Reliability

The Midcontinent Independent System Operator and the Tennessee Valley Authority will be able to sell “emergency energy” to each other under a first-ever agreement filed Oct. 24 at the Federal Energy Regulatory Commission.

The TVA is not able to supply emergency energy directly to MISO due to restrictions in the TVA Act that limit exports only to neighboring electric systems that the federal agency had exchange power arrangements with as of July 1957, according to MISO’s filing. 

As a result, under the agreement, Ameren and Entergy — MISO members that meet the requirements of the TVA Act — will be able to buy electricity from the TVA during energy emergencies on behalf of MISO.

“Due to the changing configuration of the grid and recent emergency events, like Winter Storm Elliott, MISO and TVA have become increasingly focused on the need for additional coordination and planning to better ensure reliability in an emergency,” MISO said. “To that end, each has identified the need to purchase Emergency Energy from the other to maintain the reliability of each individual transmission system and, more generally, the integrity of the Eastern Interconnection.”

During Winter Storm Elliott in December 2022, about 7,000 MW flowed from MISO into the TVA’s region, according to a presentation by FERC and the North American Electric Reliability Corp. The TVA instituted nearly eight hours of rolling blackouts totaling 3,000 MW at their peak during the winter storm.

Under the agreement, emergency energy can only be requested when an Energy Emergency Alert Level 2 or higher has been declared, MISO said. The proposed agreement is similar to ones MISO has with other balancing authorities, the grid operator said.

“Emergency Energy is typically only called on in the most extreme cases when reliability is threatened and there are few options remaining,” MISO said. “Both MISO and TVA anticipate that there may be situations in the future that will meet this criteria and having the ability to purchase Emergency Energy from each other may be the key to enhanced grid stability and avoiding load shed.”

MISO asked FERC to allow the agreement to take effect on Dec. 24.

The PJM Interconnection on Oct. 8 floated a plan to allow a limited number of generating projects that could address reliability needs to jump into an interconnection study cycle early next year.

The “reliability resource initiative” is a response to unprecedented demand growth forecasts coupled with a slow pace of bringing new power plants online and looming generator retirements, according to Donnie Bielak, PJM’s director for interconnection planning.

“We need to do something, and do something now,” Bielak said Oct. 8 during a PJM Planning Committee meeting.

The proposal comes as PJM is clearing out a backlog of interconnection requests that had been put on hold and are being reviewed under a three-track transition process to a fully reformed interconnection study framework. PJM plans to begin studying new interconnection requests by mid-2026 under its reformed process.

PJM is finishing generator interconnection agreements for its roughly 24.5-GW “fast track” interconnection review and is in the second-phase of its 26.2-GW Transition Cycle 1 process, according to Bielak. A window for eligible projects to enter the roughly 96.2-GW Transition Cycle 2 process closes on Dec. 17.

Projects in the three tracks are heavily tilted toward solar energy, Bielak noted. “If you look at that from an operational standpoint, you’re kind of putting all your eggs in one basket, and what we're looking to do is really try to diversify … kind of hedge our position in being able to get as much generation online as quickly as possible to meet the reliability demands that we have coming up,” he said.

If PJM’s reliability resource initiative advances and the Federal Energy Regulatory Commission approves it, the grid operator would allow eligible projects to enter into the TC2 study process early next year to be reviewed alongside all the other interconnection requests eligible for that track, according to Bielak. PJM doesn’t want to do anything that would delay the TC2 process, which could lead to delays in studying new interconnection applications in 2026, he said.

The proposal to let resources jump into the TC2 study process is “only going to be for a very, very select few [projects] most likely,” Bielak said. “We don't want to do that at the expense of all of the other projects, especially the ones that are currently eligible for TC2.”

In its “fuel agnostic” framework, PJM is considering an eligibility requirement that projects meet effective load carrying capability or unforced capacity thresholds, Bielak said during the presentation. The projects would also have to be online by specific dates.

