The Gemini facility scheduled to begin operation this year near Las Vegas, with a planned solar capacity of nearly 700 megawatts and battery storage capacity of up to 380 megawatts, is expected to become the nation’s largest solar project. (Image: Primergy Solar construction simulation presentation of Gemini project)

Policy, politics and progressive commentary

With some parts of the country already facing heat waves, the organization in charge of setting reliability standards for the American electric grid is warning that a scorching summer could lead to a shortage of power generation in some regions.

The warning comes as the National Oceanic and Atmospheric Administration says there’s a 99% chance that 2024 will rank among the five warmest years on record and 55% chance it will be the hottest on record.

Overall, though, the analysis by the North American Electric Reliability Corporation painted a rosier picture than last year’s report, in part because of a surge in solar power development.

The nation has enough energy supply to handle normal peak demand, called “load” in the electric industry, largely because of 25 gigawatts of new solar power capacity — at full capacity that’s the rough equivalent maximum output of 25 large fossil or nuclear power plants. (The number of homes that can be powered from one gigawatt of solar can vary widely across the country). But the new panels have helped move some areas from what NERC calls “elevated risk” of power shortfalls in last year’s analysis  to “normal risk” this year.

“Resource additions are providing needed capacity to keep up with rising peak demand in most areas,” Mark Olson, the organization’s manager of reliability assessments, told the Federal Energy Regulatory Commission Thursday. New power transfer agreements, growth in demand response programs, which incentivize customers to reduce power usage during times of grid stress, and delayed power plant retirements “are also contributing to an overall improved resource outlook for the upcoming summer,” NERC says.

A solar surge

A separate FERC staff presentation said solar will make up 10% of overall national electric generation capacity by the end of this summer, with natural gas providing 42%, coal providing 14% and wind power at 13%.

Solar power is growing fast across the country, with the U.S. hitting five million total solar installations (most of them residential), per the Solar Energy Industries Association. Reaching that milestone took 50 years, but the industry group projects that hitting 10 million solar installations will only take six years. Solar power for the first time accounted for more than half of new electric generation capacity added in 2023, the group noted.

The U.S. Energy Information Administration expects “a record addition” of new utility-scale solar power this year, with about 36.4 gigawatts projected to be installed. More than half of that new capacity is planned for Texas, California and Florida.The Gemini Solar facility, scheduled to begin operation this year about 30 miles northwest of Las Vegas, with a planned solar capacity of nearly 700 megawatts and battery storage capacity of up to 380 megawatts, is expected to become the nation’s largest solar project.

Battery storage is also growing rapidly, with more than 14 gigawatts expected to be added this year, according to the EIA. Batteries complement solar generation well, since solar’s peak production doesn’t generally line up with peak demand on the grid, which happens later in the day. Batteries allow excess solar power to be banked for when it’s needed.

But a changing power mix also comes with new challenges and risks, NERC warned.

In his presentation to FERC, Olson said that while the overall summer electric reliability outlook has improved, some regions are seeing what he described as growing risks during extreme weather.

“Shortages could occur when demand is high and solar, wind or hydro output are low,” he said.

Those regions include parts of the Midwest and South in the grid area managed by the Midcontinent Independent System Operator, New England, Texas, much of the Southwest and California. Grid operators, though, are becoming increasingly adept at planning and running electric grids with large amounts of intermittent resources.

“It’s refreshing to finally get the recognition that renewables can help with reliability,” said Simon Mahan, executive director of the Southern Renewable Energy Association.

Shifting seasons and climate change

While most of the country has historically been “summer-peaking,” meaning regions hit their highest demand for electricity during the summer months, some areas are increasingly seeing demand spike in winter, a trend that is expected to continue as result of heating electrification, other decarbonization policies and more extreme, protracted cold weather events. Indeed, the majority of recent electric grid failures have been during severe winter weather, such as Winter Storm Elliott in 2022, which caused blackouts in several southern states and Uri in 2021, which caused a catastrophic collapse of the Texas electric grid that caused an estimated 246 deaths.

But summer heat still poses risks, NERC says, contributing to both high demand and power plant outages, such as at natural gas power plants.

