Reliability

North American Electric Reliability Corp. CEO Jim Robb spoke July 25 at the WIRES summer meeting, laying out the challenges and opportunities that a changing resource mix creates for the North American energy system.

“We are in a pretty amazing period of time for the electric grid, because of the pace of change that we're seeing, and the fact that it's coming at the grid from a number of different directions at the same time,” he said. “We're having to rethink a lot of things.”

Historical planning approaches are not as effective as they once were, as weather has become more extreme. Physical and cyber attacks are on the rise, while generation retirements are threatening reliability. Utilities see electricity demand rising for the first time in years, Robb said.

NERC was formed in 1968 to address issues related to a blackout three years prior that left 30 million people in the U.S. and Canada in the dark. For decades, the organization focused on the basics of utility operations, like vegetation management, situational awareness, training and communications, Robb said.

“And now we're into a lot of very frontier issues where we need to understand the science at the same time [that] we're trying to draft requirements — and that's obviously challenging all of us to rise to the occasion,” Robb said.

Here are five takeaways from Robb’s speech.

Another 100 GW of retirements could further threaten reliability 

NERC published its annual Long-Term Reliability Assessment in December, warning that rising peak demand and the planned retirement of 83 GW of fossil fuel and nuclear generation over the next 10 years creates blackout risks for most of the United States. In particular, the Northeast and Western half of the U.S. face an elevated risk of blackouts in extreme conditions, while parts of the Midwest and central South areas could see power supply shortfalls during normal peak operations.

The next LTRA will likely show the risk is growing, as new data center loads are added into the assessment, Robb said. Electricity demand from data centers could double by 2030 to consume 9% of U.S. electricity generation, according to the Electric Power Research Institute.

And NERC is aware of another possible 100 GW of capacity at risk of retirement in the PJM, Mid-Atlantic and South areas.

Right now those areas are characterized as having a “normal energy risk,” but the next LTRA “will almost certainly put those areas into the high-risk category if those retirements get solidified,” Robb said.

2 TW of capacity in interconnection queues

While increasing thermal retirements are driving reliability risks, renewables developers are working to bring on new resources quickly. Interconnection queues are “now twice the size of the existing resource base of the country,” Robb said.

There are about 2 TW of projects looking to connect to the grid, though there is some double counting in that figure, he said. Meanwhile, existing capacity today is about 1 TW.

“That 2-to-1 ratio is stunning ... Typically, the aggregate interconnection queues are about half to a third of the installed base,” Robb said. “So that shows how much investor interest there is in new generation resources,”

And the vast majority of the proposed projects are wind and solar, “with a smattering of batteries, a little bit of gas, no coal, no nuclear of any consequence, and no hydro. So it's very, very clear that as we move forward, the lion's share of new additions we'll see on the grid will be largely variable resources,” Robb said.

Electric-gas coordination is vital

The transition to a renewables-heavy resource mix will require natural gas generation and greater coordination between the gas and electric systems, Robb said.

“It's not that I love natural gas so much, but I really love natural gas generation,” Robb said, pointing to its ability to operate reliably and flexibly on a dispatchable basis.

“We need to be paying really, really close attention to securing the balancing resources to integrate variable resources reliably,” he said. “Long term, we may come up with a long-duration battery technology that can be used. Hydrogen in some areas may play a role in that. But right now, really the only way to deal with that is natural gas.”

That means the gas and electric systems must work in tandem, he said.

“We think of these two systems as being increasingly interdependent and interconnected, not just two parallel systems that happened to grow up together and have some marriages of convenience,” Robb said. “They're now intimately linked ... electricity is now 40% of gas consumption in the U.S.”

Grid faces a ‘toxic soup’ of security threats

Along with risks related to the clean energy transition, cyber and physical threats are growing, Robb said.

“We're living in an absolute toxic soup of security threats,” he said. “And I think over the last four years, the threat environment, both for physical and cybersecurity has really changed.”

Utilities must defend against the “big four” nation state adversaries of Iran, China, Russia and North Korea and the organized cyber criminals that they sometimes sponsor, Robb said. And then there are the “punks, thugs and crooks” focused on ransomware and physical attacks.

