Much of the U.S. bulk power system faces an elevated risk of blackouts in extreme winter weather, the North American Electric Reliability Corp. warned in its 2023–2024 Winter Reliability Assessment, published Nov. 8. 

A key issue is the availability of natural gas supplies for generation and the operation of gas-fired power plants, NERC said. During extreme weather, generators can face operating difficulties in frigid temperatures, supplies may be diverted for home heating, and gas production may slow due to wellhead and pipeline issues.

NERC’s recommendations for the cold months ahead include for reliability coordinators to monitor fuel adequacy, generators to weatherize power plants and for balancing authorities to “pay particular attention to the risk of demand underestimation ahead of extreme winter conditions.”

Most of the North American electric grid can manage through normal peak winter conditions, but in extreme weather NERC said there are heightened risks extending across much of the eastern two-thirds of the continent.

“As observed in recent winter reliability events, over 20% of generating capacity has been forced off-line when freezing temperatures extend over parts of North America that are not typically exposed to such conditions,” the report warns. “When electricity supplies become constrained, [bulk power system] operators can face a simultaneous sharp increase in demand.”

The Federal Energy Regulatory Commission in February approved new cold weather reliability standards for U.S. generators. NERC proposed the standards in response to Winter Storm Uri in 2021, when Texas faced widespread blackouts and almost 250 people died.

“Additional cold weather standards recently adopted by NERC’s Board have been filed for FERC approval,” John Moura, NERC’s director of reliability assessments and performance analysis, said in a statement. “This is a positive development in ensuring industry is prepared for extreme cold weather.”

Other issues NERC identified include the growing complexity of forecasting winter load and the curtailment of electricity transfers between reliability coordinators and balancing authorities.

“While the curtailments alleviate an issue in one part of the system, curtailments can contribute to supply shortages or affect local transmission system operations in another area,” NERC said.

NERC released its report ahead of a FERC technical conference Nov. 9, focused on reliability. And on Nov. 7 FERC and NERC jointly published a final report on 2022’s Winter Storm Elliott, calling for “robust monitoring” of how the new cold weather reliability standards are implemented.

Todd Snitchler, president and CEO of the Electric Power Supply Association, said generators take those findings seriously, but added the Winter Storm Elliott report also concluded “no market model, region of the country, or fuel type is immune to the challenges experienced” during the event.

“A well-designed competitive power market, however, is the best foundation to serve power needs reliably and efficiently. Natural gas generation remains and will remain a vital component of a reliable system,” Snitchler said.

In the southern areas of the Midcontinent ISO market, NERC’s winter reliability report warned extreme cold-weather “can cause high generator outages from inadequate weatherization or insufficient natural gas fuel supplies.” In New England, gas transportation infrastructure could be constrained if fuel is diverted for consumer heating needs.

Across the PJM Interconnection territory and in some portions of the U.S. Southeast, severe cold can cause a spike in forced outages. “Forecasted peak demand has risen while resources have changed little in these areas since Winter Storm Elliot caused energy emergencies across the area in 2022,” NERC said. “Generators are vulnerable to derates and outages in extreme conditions.” 

This winter’s anticipated reserve margin in the Southwest Power Pool is 38.8%, “more than 30 percentage points lower than last winter; this is driven by higher forecasted peak demand and less resource capacity,” NERC said.

The Electric Reliability Council of Texas, which manages most of the state’s grid, could see “a significant number” of forced outages in extreme cold temperatures, NERC said. Load growth is also driving a risk of reserve shortages, according to the report, though ERCOT has issued a request for proposals to increase operating reserves by 3,000 MW.

Saskatchewan Power, in Canada, could face insufficient operating reserves in normal peak conditions due to falling reserve margins, planned generator maintenance and the retirement of a 95 MW gas-fired unit.

‘Massive grid disruption is inevitable’

It is only a matter of time before a widespread grid disruption occurs, according to Mark Spurr, legislative director at the International District Energy Association and president of engineering and consulting firm FVB Energy. 

Spurr pointed to a confluence of three trends: an increase in severe weather events due to climate change, rising peak electricity demand and a growing dependence on natural gas. “A massive grid disruption is inevitable,” he said, because those factors are “getting worse, not better.”

“We’re thrilled to see NERC acknowledge what everyone already knows: failure of fossil-fueled power plants, especially gas-fired ones, during the winter is the greatest threat to grid reliability today,” said Tom Rutigliano, senior advocate for the Sustainable FERC Project at the Natural Resources Defense Council.

But Rutigliano added that NERC’s focus on fuel supply risk “hides that the root cause is simply poor maintenance by power plant owners and the gas industry.”

“Grid operators must plan for the poor reliability gas plants have demonstrated time and again and hold non-performing plants accountable,” Rutigliano said. “Congress should follow FERC's recommendation to set reliability standards for the gas industry.”

The National Rural Electric Cooperative Association warned the Environmental Protection Agency’s proposed limits on greenhouse gas emissions from coal-, gas- and oil-fired power plants could worsen the grid’s precarious situation.