“Last summer brought record temperatures, extended heat waves and wildfires to large parts of North America,” the organization said. And though energy emergency alerts were few and no electricity supply interruptions happened as a result of insufficient power resources, grid operators “faced significant challenges and drew upon procedures and protocols to obtain all available resources, manage system demand and ensure that energy is delivered over the transmission network to meet the system demand.” Utilities and state and local officials in many areas also “used mechanisms and public appeals to lower customer demand during periods of strained supplies,” NERC added.

Christy Walsh, a senior attorney at the Natural Resources Defense Council’s Sustainable FERC Project, said the reliability reports show how climate change is central to the pressures facing the electric grid.

“And it needs to be at the center of our solutions too,” she said in a statement to States Newsroom. “Earlier and more intense hurricanes brought on by increasing sea temperatures are a new and noteworthy concern, and this underscores the need for more large-scale transmission and connections between regions. Most of the new additions were wind, solar and storage, and last summer especially we saw just how crucial these resources can be during extreme heat events. We need to make sure we have a grid that can withstand the weather and move resources around during times of stress.”

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FERC's chairman said construction of the high voltage transmission lines that help get power to where it’s needed has slumped to a record low. (Photo: Getty Images)

Policy, politics and progressive commentary

A divided Federal Energy Regulatory Commission this week issued a long-awaited overhaul of how regional electric transmission lines are planned and paid for, a move cheered by clean power groups but blasted by a conservative commissioner who said it was driven by “special interests” and exceeds the commission’s authority.

The commission’s final rule on transmission planning and cost allocation, intended to prod utilities and grid operators across the country into more forward-looking, comprehensive and cost-effective planning of large electric transmission lines and better account for the broad benefits those wires provide, was nearly three years in the making. It passed on a 2-1 vote, with the commission’s two Democratic appointees voting yes and the lone Republican opposed.

FERC Chairman Willie Phillips said an aging grid, increasing severe weather, demand growth from new manufacturing, data centers and increasing electrification as well as a changing generation mix all threaten reliability at a time when construction of the high voltage transmission lines that help get power to where it’s needed has slumped to a record low.

“This rule cannot come fast enough. There is an urgent need to act to ensure the reliability and the affordability of our grid,” Phillips said. “We simply will not be able to address these converging challenges and continue to supply the reliable, abundant and affordable power the American people depend on without taking a clear-eyed, long term, forward-looking approach to transmission planning.”

But Commissioner Mark Christie, a conservative former Virginia utility commissioner, vehemently dissented to the rule, calling it “a pretext to enact a sweeping policy agenda that Congress never passed” and one that will “facilitate a massive transfer of wealth from consumers to for-profit special interests.”

Christie has long opposed transmission cost allocation schemes that he claimed would force customers in some states to pay for the pro-renewable policies of their neighbors. “I was perfectly prepared to vote for this final rule if it were a bipartisan compromise, if it preserved the state role that everyone sitting up here voted for two years ago,” he said.

The genie and the bottle

The sprawling rule requires transmission operators to conduct transmission planning at least every five years, looking out along a 20-year horizon using “best available data to develop well-informed projections” of needs, according to a staff presentation. To identify those transmission needs, providers need to consider state laws and regulations, utility planning documents, fuel cost trends, power plant retirements, requests from developers looking to connect to the grid as well as “policy goals and corporate commitments.” They also must consider “grid-enhancing technologies,” a suite of potentially cost-saving tools common in other countries that have been slow to take root in the U.S., despite years of prodding from advocates, as well as identifying opportunities to upgrade existing lines, called “right-sizing.”

Transmission providers, including utilities and the organizations that manage the grid in much of the country, are also required to use a list of seven economic and reliability benefits as they evaluate and select long-term regional transmission projects as well as establish an evaluation process with transparent selection criteria that are not “unduly discriminatory or preferential, aim to ensure that more efficient or cost-effective long-term regional transmission facilities are selected and seek to maximize benefits accounting for costs over time without over-building transmission facilities.”

Christie criticized those “mandated inputs” and said states have no ability to consent to those criteria.

A major big problem FERC is trying to fix is that even as construction of large transmission projects has nearly ground to a halt, utilities in many parts of the countries are on a building spree of smaller — potentially duplicative and inefficient — projects that are easier to get approved and paid for, increasing customer bills.