The cyber risk is “driven by the fact that we have software embedded everywhere [but] we rarely know exactly where the coding came from,” he said. The National Institute of Standards and Technology publishes a list of vulnerabilities and it is averaging about 60 entries a day, Robb noted.

Once a vulnerability is published, chief information security officers must determine the extent of the exposure and how to mitigate it, at the same time hackers look for ways to exploit it. “It becomes a foot race, to figure out how to defend against it while [hackers] are trying to figure out how to exploit it,” Robb said.

There has been a similar threat shift on the physical side, Robb said. Substation attacks in Moore County, North Carolina, knocked out power to about 40,000 customers in December 2022, and similar incidents have been seen in Idaho and Washington.

“The ability of adversaries to physically attack different pieces of infrastructure, and be able to create a wider spread event, is of increasing concern,” Robb said. “So we have to be paying really, really close attention to physical and cyber [security] hygiene.”

Transmission study a ‘bigger beast’ than anticipated

NERC, at the direction of Congress, is in the process of developing an interregional transfer capability study that will be delivered to the Federal Energy Regulatory Commission by December 2. Following that, NERC will produce an analysis in the first quarter of 2025 to evaluate transfer capabilities from the United States to Canada and between Canadian provinces.

“This turned out to be an even bigger beast than we thought it was when we started,” Robb said. NERC published an initial report on the study in June, providing context and study details. 

“What we're looking at is not trying to optimize price or cost, but looking at optimizing reserves,” Robb said. “The challenge with interregional transfer assessments is that it really has a little bit to do with the wires but it's got a lot to do with the generating resources in the various planning areas and the loads and the nature of the weather patterns that we're dealing with.”

NERC is doing scenario analysis, using historical data on big storms to pressure test the system. “We also have to forecast where we think new generation will come in and what it will look like, and how it would be impacted by those weather systems,” Robb said. 

Early insights from the work show that regional transmission capacity is very different in summer and winter, and it's not very evenly distributed, he said. NERC plans to publish another report in August that will lay out the current transfer capability, and then around November will disclose where additions are likely to provide value.

“There's not going to be a lot of time from the time we ... publish our draft report to when we have to file it at FERC. So I'm encouraging everybody to try to engage in the webinars that we're having to get points of view across earlier rather than later because there's not going to be a lot of review time,” Robb said.

Electricity demand from data centers could more than double over the next decade, threatening U.S. grid reliability and increasing operational risks for other businesses, the Conference Board said in a May 30 report.

Due to limited grid and transformer capacity and long permitting and interconnection timelines for new generation and transmission projects, expected data center load growth could slow the pace of the United States’ transition to a net-zero electricity system, the report said.  

“More positively, the broad adoption of AI tools might unlock greater efficiencies in the way electricity is used, as well as generated, stored and transported,” wrote authors Alexander Heil, senior economist at the Conference Board’s Economy, Strategy and Finance Center, and Ivan Pollard, leader for the Conference Board’s Marketing and Communications Center.

Global energy consumption from data centers, including those devoted to AI and cryptocurrency mining, could jump from 460 TWh in 2022 to more than 1,000 TWh in 2026, according to an International Energy Agency projection cited by Heil and Pollard.

In the United States, data centers’ electricity consumption could double to more than 9% of total U.S. generation by 2030, the Electric Power Research Institute said in May.

Some models expect even more dramatic growth over the next five to six years, said Josh Claman, CEO of Accelsius, a provider of computer chip cooling technology. 

High-end predictions for data center energy consumption “sound like hype, but we can’t discount them yet,” Claman said.

Accelsius and competitors like LiquidStack and Marathon Digital Holdings develop direct-to-chip cooling systems that use non-water refrigerants that transition from liquid to vapor to maximize cooling efficiency. Data center operators are quickly realizing that this type of system offers the longest technological runway for AI and high-performance computing applications, Claman said.

Cooling accounts for roughly 40% of data centers’ total energy consumption today, but two-phase liquid chip-cooling systems like Accelsius’s can reduce server racks’ power consumption by 50% or more, and the industry as a whole will become more efficient as more data centers transition from air- to water-based cooling, Claman said. 

