, NERC’s director of engineering and security integration, said in a statement. “The findings in this report demonstrate that potential reliability gaps exist when those recommended practices are not implemented.”

As a result, NERC said it will make development of two new reliability standards a “high priority.” One will modify PRC-024 and another will set performance standards for IBRs to address “systemic” performance issues.

“This report reiterates the criticality of implementing these standards in a timely manner to ensure adequate ride-through performance of IBRs as well as proactive risk mitigation,” NERC said. It also recommended examining how FERC interconnection agreements and procedures can further support the reliable integration of IBRs.

“Less than one-third of the inverter settings reported are set based on equipment capability, showing that there is significant underused ride-through capability” across the bulk power system, the report concluded.

A NERC subcommittee focused on IBR performance will develop a standard authorization request and should also consider proposing commissioning requirements for IBRs, the report said. The request “might mention that the standard could be applied at commercial operation to ensure adequate risk mitigation steps occurred during the commissioning process,” it added.

The National Association of Regulatory Utility Commissioners, or NARUC, has launched a 15-month effort to improve coordination between the electric and natural gas sectors, ultimately aimed at bolstering the reliability of the nation’s power grid.

The Gas-Electric Alignment for Reliability initiative, known as GEAR, will bring together a group of state regulators and stakeholders “to develop solutions to better align the gas and electric industries to maintain and improve the reliability of both energy systems on which our nation depends for power,” NARUC announced Nov. 22.

Electric generators are “more reliant than ever” on natural gas, NARUC noted. However, because residential customers also utilize gas to heat their homes in some regions, generators can find themselves with limited access to fuel during severe cold weather.

“The safety and reliability of the grid is job number one for regulators and the power sector,” NARUC President Julie Fedorchak said in a statement. She is also a North Dakota Public Service Commission regulator.

“GEAR will zero in on one of our biggest reliability risks, the [misalignment] of the gas and electric power systems,” Fedorchak said.

During Winter Storm Uri in February 2021, for example, some Texas electric companies cut power to gas facilities as part of their emergency conservation response. That reduced fuel supplies to gas-fired power plants, contributing to energy shortages and blackouts. Almost 250 people died during the storm.

NARUC’s effort “will bring together key industry experts with the perspectives and experience needed to get to the root of these persistent problems and develop some solutions,” Fedorchak said.

GEAR membership is still being finalized but Fedorchak has appointed Georgia Commissioner Tricia Pridemore as working group chair and New Hampshire Commissioner Carleton Simpson as vice chair. Other members include Michigan Commissioner Daniel Scripps, Arizona Commissioner Lea Márquez Peterson, Texas Commissioner Jimmy Glotfelty and Minnesota Chair Katie Sieben.

The group will also include representatives to be named later from each of the following: a gas utility, electric utility, grid operator, intrastate and interstate pipelines, a gas producer and a gas processor. 

NARUC is not the first group to study gas-electric coordination, and said it plans on using previous efforts in developing its own recommendations.

The North American Energy Standards Board issued a July report with 20 recommendations to harmonize the gas and electric sectors. Among them, the group called on state utility regulators to encourage utilities to develop demand response programs “in preparation for and during events in which demand is expected to rise sharply for both electricity and natural gas.”

According to the working group’s charter, NARUC’s GEAR plans to give a status report on its efforts at the November 2024 NARUC annual meeting and develop a final report and recommendations by February 2025, ahead of NARUC’s Winter Policy Summit.

Cloud technologies could provide significant cost, security and reliability benefits to the U.S. electric grid but critical infrastructure rules do not allow them to be used for certain larger assets, multiple speakers said Nov. 9 at the Federal Energy Regulatory Commission’s annual reliability conference.

The Critical Infrastructure Protection rules, or CIP, are managed by the North American Electric Reliability Corp. and currently require grid asset owners to have certain control or knowledge of the devices operating their software. Cloud computing makes that difficult or impossible, experts agreed, in particular for what are known as high- or medium-impact grid assets.

Current NERC standards “do not provide clear guidance” on how regulated entities can implement new technologies that may not have been envisioned by the current CIP rules, Joseph Mosher, portfolio manager at EDF Renewables, told the commission. “Attempts to incorporate newer technology into the NERC CIP standards can be painful and time consuming,” he said.

Experts expressed concerns over the outdated CIP rules, at a time when grid officials say they face growing threats.