“The absence of this type of regional transmission planning is resulting in piecemeal transmission expansion that addresses relatively near-term transmission needs,” the staff presentation reads. “The status quo approach results in transmission providers investing in relatively inefficient or less cost-effective transmission infrastructure, with the costs ultimately recovered through commission-jurisdictional rates. This dynamic results in, among other things, transmission customers paying more than is necessary or appropriate to meet their transmission needs, and customers missing out on benefits that outweigh their costs, which results in less efficient or cost-effective transmission investments.”

For example, proponents of the new rule point to hundreds of millions of dollars in transmission costs that will result from the closure of a Maryland power plant in the region overseen by PJM Interconnection, the nation’s largest grid operator, as an example of poor planning.

“It is hard to imagine the region could not have found a more cost- effective solution had it begun planning for that retirement along with other anticipated shifts further ahead of time,” said Democratic Commissioner Allison Clements, who took Christie to task over his dissent. She said he was pushing the commission to take a “fraught voyage” to decide which public policies are appropriate for creating transmission demands.

“All transmission needs are inherently influenced by state policies of all stripes,” she said. “The truth is that enormous sums of money are going to be spent on transmission investment regardless of whether or not it’s done within the framework of this new rule.”

She argued that the new rule will protect customers from the pricey, fits-and-starts transmission buildout happening in much of the nation now.

“Not everything is about politics,” she said. “It is not the commission’s job to try and force the genie that is the energy transition back in the bottle. It is our legal responsibility to protect consumers in light of whatever is going on in the world around us.”

Neil Chatterjee, a Republican former FERC chairman, posted on X that he would have voted for the rule if he was still on the commission.

“Today’s @ferc rule was voted out 2-1 but that does NOT mean it’s a partisan rule making,” he wrote. “Had I authored this rule as chair would it have looked exactly like this? Of course not. But it would have been in the range. Regulatory rule making is hard.”

‘Benefit of having a big grid’ 

Competitive transmission providers and clean energy groups were celebrating Monday. Organizations ranging from the American Council on Renewable Energy and the National Audubon Society to the Conservative Energy Network and Americans for a Clean Energy Grid issued statements applauding the order.

Some renewable power organizations had privately wondered whether a drive for a unanimous vote might produce a more watered-down rule to get Christie onboard. That might have left states with big renewable power goals paying for all the transmission costs necessary to accommodate them, as New Jersey is doing for its planned offshore wind buildout, even though that power generation could mean cheaper, cleaner electricity for its neighbors, also, along with other benefits.

The U.S. Department of Energy has found a “pressing need” for new transmission infrastructure across the country to alleviate congestion and improve reliability. Grid congestion costs electric customers billions of dollars a year, according to some reports. And because of the more diffuse nature of renewable power, getting it from where it’s produced to where it’s needed, as in the vast amount of wind power in the Great Plains, can require large, multi-state transmission lines.

“Families and businesses are paying the price for utilities’ and grid operators’ failure to address our critical electricity infrastructure needs,” said Heather O’Neill, president and CEO at national clean power business association Advanced Energy United. “Building more multi-state transmission lines unclogs the traffic jams on America’s electricity superhighways and unlocks our ability to keep up with our growing energy needs.”

Justin Vickers, a senior attorney for the Sierra Club, said the rule appears to be firmly within FERC’s jurisdiction, despite Christie’s concerns to the contrary.

“I think the commission is on very strong footing here,” he said. “This is a way of maximizing the benefits of living in a big country. We can send power around the country. It increases reliability and it lowers price. That’s the benefit of having a big grid. .. Let’s take advantage of it.”

The Edison Electric Institute, which represents investor-owned utilities, said it was “disappointed” that FERC declined to include a “right of first refusal” policy for some transmission projects, which would have given their members first crack at some of the lines. The organization also said the rule lacked “regional flexibilities for evaluating project benefits.”

“A one-size-fits-all approach does not work, as different regions have different needs and different states have different policies,” said Phil Moeller, an executive vice president at the institute.