Still, demand for AI could outpace those efficiency improvements and sustain the recent rapid growth in data centers’ absolute electricity consumption, he said. Though improvements in silicon-based chip technology or the emergence of reliable quantum computers could dramatically reduce the energy demands of high-performance computing, current research on those fronts is likely a decade or more from commercialization, meaning utilities and grid operators can’t expect them to mitigate near-term load growth, Claman added.

In the meantime, load growth attributable to data centers could slow progress toward utility, state and federal net-zero goals, the Conference Board report said. 

Smaller utilities that can’t readily procure additional renewable power or quickly deploy renewable generation may be hardest-hit. Oregon’s 16,000-customer Umatilla Electric Cooperative saw its carbon emissions quadruple between 2018 and 2021 following an influx of Amazon data centers into its territory, the report noted.

Utilities with inadequate renewable capacity could also lose high-load customers with ambitious near-term net-zero goals, including technology companies and data center operators, the Conference Board said. 

Such customers could “relocate…to another location where [their] environmental needs could be met,” the report said.

Utilities and data center operators can mitigate the threat to climate goals by locating facilities “next to distributed power resources such as solar, wind or even nuclear [plants to] allow low-carbon energy to be utilized directly,” the report said. 

Public Service Enterprise Group is in talks with data center operators to sell power generated by two New Jersey nuclear plants, Utility Dive reported in May.

AI-driven load growth could be a boon for the U.S. nuclear industry in general, according to the Conference Board. “Any dramatic increase in electricity demand from data centers and AI might further prioritize the use of nuclear energy as an emissions-free power source,” the report said.

The report downplayed the potential for AI to drive dramatic breakthroughs in grid efficiency. Although more sophisticated AI tools could enable more efficient electricity generation, storage, delivery and use, “how much AI can offset its own increase in load demand remains an open question,” Heil and Pollard wrote.

Instead, public and private actors could offset AI-driven power demand growth through more conventional solutions like energy efficiency, peak shifting, expedited permitting and interconnection for new energy resources and broader adoption of small nuclear reactors, they said.

In response to state utility regulators and other advocates, the PJM Interconnection and the Midcontinent Independent System Operator have agreed to look for possible near-term transmission upgrades that would increase power flows between their footprints.

PJM and MISO will explore opportunities to engage in joint transmission analysis and coordinated modeling while using existing planning processes to promote reliability and resiliency through “holistic, efficient and cost-effective” transmission planning, the grid operators said. They plan to finish their “informational” study early next year.

This is the first time MISO and PJM will specifically look for opportunities to increase transfer capability between their two regions, according to Natalie McIntire, a senior advocate with the Sustainable FERC Project. “There's a huge opportunity to get this right, boost reliability, and reduce congestion — but to deliver those benefits, we hope the two grid operators are prepared to work closely on taking action after they conduct this study," McIntire said in an email.

The Organization of MISO States and the Organization of PJM States, which represent state utility commissions, in January urged the two grid operators to bolster joint long-term interregional transmission planning between their footprints. Similar calls were made by the Midwest Governors Association and a coalition that includes Advanced Energy United, Clean Grid Alliance, the Sierra Club and others.

“As we continue to focus on our Reliability Imperative efforts, we understand the need to explore interregional planning, and with encouragement from OPSI, OMS and MGA, we will conduct a study that will address both near-term needs and create a model for future studies,” said Aubrey Johnson, MISO vice president of system planning and competitive transmission.

While Federal Energy Regulatory Commission Order 1000 on transmission planning requires interregional coordination between grid operators, that coordination amounts to very little in most cases, according to Rob Gramlich, president of Grid Strategies, a transmission-focused consulting firm.

“I’m very glad to see this initiative,” Gramlich said in an email. “I hope incumbent generators, which tend to want to stop interregional transmission from adding competition in energy markets, refrain from trying to block this effort since it is very important for reliability.”

A study conducted by Grid Strategies found that increased transfer capacity between MISO and PJM could save more than $15 billion by 2035, in part by reducing the need for generation.