PJM plans to present a straw proposal at an Oct. 18 Planning Committee meeting, followed by discussion at an Oct. 30 meeting of its Markets and Reliability Committee. In mid-December, PJM intends to file a proposal for FERC approval. The plan is backed by PJM leadership and the grid operator intends to make the filing at FERC unilaterally, without a stakeholder approval process, according to Bielak.

Some PJM stakeholders raised concerns about the proposal.

“It is unjust, unreasonable and highly discriminatory against the generators that are in the queue, specifically renewable generators” some of which have been in PJM’s queue for years, Omar Martino, Invenergy executive vice president of markets and regulatory, said at the meeting.

The proposal represents a “sweetheart deal” for some generators and goes against open access principals, Martino said. It could be heavily litigated at FERC and end up in court, according to Martino.

“I think this proposal, unless it really changes significantly, is going to create a lot more confusion, a lot more chaos, a lot more uncertainty for many years to come,” Martino said.

Capacity interconnection rights proposal advances

Meanwhile, a separate plan that could make it easier to bring new generation online advanced Oct. 8 when the Planning Committee approved a proposal that creates an expedited process for transferring capacity interconnection rights, or CIRs, from retiring generating resources to new replacement resources at the same point of interconnection.

If approved, the technology neutral CIR transfer process could be completed in nine months, according to a presentation on the proposal by a coalition that includes Elevate Renewable Energy.

“Expedited timing allows replacement resources to be included in reliability solutions, including but not limited to, as a resource option alternative to a [reliability must-run resource],” the presentation said.

The committee rejected alternate proposals offered by PJM and by Monitoring Analytics, the grid operator’s market monitor.

PJM’s process for deactivating resources to transfer their CIRs is tied to the grid operator’s interconnection queue study process, according to a summary of a stakeholder initiative on the issue. Because of the interconnection backlog, “resource owners are likely to experience a gap between the desired date of deactivation and the date a new resource could commence operation, resulting in cost and reliability concerns,” the summary said.

Almost two years after Winter Storm Elliott forced the largest recorded manual load shed in the history of the Eastern interconnection, the North American Electric Reliability Corp. says it “remains concerned about maintaining sufficient natural gas supplies to address extreme winter conditions.”

NERC’s statement on the “criticality of natural gas supply this winter” follows other warnings the reliability watchdog has issued regarding the need for greater coordination between the gas and electric sectors. Grid operators and gas producers this week said they are heeding those warnings and are working to weatherize their systems and improve market mechanisms to keep energy flowing.

Temperatures were up to 30 degrees below normal during the December 2022 storm, driving electricity demand higher and causing grid operators to declare emergency operations. Unplanned outages reached 90,500 MW, and transmission operators in the Southeast ordered firm load shedding that exceeded 5,400 MW, NERC, the Federal Energy Regulatory Commission and grid operators concluded in a joint assessment of the event published a year ago.

Elliott marked the fifth event in the last 13 years where gas supply disruptions played a role in cold weather-related generation outages that jeopardized bulk power system reliability, NERC said. And heading into this winter, some weather forecasts are calling for a colder-than-average December across much of the U.S. northern tier.

Elliott was “by no means an isolated example of the link between natural gas supply and electric reliability,” NERC said.

“As the electric system increasingly relies on natural gas, more gas infrastructure, including pipelines and storage, is needed to enhance deliverability,” NERC said. Supply disruption “was a central cause of generator failures that led to load shedding,” with cold temperatures resulting in declines in gas wellhead production and other system impacts.

The joint report on Winter Storm Elliott concluded that gas fuel supply issues accounted for 20% of unplanned generating unit outages, derates, and failures to start. Not all of those outages resulted from physical issues, however. The report also pointed to problems with scarcity pricing, mismatches between the timing of the gas and electricity markets, and pipeline scheduling constraints.