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Judy Chang, David Rosner and Lindsay See, nominees to serve on the Federal Energy Regulatory Commission, are sworn in Thursday at the Senate Energy and Natural Resources Committee. (Senate Energy and Natural Resources Committee livestream)

Policy, politics and progressive commentary

President Joe Biden’s three nominees to the Federal Energy Regulatory Commission faced questions from a U.S. Senate committee Thursday, with senators probing their views on fossil fuels and climate policy, the reliability of the nation’s electric grid and gas delivery system and how to handle the pressing need for new electric transmission lines, among other topics.

One major clean energy industry group, wary of a political fight that could leave the crucial energy regulator without a quorum during a major transition of the electric grid, called on the Senate to confirm the nominees swiftly.

Sen. Joe Manchin, a West Virginia Democrat and the powerful chair of the Senate Energy and Natural Resources Committee who has clashed with the Biden administration over climate and energy policy, called the work of the commission “enormously important” to the nation during the hearing.

“The commission’s job is to ensure the orderly development of plentiful supplies of electricity, natural gas at reasonable prices,” Manchin said. “It enables us to keep the lights on, protects the American people from excessive gas and electric rates and it protects the public interest. The job calls for people who can fairly assess the needs and concerns of all interests affected by our energy policies and apply the law.”

Manchin has taken on FERC head-on in the past, refusing to hold a confirmation hearing for former FERC Chair Richard Glick, a Democrat who had been nominated for a second term by Biden. Glick had spearheaded efforts to more thoroughly vet the need for natural gas pipelines and their environmental effects, angering Manchin.

By law, FERC has five members, with no more than three from the same political party. They are appointed by the president with the “advice and consent of the Senate” and serve five-year staggered terms. Biden is attempting to fill vacancies left by Glick, who departed in 2023, GOP commissioner James Danly, whose term expired last year, and Democrat Allison Clements, whose term expires this summer.  If no new appointments are confirmed before Clements leaves, the commission would be reduced to two members.

The nominees

At least two of Biden’s nominees could be seen as an olive branch to Manchin. One is David Rosner, a Democrat and FERC energy industry analyst who was detailed to Manchin’s committee and was recommended for the commission seat by the senator last year, Politico’s E&E News reported. Rosner was previously a senior policy advisor at the U.S. Department of Energy and an associate director at the Bipartisan Policy Center’s energy project.

The other is West Virginia Solicitor General Lindsay See, a Republican who led the state’s successful legal fight against the Environmental Protection Agency’s proposal to regulate greenhouse gas emissions from power plants that wound up before the U.S. Supreme Court. The third nominee, Judy Chang, a Democrat, is an energy economics and policy expert and adjunct lecturer and senior fellow at Harvard’s Kennedy School. She is the former undersecretary of energy and climate solutions for the Commonwealth of Massachusetts.

In a hearing that featured few fireworks, Chang faced the toughest grilling. Wyoming Republican Sen. John Barrasso blasted Massachusetts for consuming more energy than it produces and blocking natural gas pipelines as part of a “radical climate agenda.”

“The last thing FERC needs is someone eager to impose the failed policies of Massachusetts on the rest of our nation,” he said.

Barrasso questioned Chang about a 2018 newspaper article in which she was quoted as saying it “doesn’t make sense” to build new gas pipelines or power plants.

“Do you still think it’s fiscally irresponsible to invest in pipelines?” Barrasso asked. Chang initially said the issue is “very complex in New England” but added that “if I had my magic wand I would love to have more gas infrastructure and gas supply” in the region.

‘Pretty civilized’

In response to repeated questions from multiple GOP senators about whether FERC is an economic or environmental regulator, the nominees agreed that is the former. They also agreed that “beneficiaries” should shoulder the costs for transmission projects, though quantifying benefits of large transmission projects, and who they extend to, is a thorny debate.FERC is expected to release a final rule to address some of those questions this spring.

“The who pays question is significant,” said Utah GOP Sen. Mike Lee, who was concerned about “socializing” the costs of transmission to “ratepayers that will not benefit from those projects and did not have a say in the climate policies that have been adopted in other states.”

Colorado Sen. John Hickenlooper, a Democrat who has been pushing legislation to build more interregional transmission lines, asked whether FERC should establish minimum interregional electric transfer requirements, which would allow different parts of the electric grid to better help each other during increasing severe weather and other emergencies. All three nominees voiced interest, though See and Chang noted the importance of taking “regional differences” into account.