The Department of Energy’s national transmission study, released in October, found that the border between PJM and MISO needs between 27.9 GW and 51.7 GW of new transfer capacity by 2035 to handle moderate load growth and high amounts of new clean energy.

FERC has been considering requiring regions to have minimum amounts of transfer capacity, in part to allow for more power-sharing during extreme weather. The Big WIRES Act, legislation pending in Congress, would require regions to be able to transfer at least 30% of their peak loads with other regions.

Ask any power system operator and they’ll tell you: Early detection is crucial. The sooner we identify a potential problem, the more options operators have at their disposal — allowing issues to be resolved before they become emergencies. This is true whether a challenge develops within a single day, or over a longer-term planning horizon.

ISO New England’s new Probabilistic Energy Adequacy Tool, or PEAT, created as part of a joint effort with the Electric Power Research Institute, is part of our comprehensive and proactive approach to planning for a reliable future power system.

Climate change, and the decarbonization policies states are implementing to curb it, are fundamentally altering the way consumers use electricity in New England, as well as the types of resources that provide that energy. These changing conditions make it more challenging to assess our region’s long-term ability to meet consumer demand.

ISO New England and EPRI recently completed a first-of-its-kind study that analyzed the impacts of extreme weather on the region’s energy supplies within an operational timeframe. The analysis takes into account the increasingly important role weather plays in power system operations, examining how factors such as temperature, cloud cover and wind speed may impact future electric power generation (i.e., energy supplies) and consumer demand.

EPRI reviewed more than 70 years of New England weather data — factoring in several models that forecast how the region’s climate might change — to determine the weather conditions most likely to threaten energy supplies. Then, the team used the ISO’s 21-day assessment tool — itself a one-of-a-kind energy supply outlook — to evaluate the New England power system’s capability to manage disruptions in energy demand and supply over a three-week period under extreme weather conditions.

The study creates a detailed snapshot of risks of energy shortfalls — a condition that happens when the region’s electricity supply falls below consumer demand — for the two target years — 2027 and 2032.

At a high level, we learned that the risk of energy shortfalls during winter cold snaps appears manageable over a 21-day period, meaning that existing situational awareness measures, communication protocols and operating procedures, such as calls for energy conservation, are likely to be sufficient to mitigate the low probability risk of energy shortfalls.

In addition, our results confirm that the region’s energy shortfall risk profile is dynamic and will evolve along with supply and demand patterns. Similarly, we know that an increasingly risky energy profile could emerge if key assumptions about the future system don’t hold.

This fluidity highlights the importance of a key deliverable from the study: development of the PEAT, which acts as an early warning system, identifying circumstances that could lead to an energy shortfall, and alerting the region to the likelihood and magnitude of potential problems. From there, steps can be taken to mitigate the risk.

Beyond its use in this initial study, PEAT provides the region with the framework needed to assess energy adequacy risk moving forward. It will serve as the baseline in discussions with the New England states and other stakeholders on establishing a Regional Energy Shortfall Threshold, meant to indicate an acceptable level of energy shortfall risk common to the six states during extreme weather.

Once the Regional Energy Shortfall Threshold is established, the region can consider potential solutions that would trigger if the PEAT-based energy assessments project risk greater than the agreed-upon threshold. These solutions could include adjustments to wholesale market designs, investments in infrastructure, or dynamic retail pricing and additional responsiveness by end-use consumers. Some of these solutions fall under the purview of the New England states, who will be key participants in the regional discussions about scope, timing and feasibility happening in 2024 and 2025.

Gone are the days when power system planning was simply about making sure there was sufficient steel in the ground on the hottest and coldest days of the year. At ISO New England, we’re building tools that provide vital information about tomorrow’s system, helping us better understand potential risks and how to mitigate them.

By providing trusted information to the region’s energy stakeholders, these tools facilitate our journey to a greener future, and spur the regional conversations and collaboration needed to provide meaningful, long-term solutions to the challenges we’ll meet on the way.

The Midcontinent Independent System Operator on March 28 asked federal regulators to approve a capacity accreditation methodology that aims to better account for how much different resources bolster grid reliability during stressed periods.