Since Elliott, gas operators have been working to weatherize pipelines, wellheads and other infrastructure. And grid operators say they are adjusting their planning processes and protecting their systems against extreme weather.

The Natural Gas Supply Association, representing gas producers and marketers, in a Sept. 4 fact sheet, said its members are taking a “multitude of proactive measures” to prepare for the winter, including “stringent self-inspections prior to anticipated weather conditions,” assisting customers in finding alternative market options, and mitigating weather exposure with “additional supplies and enhanced protections.”

“We operate winter continuity programs that help protect upstream facilities and field personnel during winter events, improving our ability to maintain operations during extreme conditions,” NGSA said.

Grid operators focus on weatherization, market mechanisms

The Midcontinent ISO “is currently conducting the annual winter readiness surveying cycle,” Brandon Morris, a spokesperson for the grid operator, said in an email. MISO’s territory covers 15 central U.S. states and the Canadian province of Manitoba.

“We are focused on sending the right market signals to highlight the value of resource availability and incentivize generation owners to have firm access to fuel, especially during tight operating conditions,” Morris said.

MISO faces a possible capacity shortfall in some regions beginning next summer, according to an annual report published in June.

The grid operator has recently implemented a “seasonal construct” for its annual planning resource auction to consider how much different resources bolster grid reliability during stressed periods, Morris said. “MISO will continue working with regulators, our member utilities, fellow grid operators and the natural gas industry to improve coordination with a focus on maintaining reliability,” he added.

New England uses natural gas to generate about half of the region’s electricity, “so we’re always focused on what’s happening on the gas system,” Matt Kakley, spokesperson for ISO New England, said in an email. “This is particularly true during the winter months, when supplies may be tighter due to heating needs.”

ISO New England, along with MISO, PJM Interconnection and the Southwest Power Pool, in February published a white paper on paths to improving the reliability of gas-electric coordination across their territories, including weatherization, permitting reforms and incentivizing firm gas transportation and storage for generators.

“There are significant differences in the level of scheduling flexibility available to generators to respond to [regional transmission organization] dispatch instructions, particularly during constrained system conditions,” the paper noted. The RTOs added that they “recognize that 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.”

The New England grid operator is conducting an analysis of the upcoming winter, “but [we] are not anticipating any levels of concern greater than recent years,” Kakley said. “We agree with NERC’s sentiment that close coordination between the gas and electric sectors is vital to reliable operations.”

The Electric Reliability Council of Texas is conducting weatherization inspections of generating and transmission facilities, “being more transparent in grid operations, and continuing ERCOT’s conservative approach to operations,” the grid operator said in a statement.

Since 2021, ERCOT has taken a “reliability-first approach to grid operations, bringing generating resources online early to mitigate sudden changes in generation or demand,” it said in a statement. “ERCOT will continue to use all operational tools available, including implementation of programs, as well as executing legislative reforms (like summer and winter weatherization inspections).”

Every PJM capacity auction tells a story. PJM’s capacity auctions are intentionally designed to provide a glimpse into the future and allow market participants to anticipate tomorrow’s challenges so market-based solutions can be crafted today.

Between May of 2018 and June of 2024, capacity markets were clearing at prices that told the market that supply was robust, demand was basically flat, new resources were largely not needed and some older, lesser efficient resources could retire. With these assumptions, lower prices for consumers make sense.

Of course, we know that is not the reality of today as demand expansion and supply contraction are creating a significant tightening of available generation resources everywhere, including in PJM’s wholesale markets. The July 2024 capacity auction for the 2025/26 delivery was the first auction in over a half decade that sent a message to suppliers that we need you to stay, and we need you to bring some more friends.

Higher prices make for challenging discussions, but they should not be a signal for panic. There will be hot takes a plenty, interest-group-motivated spin and comparisons to other situations that are completely irrelevant. Fingers will be pointed in every direction as people look to blame others for price increases. Policymakers would be wise to be a calming influence and not add fuel to any of these unnecessary fires.