Sen. Bill Cassidy,  a Louisiana Republican, asked whether FERC has the authority to incorporate greenhouse gas emissions into its review of projects, a long-running debate at the agency. The nominees pledged to follow the law, though Rosner noted there are some courts that have decided the agency needs to consider certain emissions.

“According to the Natural Gas Act, it does not specify greenhouse gas as a criteria for evaluating natural gas pipelines,” Chang said.

The nominees were also asked about grid-enhancing technologies, which can improve the capacity of existing transmission lines, speeding up the connection of new power resources to the grid and local and state conflicts with federal authority over transmission, among other concerns.

But they mostly provided artful answers, noted Ari Peskoe, director of the Electricity Law Initiative at the Harvard Law School Environmental and Energy Law Program.

“I think if there’s any value to these hearings it’s that the public hears what issues the senators are interested in,” he said. “These nominees were careful to avoid saying anything that would get them into trouble with either the Republicans or Democrats.”

Alaska Sen. Lisa Murkowski, a Republican, called the committee hearing “pretty civilized” and “not pitting individuals against one another or kind of the political trading that goes back and forth.”

And indeed, the tone of the hearing could signal that the nominees might face a smooth path to confirmation, Peskoe said. The Koch Industries-linked American Energy Alliance, which has been supportive of fossil fuel industries, complained that Manchin is “working with President Biden to rush these nominees through the process without much scrutiny.”

“These three nominees were selected to ease some of the political considerations,” Peskoe said. “Maybe it actually suggests we’ll have a moment of cooperation here.”

It’s never ideal for FERC to be without a quorum, like it was in 2017, but now is a particularly bad time, said Caitlin Marquis, managing director at Advanced Energy United, a clean energy trade group.

“There should be recognition from both sides that FERC without a quorum is bad for everyone. It creates uncertainty for all aspects of the energy industry,” she said. “There’s never a good time for FERC to be in turmoil but certainly this is a time of historic change in the industry.”

Manchin’s office did not respond Thursday to questions about next steps for the nominees.

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It’s the first non-water-cooled reactor to be approved for construction in the U.S. in over 50 years.

Policy, politics and progressive commentary

The U.S. Nuclear Regulatory Commission has issued a construction permit for a new nuclear test reactor to be built in Oak Ridge, Tennessee.

Kairos Power, the California company developing the Hermes demonstration reactor, says it’s the first non-water-cooled reactor to be approved for construction in the U.S. in over 50 years.

Construction of the 35-megawatt thermal reactor, which uses molten salt to cool the reactor core, at the Heritage Center Industrial Park is expected to begin next year. The Oak Ridge National Laboratory and the Tennessee Valley Authority, are “collaborators” on the project, which has been paid for “nearly exclusively” through private investment, the company says, though the project has also been selected for $303 million in Department of Energy funding.

“With the Hermes construction permit now approved, Kairos Power is demonstrating our leadership in developing advanced nuclear reactors and we have made a big step forward on our path to deploying clean, safe, reliable, and affordable energy in East Tennessee and beyond,” said Mike Laufer, Kairos Power co-founder and CEO, in a statement.

A separate application to the NRC for an operating license will have to be approved before Kairos Power can operate the demonstration reactor, the NRC said.

Across the country, private developers, policymakers and utilities are exploring options for advanced reactors and small modular reactors to maintain reliability in a decarbonizing grid, power hydrogen production, replace jobs and tax revenue in struggling towns where coal power plants are closing and bring zero-emissions electricity to remote areas of the globe.

But new nuclear power has been infamously expensive and difficult to build in the United States over the past several decades, and one of the more celebrated advanced reactor projects, NuScale’s Carbon Free Power Project, was recently canceled as costs climbed and subscribers pulled out.

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New rules proposed by the U.S. Environmental Protection Agency earlier this year in its latest attempt to regulate the carbon from power plants have drawn fire from some congressional Republicans, grid operators and other regulators. (Photo by Scott Olson/Getty Images)

Policy, politics and progressive commentary

Electric reliability has been a hot topic lately — from congressional hearings to regulatory agencies and at the regional transmission organizations that run the electric grid in much of the country.

The electric grid in the U.S. is undergoing a major change, prodded by state and federal decarbonization policies, market forces pushing cheaper and cleaner forms of electricity and aging power infrastructure.