MISO plans to begin using the direct loss of load, or DLOL, -based capacity accreditation methodology for the 2028/29 planning year, but intends to release indicative results as soon as possible to give stakeholders time to adjust their long-term resource planning and retirement decisions, the grid operator said in its proposal with the Federal Energy Regulatory Commission.

MISO said its proposal addresses growing reliability risks driven by various factors including increasing demand and shrinking reserve margins. “The changing resource mix combined with extreme weather and shifting load profiles have created what the [North American Electric Reliability Corp.] has characterized as a ‘hyper-complex risk environment,’” MISO said.

Grid operators — such as the Southwest Power Pool, PJM Interconnection and ISO New England — have been making changes to how they measure capacity in efforts to ensure they have adequate resources to maintain grid reliability.

MISO’s proposal, developed through a two-year stakeholder process, is part of its Resource Availability and Need initiative, which led to plans to revise the grid operator’s demand curve used to set capacity prices, and a shift to a seasonal capacity framework.

MISO’s two-step proposal blends probabilistic and historic approaches. In the first step, MISO will measure a resource’s expected marginal contribution to reliability using resource class-level performance during a loss of load expectation analysis, the grid operator said. In the second step, MISO will use historical resource-specific performance during hours when capacity was tight over the previous three years.

“The DLOL-based methodology balances a range of reliability risks in the planning and operations horizons by incorporating forward-looking probabilistic analysis and measuring a resource’s performance during recent periods of high system risk,” MISO said.

Potomac Economics, MISO’s market monitor, supports the proposal. “Establishing accreditation that is accurately aligned with reliability will ensure that the capacity market provides efficient incentives to invest in and maintain a portfolio of resources that meet the reliability needs of the MISO system,” David Patton, president of Potomac Economics, said in an affidavit included with MISO’s application.

Intermittent generation — such as wind and solar — provides MISO with less and less reliability as more comes online because it lacks key attributes provided by dispatchable resources, Patton said.

“Resources with essential attributes or attributes that are in short supply will receive relatively high accreditation levels while those lacking such attributes that provide little marginal reliability value will receive lower accreditation,” he said.

The proposed accreditation framework will send clear signals to utilities and state regulators on what kinds of resources the grid needs, according to Patton.

Also, it will likely “substantially” change MISO’s expectations for what resources will be on its system in the future, altering its outlook for new transmission, Patton said.

MISO told FERC the grid operator needs to put its proposal in place in three years — and not longer, as some stakeholders asked for. About 50 GW of planned generation has cleared MISO’s interconnection process, including 32 GW of solar, according to the grid operator.

“If these resources start coming online at a much faster pace than the historical trend, MISO may experience shifting risk profiles much earlier than current expectations,” the grid operator said.

MISO operates the grid and wholesale power markets across 15 midcontinent states and Manitoba, Canada.

Federal regulators should reject the North American Electric Reliability Corp.’s latest proposed cold weather reliability standards for power plants, according to the PJM Interconnection and other major grid operators.

“Settling for the standard that NERC has filed in this proceeding, with its glaring exceptions and vague requirements, will only result in reliability issues that the Commission will need to address later and at a greater cost to generator owners and the public,” the ISO/RTO Council said in a March 21 filing at the Federal Energy Regulatory Commission.

NERC’s mid-February proposal sets a “low winterization bar” and includes “inappropriate exceptions” that will hurt grid reliability, according to the council — which represents the Alberta Electric System Operator; the California Independent System Operator; the Electric Reliability Council of Texas; the Independent Electricity System Operator of Ontario; ISO New England; the Midcontinent Independent System Operator; the New York Independent System Operator; the PJM Interconnection; and the Southwest Power Pool.

NERC’s proposal comes as large numbers of power plants failed to run during winter storms Uri in 2021 and Elliott in 2022, in some cases leading to major power outages. FERC, which must approve NERC standards, directed the grid watchdog organization to bolster its standards in a February 2023 decision.

NERC struggled to gain approval for its proposal during its standards development process.

Among other things, the ISO/RTO Council objects to NERC’s proposal to allow power plant owners to declare a “Generator Cold Weather Constraint” that would excuse them from putting in place freeze protection measures if they cannot be implemented at a “reasonable cost consistent with good business practices, reliability, or safety.”