NERC’s reliability assessment “shows that our nation faces looming grid reliability challenges while demand for electricity continues to soar,” NRECA CEO Jim Matheson said in a statement. EPA’s “unlawful, unrealistic and unachievable proposal will result in less electricity, more power outages and higher costs for American families and businesses.”

The U.S. Department of Energy on Wednesday announced nearly $3.5 billion in awards under its Grid Resilience and Innovation Partnerships program, known as GRIP, to support 58 projects in 44 states. When matched with private and local investment, officials said the awards will support a total of $8 billion to expand and strengthen the nation’s electric system.

It is “the largest ever investment in America's grid,” said Energy Secretary Jennifer Granholm. Billions more in future GRIP funding is planned.

The smallest of yesterday’s awards include smart grid grants of around $1 million to individual cities, and the largest is $464 million to support the construction of five transmission projects across seven Midwest states. 

More than half of U.S. transmission lines and power transformers were installed before 1970 and the outdated grid is vulnerable to the increasing impacts of the climate crisis, said DOE officials.

The bipartisan infrastructure law made $10.5 billion available to DOE’s Grid Deployment Office for GRIP. The program aims to help mitigate wildfire and other climate change risks, unlock stranded renewables projects, and boost the flexibility, efficiency and reliability of the nation’s aging electric power system.

“This round alone is the largest ever investment in America's grid,” Granholm said. “It's going to enable more than 35 GW of renewable energy on the grid and it will also boost the current renewable capacity as well by more than 10% within this decade.”

The program represents a new approach to grid upgrades, a senior DOE official told reporters.  All of the awards have stipulations in place between community groups and developers, known as Community Benefit Agreements, agreeing to local benefits in exchange for project support. 

“Historically, grid upgrades have not necessarily involved a ton of community engagement and we're trying to change that paradigm through this process,” the official said. “By asking people to engage from the Justice40 perspective, and engage with disadvantaged communities, [projects] are much more likely to be built.”

President Biden’s Justice40 initiative calls for 40% of the benefits of certain federal investments to flow to disadvantaged communities that are marginalized, underserved and overburdened by pollution.

While energy siting reform remains a work in progress, “the funding itself makes these projects almost irresistible,” Granholm said. “We've gotten huge support from states, from localities where the proposed projects will be.”

DOE received 700 initial concept papers for GRIP projects, and then encouraged 300 different organizations to make full applications. The awards announced Wednesday are not final and still require applicants to undergo a negotiation process with the agency.

The largest award will support the Joint Targeted Interconnection Queue portfolio, known as JTIQ, involving construction of five transmission projects across seven Midwest states. The projects are in Iowa, Kansas, North Dakota, Nebraska, Minnesota, Missouri and South Dakota, and will support resource adequacy in the Southwest Power Pool and Midcontinent Independent System Operator territories.

“The costs and uncertainty of the system upgrades have become one of the biggest bottlenecks for developing new renewable energy projects in the upper Midwest,” DOE said in a description of the project. “The JTIQ Portfolio project overcomes many of these challenges and provides numerous interregional benefits, including scalable transmission solutions, new renewable generation, lower energy costs, enhanced community engagement, and workforce development.”

Xcel Energy is developing two of the JTIQ projects and said the GRIP award would help advance that work.

“Unprecedented growth of utility-scale wind and solar projects in the central U.S. has created a bottleneck in the process of interconnecting new generation,” the utility said in a statement. “Right now, the transmission system along the locations where MISO and SPP meet is at capacity, and upgrades are too costly for individual energy developers.”

The GRIP award “is a critical step” in DOE’s efforts to expand the nation’s transmission capacity, increase connectivity between regions and add more clean energy, John Moore, director of the Sustainable FERC Project at the Natural Resources Defense Council, said in a statement.

“A larger grid is a resilient grid, and the funding for planning and coordination from today's grants will go a long way toward accelerating these efforts,” Moore said.

Entergy New Orleans celebrated its award of $55 million to fund the utility's Line Hardening and Battery Microgrid project, which it said will enhance the local grid’s resilience against storms.

“This is a huge win for our customers, for our community, and for the City of New Orleans,” Deanna Rodriguez, president and CEO of Entergy New Orleans, said in a statement. “Federal grant funds at this scale will enable us to make our grid stronger ... These funds will help offset the cost burden on our customers.”

The National Rural Electric Cooperative Association and a consortium of 39 cooperatives were tapped to receive nearly $100 million for wildfire mitigation.

“This infrastructure funding is an important step as electric co-ops work to harden systems against wildfires and enhance the reliability of the grid. These projects hold tremendous potential for local communities,” said NRECA CEO Jim Matheson. 

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

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

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

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

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

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

Pratt provided one such definition.

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

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

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

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

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

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

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

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

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

How many are there?

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

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

But at least one independent assessment exists.

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

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

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

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

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

What does it take to make more of them?

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

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

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

What are the benefits?