That’s run up against electric transmission constraints, big delays in getting new wires built and massive backlogs in getting new, mostly renewable projects connected to the grid. Grid operators, in particular, are worried about the pace of the change, arguing fossil plant retirements are accelerating too quickly to ensure there are enough new resources to replace them.

Into that tumult the U.S. Environmental Protection Agency earlier this year dropped a proposal to again attempt to regulate carbon from power plants, which are responsible for about a quarter of all U.S. greenhouse gas emissions.

Since they were rolled out in May, the proposed rules have been a lightning rod for congressional Republicans and drawn fire from competitive electric generators as well as concern from federal and state energy regulators and grid operators that the regulations go too far, too fast.

But the EPA and clean energy proponents say the time frames are workable and crucial to cutting carbon emissions while allowing time for compliance and the flexibility needed to keep the lights on during the transition.

What is the EPA proposing? 

EPA’s draft rule creates different emissions targets for gas and coal plants depending on their planned retirement date and capacity factors, a measure of how much power a plant produces over time relative to how much it could have produced at full operation.

“We have committed ourselves to designing and implementing regulations to serve the public’s dual needs of healthful air quality and reliable and affordable electricity,” said Joseph Goffman, a principal deputy administrator at EPA, at a Nov. 9 Federal Energy Regulatory Commission (FERC) technical conference on electric reliability. “These emissions are helping fuel an escalating climate crisis that is already having devastating impacts on Americans across the country.”

The general approach, according to Carrie Jenks, executive director of Harvard Law School’s environmental and energy law program, is to require coal and gas units that don’t plan to retire in the near term and are operating at higher capacity factors to undertake more rigorous carbon reductions.

“If you’re operating a lot, and a lot throughout the year and really frequently, then you have to do more to reduce your emissions from those plants. But if you’re operating either as a peaker or intermediate, meaning not all the time, then there’s different options that are available for those plants,” Jenks said at a media briefing organized by Energy Innovation, a non-partisan energy and climate policy think tank.

For example, for a coal plant that intends to operate beyond 2040, EPA is proposing that the facility will need to capture 90% of its carbon emissions by 2030.

For a plant that will retire by 2040, its emissions rate is based on co-firing with natural gas at a rate of 40%. A coal unit that plans to retire by 2035 could agree to operate at 20% capacity and not be bound by any new carbon restrictions, Jenks said. If it’s retiring before 2032, it can operate as is.

“2030 is really the decision point for units for how they plan to operate going forward,” Jenks said, noting the exact thresholds and parameters could change in response to comments EPA receives. There are similar requirements for gas plants (though they differ slightly for new and existing plants) to either blend with hydrogen to reduce emissions or capture emissions depending on whether they are baseload (above 50% capacity factor) or so-called “peaker plants,” which fire on during periods of high demand.

However, EPA’s reliance on carbon capture and storage as well as hydrogen blending have drawn lots of criticism, mainly because both sets of technologies are relatively in their infancy and have yet to be deployed at any kind of scale.

Anthony Campbell, president and CEO at East Kentucky Power Cooperative, speaking on behalf of the National Rural Electric Cooperative Association, said EPA’s rule “is unlawful and unworkable” at the FERC technical conference. Campbell said that under the proposed rule, plans are due to EPA by 2026, making it impossible for plant operators to make compliance decisions given the uncertainty surrounding carbon capture and hydrogen production.

“They will be forced into either retirement of essential, dispatchable coal units or curtailment of those units to capacity factors below 20% by 2032 and complete retirement by 2035,” Campbell said. “The disorderly retirement and elimination of baseload generation will leave the electricity grid with a significant deficit of dispatchable generation that cannot be replaced by intermittent resources, especially during a time of economic growth.”

‘The arithmetic doesn’t work’

Electric reliability debates can get complex. But FERC Commissioner Mark Christie, a former Virginia utility regulator, said at the Nov. 9 technical conference on reliability that the fundamental problem facing the U.S. electric grid is as simple as two lines on a chart. One is the demand for power.

“That line’s going up,” Christie said. “It may go up astronomically if ‘electrify everything’ takes place — you electrify the transportation sector, you electrify the home heating sector.”