“Enforcing the standard when this exception is invoked effectively injects NERC and the Regional Entities into the process of judging the reasonableness of costs, cost estimates, and even the particular Generator Owner’s specific financial situation,” the council said.

Cost issues are important, but should be addressed by FERC and state regulators instead of by NERC, according to the council.

“Constraint declarations based on claims of unreasonable costs will prove to be difficult or impossible to audit effectively and consistently,” the ISO/RTO Council said.

FERC should give NERC 120 days to revise its proposal, according to the council.

The New England Power Generators Association doesn’t oppose NERC’s proposal, but warned FERC that ISO-NE’s tariff likely doesn’t allow generators to include the costs of meeting the standards in their energy market bids.

“Generator owners could be left with uncompensated costs for actions they took on a timely basis to comply with the standards,” NEPGA said. “Generator owners should not be left in this legal limbo.”

The trade group urged FERC to clarify how power plant owners can recover their compliance costs in wholesale power markets.

These days, after every extreme weather event, Republicans cry wolf about the dangers that renewable energy and clean energy policies pose to grid reliability. In one sense, pundits are right. The U.S. power grid is under enormous stress, and reliability challenges will continue to get worse unless policymakers intervene quickly and decisively. But they are wrong to blame renewables.

The real problem stems from the grid’s outdated and parochial governance system. Our electricity system is run by a dizzying array of players — many of whom are heavily influenced by incumbent fossil generators — who routinely ignore each other’s regulatory objectives and design energy market rules to protect their own financial interests. As we argue in a recently released white paper, reliability regulations should be designed, implemented, and enforced by regulators and market participants who represent all stakeholders — not just by the utilities who have the most to lose from a clean energy transition.

Clean energy critics largely ignore evidence about the underlying cause of reliability failures. No generation resource offers perfect reliability. While non-weatherized wind turbines sometimes freeze during cold snaps, wind and solar have also at times beaten expectations during extreme weather. Natural gas generation and, to a lesser degree, coal generation, have at times helped to keep the lights on but in other cases have failed to meet reliability commitments. This record suggests the need for a deeper and more nuanced conversation about both the real threats and solutions to grid reliability.

The grid faces two governance challenges. The first is that the current regulatory framework treats reliability and decarbonization as separate objectives. Different energy regulators — the Federal Energy Regulatory Commission, the North American Electric Reliability Corporation, state public utility commissions and regional grid operators, just to name a few — are charged with regulating some dimensions of grid reliability. These entities occasionally work together to design reliability rules. But just as often they operate within their own silos. So, when clean energy resources try to enter the market in response to clean energy subsidies, they often encounter technical and outdated reliability and market rules that impede their entry or operation and make the grid less reliable.   

The second problem is that entities charged with overseeing grid reliability are private organizations heavily influenced by incumbent utilities, many of whom stand to lose out from the clean energy transition. In theory, FERC should be working with other regulators to make sure that electricity market and planning rules harmonize with other regulatory objectives, such as reliability and clean energy policies. That would mean reforming resource adequacy markets to address the increasing need for flexible resources that can ramp up quickly when renewables are unavailable and redesigning transmission planning to encourage more high-voltage transmission lines that can bolster reliability through interregional transfers of energy.

In reality, though, FERC has outsourced market design decisions to for-profit and nonprofit entities.

In much of the country, resource adequacy markets and transmission planning are conducted by regional transmission organizations that are private, nonprofit, member-run institutions. Even though FERC has put in place guardrails to ensure independence, incumbent utilities have significant formal and informal sway in the decision-making processes of these organizations.  Thus, it is little surprise that regional rules often favor utilities’ financial interests.

Consider transmission planning. The best wind and solar resources are located far from population centers that consume large amounts of electricity. To bring these resources to market, the United States needs to double its transmission capacity. Interregional transmission capacity is also one of the best ways to ensure reliability in the face of increasing weather disasters. Nevertheless, the country has failed to build a robust, nationally interconnected transmission grid. For the last decade, the most lines that have been constructed are small, local lines that only address immediate reliability issues and benefit a single utility’s service area.