“One can definitely make the argument that the grid is less secure today than it would be” if cloud computing solutions were allowed, “and that gap is growing every day,” security consultant Tom Alrich said. “This is the biggest problem with NERC CIP today.”

A related problem — that important information about those systems can't today be stored in the cloud — will be fixed beginning next year when two revised CIP standards come into effect, he said.

A sector under attack

The cyber threat to the electric power sector is growing, and grid officials say they must utilize new tools to counter it.

“The electricity sector is under constant attack by nation states and organized criminals. We see billions of attempts a day to survey our networks, identify vulnerabilities or gaps in protection, steal credentials or data, or exact a ransom,” Manny Cancel, senior vice president and CEO of the Electricity Information Sharing and Analysis Center, told regulators Nov. 9. The E-ISAC is operated by NERC.

China is the biggest cyber threat to the U.S. grid, Cancel said, followed by Russia.

“China will continue to target critical infrastructure here in the U.S., to grow their knowledge and identify access points for future use,” he said. Hackers are constantly looking to exploit vulnerabilities in enterprise software platforms “that are used pervasively across the electricity industry,” he added.

The database of cyber vulnerabilities maintained by the National Institutes of Standards and Technology is on pace to report over 27,000 vulnerabilities in 2023, Cancel said, representing a 25% increase over 2022, and "many of them are critical.”

Those vulnerabilities can combine with the rapid expansion of grid-connected assets to create a threat-rich environment, experts agreed.

The rate at which smaller generators, such as solar, wind and batteries, are connecting to the grid is multiplying not only the number of generators but also the vendors necessary to support the infrastructure, Mosher added. “In many cases” these new vendors may not fully support on-premise solutions “and instead require a full or partial cloud implementation, potentially making the generator owner noncompliant with NERC CIP,” he said.

‘These tools cannot be used’

Some of ISO New England’s most robust security tools are not allowed to protect certain electric system assets because they use cloud technology, said Rudolf Pawul, vice president of information and cyber security services for the grid operator.

“Traditional log monitoring and malware detection is insufficient in the face of modern threats,” Pawul said. The ISO “has augmented its traditional security tools with learning-enabled endpoint detection, backed by world class threat hunters, and similar tools for application performance monitoring that aids with anomaly detection. Unfortunately, these tools cannot be used for several ISO New England systems, including some of the most important ones.”

ISO New England has submitted a standards authorization request to NERC “with the hope that the standards can be revised to allow the use of cloud-based services,” Pawul said. “Despite the broad support and a positive reception from both NERC and [the Northeast Power Coordinating Council] the CIP revision process will take years.”

Pawul also said the process of integrating new technologies — not just cloud computing — should be reviewed.

“Whether it is artificial intelligence, quantum computing or the next disruptive technology, the industry will again be at a disadvantage unless it adapts. ... the energy industry must assess the ramifications of the CIP standards on disruptive technology sooner [and] reduce the time spent to make revisions, or create a process for compliance exceptions within the CIP reliability standards,” Pawul said.

The need for cloud computing solutions on the power grid extends beyond security, experts said.

Decarbonization will require cloud computing

Cloud technologies “are key in augmenting security teams’ abilities, with increased visualization, automation and resilience,” Maggy Powell, security assurance principal for the power and utility sector at Amazon Web Services, told the commission. But beyond that, the operational demands of decarbonization, decentralization and digitalization “translate to a more than 100 times increase in data volumes to reliably operate the grid, making computing capacity essential,” she said.

Cloud computing can offer utilities opportunities to gather instructive information from the new data “and create value for applications such as predictive maintenance, outage management, power flow analysis and other operational applications,” Powell said.

The last complete update of NERC CIP standards was finished in 2017, and that endeavor took more than eight years, Alrich said. Because of the critical nature of cloud computing, he said a solution will likely be developed much sooner. 

“This is one of those cases where the vendors’ interests and the users’ interests and the regulators’ interests are all the same,” Alrich said. “There's got to be a way this can be done sooner than eight or nine years ... Pretty soon there's not going to be any software to run on premises anymore.”

Utilities are beginning to use artificial intelligence to operate the electric grid more reliably and efficiently, but there are also challenges and risks to consider, including data privacy, cybersecurity and AI’s own energy use, experts told the House Energy and Commerce Subcommittee on Energy, Climate, and Grid Security Oct. 19.