For policymakers, the key takeaway is that the PJM market is catching up to most of the rest of the country in feeling the pressure to manage the supply crunch. PJM, however, will distinguish itself from others by managing itself through this pinch with market-based solutions and not knee-jerk, over-reactionary regulatory or legislative mandates that have proven more costly and less effective. As the PJM Independent Market Monitor recently advised, “PJM and its market participants will need to continue to resist the temptation to turn to regulatory solutions based on cost of service rather than markets.”

While the road ahead could be a bumpy ride as demand increases, supply shrinks and upward pressure on price is persistent, here are five relatively straight-forward actions that PJM policymakers can and should do to ensure that consumers continue to experience the reliability and market efficiency benefits that have been traditionally enjoyed in the PJM region:

1. Keep the faith. Competitive markets and their efficiencies have saved consumers billions of dollars. Pressure to abandon the market by pursuing out of market solutions will likely come as opportunistic companies put their bottom lines over the health of an efficient market. Policymakers need to end those discussions quickly. Now, more than ever, during this period of transitioning supply and load, stable, competitive markets are essential to delivering reliability at reasonable costs to the 65 million customers in PJM who depend on these markets to keep the lights on at home and power their businesses. Markets work best when they are not interfered with — let’s not go down that road.
    
2. Stop the bleeding. The cheapest and easiest way to maintain reliability is to keep existing assets on the system. Assets that are capable of still running should not be forced off the system by arbitrary state or federal policies. Moreover, generation owners can take action to keep assets in service — for instance, through coal-to-gas switching — when capacity prices support those actions. Illinois, with the stroke of the pen, could keep (rather than force the shutdown of) 6,000 very needed megawatts on the system — and it should do so. Other state and federal policies also are hastening the premature retirement of viable assets. Economics should determine plant closures — not regulatory or legislative fiat.
    
3. Get a grip on demand. PJM is facing demand growth like it has never seen. There are a lot of incredible numbers being carelessly tossed around that are being used by some to advance self-serving policy solutions. This needs to stop. There is little doubt that demand is going up. There is a lot of doubt about the scale and pace of that growth. Consumers and regulators deserve an honest assessment about how much of the growth is real and how much it is going to cost them.
    
4. Be real about reliability. PJM has noted that 38,000 MW of new capacity have signed interconnection agreements and higher capacity prices can be an important enabler to bring these resources to energy production. However, the vast majority of that 38,000 MW is renewable and not all resources are created equally when it comes to reliability. Wind and solar make for great energy resources when the wind is blowing and the sun is shining, however, despite the name of the TV show, it is not always sunny in Philadelphia. FERC and PJM should prioritize projects in the queue that will have greater impacts on the reliability equation. State policymakers should be pushing them to do so.
    
5. Be engaged. Interstate wholesale markets can be complicated, and it is very easy for incomplete understandings to lead to policies that raise prices and decrease reliability. Policymakers need to better understand wholesale markets. PJM always welcomes policymaker visitors — go see them and understand and appreciate what is being managed in PJM. Most importantly, do not pursue policies in the energy space without a complete and thorough understanding of what impact those policies will have on reliability, emissions and price in the wholesale power market.

There can be little doubt that things are changing quite quickly in PJM. The grid is facing unprecedented challenges on both the supply and demand side. Now is exactly the right time for thoughtful conversations that lead to policies rooted in the competitive market structure that have served the PJM region so well. Now is not the time to panic and pursue policies that will further undermine the markets and compound some of the problems that have brought us to the current situation.

Thoughtful leadership is not always easy, but at the end of the day, affordable and available electricity should take precedence over responding to complex problems with hasty solutions. Markets have proven their value and will continue to do so, provided the market is properly designed and well-functioning — and that is a goal to which all policymakers should aspire.

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.

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.

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.

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.