From a policy standpoint, this is simply irrational. But it is entirely consistent with our mismatched and siloed system of energy governance. When utilities build local lines, they don’t have to compete with utilities and merchant (competitive) transmission providers in other regions.  Small transmission projects are also preferable for vertically integrated utilities — utilities that own both generation and transmission assets — because local lines don’t expose their generation resources to competition from a larger swath of the market. But only utility shareholders win from this arrangement. The public at large and whole swaths of potential new competitors lose out.

In another example of private interests’ dominance in reliability governance, the same utilities that heavily influence regional transmission organizations have a strong voice on committees within NERC that propose reliability standards, ultimately to be approved by FERC. Like regional transmission organizations, NERC is a private nonprofit corporation, and its voting members tend to influence reliability standards in ways that perpetuate reliance on baseload fossil fuel resources that run all of the time.

These challenges may seem esoteric — and indeed, their process- and acronym-heavy nature discourages easy public engagement by design. But it is extremely important that energy regulators focus on technocratic reforms that will allow electricity markets to accommodate high penetrations of renewable energy and the flexible resources needed to make those renewables more reliable such as increased battery storage, demand response, and microgrids.

It is even more important that they first address the underlying governance problems that create unnecessary tensions between clean energy and reliability.

At minimum, there should be more public representation in the governance processes and boards of both NERC and regional transmission organizations. And FERC should more regularly bring together all of the entities responsible for grid reliability to break down current regulatory silos. More ambitiously, Congress should consider centering the responsibility for grid reliability within FERC, rather than continuing to rely on private-membership organizations beholden to incumbent utility and fossil fuel interests.

These governance reforms would set the stage for a more reliable electric grid that meets public objectives at the lowest cost.

Four regional transmission organizations serving more than 40% of the U.S. population on Feb. 21 published a suite of recommendations to improve gas-electric sector coordination, with the aim of boosting the reliability of both energy delivery systems.

The RTOs — Southwest Power Pool, Midcontinent Independent System Operator, PJM Interconnection and ISO New England — said reliability is “increasingly reliant on the inter-relationship between the electric markets and well-functioning gas markets as well as the availability of adequate natural gas infrastructure.” They sketched out 14 initiatives to bolster coordination between the sectors, including market improvements, enhancements to infrastructure operation and regulatory reforms.

Gas-electric coordination has been a growing concern since Winter Storm Uri in February 2021, when 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 leading to calls to address the issue.

In the years since Winter Storm Uri there have already been improvements to cross-sector coordination, the RTOs said — pointing to improved generator performance during a pair of winter storms last month — but some issues persist nationally and others can be addressed regionally or by states.

“These more recent experiences underscore the value of better aligning both the purchase of commodity and delivery of natural gas,” according to the position paper. “If anything, these most recent positive experiences underscore the value of focusing on additional enhancements, building on the work of each of the regions, to better align these two industries.”

Addressing the potential for co-dependent infrastructure will require pipeline and other gas supply stakeholders to work with RTOs and electric distribution utilities “to ensure that there are redundant sources of power available to critical facilities,” according to the paper.

And because the conversion of compression stations and processing facilities to utilize electric power was driven partly driven by federal environmental permitting requirements, “closer coordination with federal and state environmental regulators is needed to address the co-dependency vulnerabilities,” the RTOs said.

Among the other coordination approaches suggested, the RTOs said they want to improve fuel scheduling flexibility and to see the development of “packages of firm transportation and storage and other pipeline services” to better meet changing electric system demands.

“There are significant differences in the level of scheduling flexibility available to generators to respond to RTO dispatch instructions, particularly during constrained system conditions,” they said, and the degree of pipeline scheduling flexibility is “heavily influenced by the degree of storage available on the system and the extent to which the pipeline is fully subscribed during peak conditions.”

Improvements to weekend and holiday gas trading can also assist power generators, the RTOs said.

The Federal Energy Regulatory Commission and state regulators should consider investigating opportunities to “enable an end to multiday trading requirements of natural gas over weekends and holidays that significantly strain natural gas/power coordination and dispatch,” the paper said.