AI’s energy use cases include load and weather forecasting, predictive maintenance, grid management, enhancing the output of wind and solar resources, faster storm recovery, wildfire risk assessment and methane leak detection, witnesses told lawmakers.

Excluding China, AI represents 4.3 GW of global power demand today and could grow almost five-fold by 2028, Sreedhar Sistu, vice president of artificial intelligence offers for Schneider Electric, told the subcommittee. Of that demand, 30-45% is estimated to be in the United States.  

“AI is already helping stakeholders better forecast power consumption,” Sistu told the subcommittee. Electric utilities and microgrid managers leverage the new technology “to forecast short-term energy consumption more quickly and efficiently across the entire geography of their grids.”

But while AI can be used to operate a more efficient electric grid, Sistu also warned of its growing energy demand. Global AI power demand, excluding China, is estimated to reach 13.5 GW to 20 GW by 2028, he said.

“With a grid that is already straining to meet existing demand, it is imperative this committee consider how strategic, future investments in physical infrastructure can support the growth of AI in America, which will in turn support the future of our grid,” he said.

The Electric Power Research Institute has been involved in more than 70 projects utilizing AI, said Jeremy Renshaw, the group’s senior technical executive for AI, quantum, and innovation.

“While automated grid operation may still be more than a decade away, current models may be useful in assisting grid operators as decision support agents to provide recommended actions to maintain grid operation,” Renshaw said. 

The new technology can contribute to the safety, affordability, and reliability in energy generation, delivery, and consumption, he said. But EPRI “has found it also poses new challenges, such as cybersecurity risks, ethical considerations ... and data privacy and security.”

Paul Dabbar, the CEO of Bohr Quantum Technology and former DOE under secretary for science, said AI is “beginning to remake energy operations” but warned about the potential for security threats.

“National security can be placed at risk with the new hardware and software deployment,” Dabbar said. China can “place physical back doors on their chips, and holes in AI algorithms, to allow sabotage. The security challenges of this new AI and digital infrastructure are acute.”

Cybersecurity “has become an increasingly large concern,” Renshaw said, but he noted that AI has the opportunity “to be both an offensive and defensive force-multiplier for cybersecurity applications.”

As cybersecurity standards are developed for AI, Schneider Electric’s Sistu said Congress “should work alongside us to both ensure these standards support the government’s goals.”

Protection of consumer data “must also be a critical focus of AI regulation,” Sistu said. “Industry must apply and exceed standards for data protection and, like cybersecurity standards, should work alongside government to develop meaningful data privacy and protection standards for AI applications.”

Rep. Frank Pallone, D-New Jersey, expressed some reticence at the pace of AI adoption.

“It’s clear that AI will likely be a part of our energy future,” Pallone said. Utilized alongside distributed energy resources, the technology “can help us transition to a clean energy future. ... with that being said, we must proceed with caution. Guardrails must be put in place to ensure the adoption of AI is responsible.”

AI can help power plants run efficiently

Rep. Jeff Duncan, R-S.C., chair of the subcommittee, asked witnesses how AI could be used to improve operations in oil and gas production and in the nuclear sector.

AI can be used to improve the reliability and throughput of oil and gas producers, said Edward Abbo, president and chief technology officer for C3.ai. The technology can be used to increase production at refineries or from wells; reduce energy consumption in oil and gas production; and to survey assets in the field such as pipelines.

“Essentially, AI can be used across the upstream, midstream and downstream sectors,” Abbo said.

Generator performance can be improved by installing sensors on turbines and breakers, said Dabbar. Over time power plant operators can collect sufficient data to efficiently perform predictive maintenance and “drive up availability, making more power for cheaper cost. It’s more reliable. It’s already being deployed on certain types of power plants.”

In 2000, the U.S. electricity grid earned the distinction of being designated the top engineering achievement of the twentieth century by the National Academy of Engineering. Even with this badge of honor, the electric grid needs help as the country transitions from relying on fossil fuels to clean electricity. While a clean energy future is necessary, it comes with its own challenges as aging fossil field plants retire and new resources come online. Just as the introduction of the first smart phone prompted skepticism about its future in a world dominated by landlines, so do these new resources. This is especially true when it comes to their ability (and incentives) to provide essential reliability services, or ERS.

These new resources are more than capable of providing ERS, but grid operators must gain confidence that services are available when needed, and regulations and market signals must align with these needs.