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

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

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

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

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

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

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

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

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

How FERC order 2222 will help

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

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

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

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

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

Visuals Editor Shaun Lucas contributed to this story. 

Earlier this year, the Environmental Protection Agency announced new proposed vehicle emissions standards that, if implemented, are projected to result in electric vehicles making up 67% of new light-duty vehicle sales by 2032. Widely considered the EPA’s toughest emissions requirements yet, the news prompted a range of reactions and questions, with one question standing out to me: Is our electric grid ready to support mainstream EV adoption?

It’s a fair ask, especially given that the frequency of major power outages in the U.S. increased by 67% from 2000 to 2020 and is expected to continue to rise. There’s no doubt the electric grid needs upgrades – not just to put more EVs on our roadways, but generally to meet the evolving electricity needs of our growing population and support the larger energy transition. But my response to “Is the grid ready?” flips the question on its head by asking to what extent EVs can and will support the electric grid. The answer? It depends on how much and how quickly we’re willing to modernize our country’s energy infrastructure.

The U.S. has already passed the tipping point for mass EV adoption, proving that the future of transportation is electric. Creating an energy ecosystem that maximizes EVs’ potential to strengthen the grid will require hard work, planning and collaboration among stakeholders — especially given the added challenges caused by extreme weather and aging infrastructure. But it’s the only viable path forward. We can’t let fear of a challenge discourage progress.

Grid modernization

Where to start? The first step is to modernize the grid. According to the White House, over 70% of the U.S. electricity grid is more than 25 years old. And while 25 might not sound old, we must consider how much our energy ecosystem has changed in the past 25 years.

The onset of the digital age and society’s reliance on technology and constant connectivity has increased our overall electricity consumption. Just last year, the total U.S. electricity consumption was the highest ever recorded and 14 times greater than our electricity use in 1950. On top of that, the U.S. population is on a rapid growth trajectory, growing nearly 18% from 2000 to 2020, with that number only expected to rise. 

And while day-to-day demand has evolved significantly, our energy infrastructure hasn’t. Before we can achieve full electric mobility, we must create an environment where EVs can thrive by making long-overdue infrastructure upgrades, such as investing in the build-out of our energy transmission system, building digital smart grids, and deploying flexible technologies to better utilize existing power networks by optimizing grid supply and demand. 

Smart charging flexibility to increase grid resiliency

It's important to mention that while grid improvements are underway, we can maintain the current level of EV momentum without increasing the risk of blackouts by leveraging managed or smart EV charging. As the name suggests, smart charging is managed in a way that can effectively improve grid flexibility and decrease the risk of outages.

In instances where there is typically a longer dwell time for EV charging, like at homes, multifamily communities and workplaces, smart charging can provide grid flexibility by optimizing charge times to align with grid conditions and prioritize the use of renewable energy. This means charging automatically takes place during off-peak times when energy demand is lowest and prices are cheapest, offering much-needed relief for the electric grid and EV owners’ wallets alike.

To further promote off-peak charging, many utilities nationwide have introduced opt-in programs with lower energy rates for EV owners. This pricing structure, commonly referred to as time-of-use, differs from conventional flat-rate models by incentivizing customers to consume energy when demand and costs are lowest, which for EV owners, means more opportunities to save. 

Maximizing the power of energy storage

In use cases where dwell time is shorter, like at a public fast-charging station along a highway corridor, the amount of grid flexibility smart charging can provide is limited. That’s where energy storage comes into play.

When integrated with energy storage capabilities, EV fast chargers can offer grid flexibility while continuing to charge during peak demand periods using stored energy. Take solar-plus-storage, for example. By using solar to power a battery-integrated EV fast charger, excess solar energy can be stored for future use to avoid relying on the grid when the sun isn’t shining or demand is high. This ability to combine smart charging with energy storage technologies and offer grid flexibility is key to maintaining EV momentum while we’re in the process of upgrading the grid.

Looking ahead, after we’ve modernized our energy infrastructure we can start looking to EVs to supplement the grid. Coming from an energy storage background, I often refer to EVs as “batteries on wheels.” This is because EV batteries can store excess electricity that can be tapped into when energy demand is high and, in some cases, can even supply stored electricity back to the grid when needed, a process known as vehicle-to-grid, or V2G, charging. However, while the outlook for V2G is exciting, to fully maximize its potential, we must first upgrade our energy infrastructure to accommodate the bidirectional flow of electricity between the grid and EVs.

Collaboration is key

While the pathway to realizing the potential of EVs is clear, none of this is possible without collaboration. Key stakeholders, such as utilities, regulators, automakers, charging network operators and governments, must collaboratively develop standards and implement policies that incentivize flexible smart charging.

By leveraging the energy storage capabilities of EV batteries and upgrading our energy infrastructure, EVs can and will play a vital role in strengthening our energy ecosystem. With continued collaboration, we can build a flexible grid that maximizes the power of EVs and supports the clean energy transition, propelling us toward a more resilient future.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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