The Natural Gas Supply Association, which represents gas producers, said it was reviewing the RTOs’ suggestions and its members “are committed to gas-electric coordination and ensuring reliability in the energy system.”

“While the gas industry did not have specific input to this paper, they should generally be aware that these concerns have been raised in the past,” a spokesperson for the New England grid operator said in an email.

There are multiple efforts underway to improve coordination between the gas and electric sectors.

In November, the National Association of Regulatory Utility Commissioners launched a 15-month effort to improve coordination by bringing together a group of state regulators and stakeholders. And in December, FERC and the North American Electric Reliability Corp. recommended 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.

Rising electric vehicle charging loads could threaten bulk power system reliability, depending on how EVs are operated, the North American Electric Reliability Corp. concluded in a white paper published Feb. 8. There were 1.2 million EVs sold in the U.S. last year, and experts anticipate continued growth.

The solution is for EV and charging system manufacturers to boost their collaboration with electric utilities in order to establish performance criteria and standards for “grid-friendly EV charging methods,” NERC said.

The EV sector and utility companies must stand up “uniform programs across the country to enable fast, reliable installation of EV chargers,” Blink Charging Chief Technology Officer Harjinder Bhade said in an email. Those could include tariffs that align charging with clean energy generation and the potential for EVs to send power back to the grid, he said.

While the early load impacts of EV adoption have materialized at the local level — a few new vehicles can stress neighborhood feeders, say experts — NERC is concerned that as penetration levels rise, there may be reliability issues on the bulk power system as well.

EVs were 7.6% of new vehicle sales in 2023, and more than 8% of new sales in the fourth quarter. Though growth has slowed somewhat, Cox Automotive said it expects EV sales to surpass 10% of new sales in 2024.

“As the rapid electrification of the fleet continues, increased cross-sector awareness, collaboration, innovation and information sharing will be essential to closing these knowledge gaps, meeting future demand and ensuring grid reliability, resilience and security,” Soo Jin Kim, NERC’s vice president of engineering and standards, said in a statement.

EV charging systems can hurt voltage recovery if they do not detect grid faults fast enough, and the study found some chargers can be delayed in returning to normal consumption patterns following a grid disruption.

Transmission planners "will need to modify their planning criteria to indicate the types of charger performance criteria that are grid-friendly for their planning area,” NERC concluded. “Different parts of North America will likely have different criteria for this, and it may be possible to address these criteria with EV charging software updates.”

“Vehicle manufacturers, the electric industry, and policymakers must increase collaboration to close knowledge gaps and address reliability concerns and benefits,” the report recommended.

EV charging experts said they largely agreed with the report’s conclusions, and believe the next generation of technologies will make managing EV charging easier.

“Establishing uniform tariffs and programs that enable the growth of vehicle-to-everything technology beyond trial periods is a great way to move this shared work forward,” Blink Charging’s Bhade said. “This emerging tech allows for the transfer of electricity from EV batteries back onto the grid and ultimately to end users as they need it.”

The capability of an EV to send power back to the grid or a building — vehicle-to-everything — will allow EVs to become a source of electric power on the distribution system. NERC noted that its study did not evaluate the impacts from vehicle-to-grid capabilities, and solely considers impacts “in response to EVs when they are in charging mode.” However, it did recommend industry develop “more specific models to represent [vehicle-to-grid] behaviors that are widely implemented in software platforms.”

“The current models are not a good representation of both reduction of load and increase in generation and, as such, a generic aggregate model that can accomplish all aspects of the EV representation should be explored,” NERC said.

The utility industry “needs new solutions to manage EV demand,” Utilidata President and Chief Operating Officer Jess Melanson wrote in an email. “This requires utilities to be able to capture and understand granular real-time data where EVs are charging and their impact on the grid.” The company offers a platform known as Karman that uses local artificial intelligence-driven models to predict charging behavior.

Last year, Utilidata launched a research partnership with the University of Michigan Transportation Research Institute to study EV driving and charging behaviors and how they can impact the grid. “We plan to share early findings soon and engage with OEMs and local utilities to scale our solution, improving data sharing and collaboration at the grid edge,” Melanson said.

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.