The reliable operation of the grid is apple pie, reliability services are the slices

Electricity supply and demand must always be balanced to maintain relatively constant frequency and voltage. During normal operations, small changes in demand occurring in each moment must be matched by corresponding changes in resource output to maintain balance.

If the supply-demand gap becomes too large, this imbalance could lead to emergency operations of the grid. In extreme cases, outages and damage to equipment or appliances could occur. Think of the grid as a tightrope walker maintaining equilibrium at great heights, any disturbance beyond a nominal amount will result in a fall.

Much like apple pie ingredients, every machine, technology, and software supplying electricity makes different contributions to grid reliability. Not every resource must provide all types of reliability services, but the entire pie (or portfolio) must be able to respond appropriately to bring the grid back to balance.

To maintain stability, each service available in the portfolio acts in a particular time frame. For example, fast frequency response occurs in the seconds immediately following a disturbance to slow decline, and is followed by primary frequency response, which stabilizes frequency. Economic dispatch, which as the name suggests is grounded in economics, typically operates at a five-minute time step, and longer time steps are typically managed by automatic or manual dispatch through market mechanisms. These services combine to restore frequency if a large generator or transmission line fails.

When more major disturbances occur, the pie must have sufficient disturbance ride-through capabilities to maintain frequency and voltage to keep resources operating through instability. In addition to frequency restoration, generators, grid equipment, and even inverter-based resources, or IBRs, can ride through voltage disturbances and restore system stability. Maintaining stable voltage keeps the lights on and avoids equipment damage but requires different capabilities like reactive power control, which allows for voltage control in the alternating current, or AC, network.

Ma Bell, meet smart phone

Traditionally, grid operators obtained services from large thermal units and rotating machines — such as coal-fired, nuclear, and hydro-electric power plants — because the physical attributes of those machines provided the grid services needed for an AC grid. Their large, spinning mass provides inertia, which contribute to stability. The imminent retirement of dozens of coal plants is prompting new questions about the ability of renewables and storage to provide this inertia and other ERS.

This task is not straightforward. Grid reliability expert and former NREL Principal Researcher at the Electric Systems Integration Facility Michael Milligan explains that “new resources behave differently than incumbent resources.”

Solar and wind energy, for example, connect to the grid via inverters which convert the direct current they generate to the AC flow of the grid. During 2023, the hottest summer on record, states and electric grids with more renewables and energy storage fared well. These resources helped balance the grid when demand for cooling combined with extreme temperature stress on grid infrastructure. While “there is an emerging recognition that inverter-based resources can provide certain grid services,” says Milligan, “greater awareness is needed [on how].”

More research and investigation into these capabilities is warranted so these resources can replace retiring resources’ ERS. One study compared grid services from a wind plant, a gas plant and a coal plant, finding that wind could provide certain services faster. But doing this systematically would require new standards and markets that incentivize and ensure performance from IBRs.

We need greater focus on strategies to integrate renewables into markets and compensate them in a way that reflects their ability to respond. For example, renewable energy developers may be disinclined to program their resources to ride through a voltage event if such a setting could compromise their asset. This led to grid reliability events in Texas and California where solar and wind facilities tripped offline when voltage fluctuated too far, exacerbating stability issues rather than solving them. While these incidents are uncommon, they spotlight the need for an appropriate response.

Grid operators, NERC and collaborative research organizations like the Energy Systems Integration Group are already working toward implementing innovative solutions. Going forward, utilities and grid operators should quantify and understand how IBRs can respond during a grid emergency — in some cases the IBRs may be capable of providing a superior response, but they must be sufficiently compensated for doing so.

Batteries, one of the fastest growing new IBRs, are untapped sources of ERS. New advanced controls allow batteries to provide stability that has traditionally been delivered by conventional synchronous generators, known as grid forming. As these new battery resources coming online, there is a ripe opportunity for evaluating their performance. Demand-side technologies also represent an untapped source of ERS.

Operating a reliable grid requires institutional reforms

Numerous factors that impact reliability must evolve apace of the technologies themselves. For example, energy market rules and economic incentives often subject to government policies and regulatory requirements dictate how the energy resources and technologies can, and will, operate. Ideally, a combination of carrots and sticks can influence grid reliability and performance by reflecting real-world operating characteristics of various technologies, allowing and encouraging resources to “show up” with the requisite grid services.

Grid operators, already on the transition frontlines, will need to continue facilitating changes like ensuring the right settings and programming for new equipment. Shifting how the grid is operated requires more awareness of the dynamic capabilities of IBRs, and appropriate rules, market signals and mechanisms to call on those capabilities during times of need.

Grid plans should evaluate the real and potential risks, including those caused by climate change-exacerbated extreme weather. Grid planning takes on a new importance in the face of so many emerging and pervasive threats. “If you can’t plan a reliable system, you can’t possibly operate a reliable system,” Milligan says.

And, as utilities and grid operators deal with mounting challenges in the face of more intense storms, solutions should aim to “make the grid larger than the storm,” Milligan says. This could include more transmission between regions, better interregional coordination on emergency response, and ensuring market rules sufficiently incentivize grid services from IBRs.

A new recipe for the pie, aligned with the laws of physics

Reliability services are essential ingredients to grid reliability, but adapting to changes requires updating the pie recipe. IBRs can provide much — and perhaps all — of what we need, but we need new approaches and thinking. Beyond efforts to understand and embrace new technological capabilities, Milligan says we need to ask better questions, such as “how can fast frequency response replace inertia? How do we incentivize resources to provide needed services? Will market designs prevent or inhibit these incentives?” Collaborative research can help, but accepting findings and adopting new approaches can facilitate an expedited evolution.

There are five “significant evolving and interdependent risks” to grid reliability, and energy policy tops the list, the North American Electric Reliability Corp. said in a report published Aug. 21.

Rounding out the five risks are grid transformation, extreme events, security and critical infrastructure interdependencies. Those four threats were all included in the 2021 version of NERC’s Reliability Risk Priorities Report, but energy policy is a new addition this year.

With increased legislative focus on decarbonization, decentralization, and electrification, energy policy is expected to drive rapid change, NERC’s report concludes. “There is an undeniable need to increase coordination and collaboration among all policy makers and regulators as well as on the owners and operators” of the bulk power system, it said.

The report was accepted by NERC’s board of trustees last week at its quarterly meeting. Board Chair Kenneth DeFontes called it the “best” report by the Reliability Issues Steering Committee to date.

The report draws attention to “some key, new risk profiles including the need to bridge important jurisdictional lines in energy policy and the interdependencies between our industry and other critical infrastructures,” DeFontes said.

Risks surrounding energy policy include “existing resource sufficiency requirements and underlying studies” which were based on a “pre-decarbonization paradigm that traditionally focused on peak capacity requirements and assumed energy sufficiency would result,” NERC said. “With a higher proportion of variable and renewable fueled resources evolving, this aspect of resource adequacy must be more specifically assessed.”

Increasing interdependencies between the gas and electric sector, and challenges in reliably incorporating aggregated distributed energy resources into the bulk power system, are also policy risks, the report said.

Along with increased communication and coordination between stakeholders, NERC recommended outreach to policymakers and regulators to increase awareness of the reliability implications of their policy decisions.

“In addition, education for the industry, as the developers of reliability standards, is needed to better understand the processes and implications of policy decisions,” the report said.

To address risks associated with grid transformation, NERC recommended operators ensure sufficient operating flexibility.

“System operators and planners should ensure that sufficiently flexible ramping/balancing capacity is available to meet the needs of changing patterns of variability and new characteristics of system performance,” the report said. “In future decades, growing storage and demand-side flexibility may help mitigate the concerns for flexibility and attention will turn to multi-day energy concerns, but intraday flexibility remains important during this transition.”

To counter risks from extreme events such as wildfires, hurricanes, heat and drought, the report recommends grid operators conduct “special assessments of extreme event impacts,” and “create simulation models, and establish protocols and procedures for system recovery and resiliency.” Planning and construction of transmission assets should also be accelerated.

To combat security risks, including physical and cyber threats, NERC should facilitate the development of planning approaches, models, and simulation methods “that may reduce the number of critical facilities and thus mitigate the impact relative to the exposure to attack.”

Critical infrastructure interdependencies, including gas pipelines, water resources and digital communications, should primarily be addressed through additional studies, modeling and the development of weatherization standards, the report said.

“The importance of the critical infrastructures interdependencies ... show potential reliability risks can be magnified when in isolation,” Soo Jin Kim, NERC vice president of engineering and standards and liaison to the RISC, said in a statement.

NERC should also investigate the feasibility of “potential infrastructure improvements, such as feeder segmentation required to facilitate more pinpoint control of load during emergencies in order to increase the amount of load available for rotating outages,” the report said.