The other line is supply of power.

“And that line ain’t going up, or it’s certainly not going up nearly as rapidly,” he said. “The arithmetic doesn’t work. And that’s the fundamental issue.”

According to the Clean Energy States Alliance, a coalition of state energy agencies, 23 states, plus the District of Columbia and Puerto Rico, have 100% clean energy goals. Along with federal policy like the landmark Inflation Reduction Act, and market conditions, utilities, many of which have their own decarbonization goals, are being prodded into retiring older coal and gas plants.

(At a recent FERC meeting, Christie warned that two of the nation’s largest regional transmission operators, MISO and PJM, are “basically hemorrhaging dispatchable resources.”)

Jim Robb, president and CEO of the North American Electric Reliability Corporation — which, for the first time, has started listing “energy policy” as a reliability risk — told the commissioners at the reliability conference that the expansion of so-called inverter-based resources like wind, solar and batteries introduce new variability into grid management, especially as they become bigger parts of the power mix.

“This is a country that hasn’t proven its ability to develop infrastructure to support that,” Robb said. “We’re going to need to figure out how to get transmission built, we’re going to have to figure out how to speed the development of new resources onto the grid and importantly we need to figure out how to retain the stuff that we have to meet any of these policy objectives.”

Goffman, the EPA official, said the agency is committed to continuing engagement with regulators and grid operators “over the coming weeks and months so that we can ensure we arrive at a final rule for reducing greenhouse gas emissions from power plants that is effective, workable, and fully compatible with maintaining reliable and affordable electricity.”

‘The grid can absolutely be reliable’ 

Ric O’Connell, executive director of GridLab, which he called a public interest organization that provides technical expertise on the electric grid to policy makers, told the FERC conference that the EPA rules and ensuring reliability are compatible.

“The grid can absolutely be reliable under the proposed EPA rules but we’ll need to plan and take action,” he said, adding that the rules codify “what’s already happening due to economic and policy forces.” He noted that 2 terawatts (2 million megawatts) of power resources, mostly wind, solar and battery resources, are stuck in interconnection queues across the country.

In a media briefing hosted by Energy Innovation, O’Connell said there’s “an enormous wealth of academic and industry literature” that shows the path to cutting carbon from the power sector drastically over the next decade.

“We do that through a very simple playbook. It’s deploy wind, solar and batteries over the next decade,” he said. Couple that with keeping carbon-free sources like hydropower and nuclear plants online and use existing gas fleets at low levels to provide the crucial balancing services large amounts of renewables will require, O’Connell added.

He noted that the United Kingdom has gone from 71% coal power in 1990 to less than 1% this year and that California and New England’s electric grids are already largely coal free. Even Texas, he noted, “is well on its way to looking like this as well.” He noted that MISO’s projections envision a similar grid, with natural gas plants running at very low capacity factors by 2040.

“Can we run our grid without coal? The simple answer is yes,” he said.

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The historic Winter Storm Elliott dumped up to four feet of snow in Buffalo, New York, and lead to power outages and rolling blackouts in the southeastern U.S. New reports say the grid serving the entire eastern half of the U.S. was at risk and that the system is still vulnerable to frigid weather. (Photo by John Normile/Getty Images)

Policy, politics and progressive commentary

Nearly a year ago, a Christmas weekend storm blasted across the country, forcing utilities to cut electricity to hundreds of thousands of people in parts of the southeastern U.S. after temperatures plunged, demand spiked, large numbers of power plants failed and natural gas supply was strained.

As the anniversary approaches of Winter Storm Elliott, a pair of reports released last week reveal how much worse the situation almost became and the continued vulnerability of the U.S. energy grid to frigid weather.

“The power plants that we had last year are the same ones we have this year,” said Simon Mahan, executive director of the Southern Renewable Energy Association, a trade group. “Sure there might be some window dressing weatherization efforts that have gone on but there’s no real way to determine if that’s going to be good enough going into this year.”

A joint inquiry into Elliott by the Federal Energy Regulatory Commission and the North American Electric Reliability Corporation, also illustrated that, despite the blackouts, a larger catastrophe for the New York City area was barely averted and the grid serving the entire eastern half of the U.S., called the Eastern Interconnection, was also at risk. Among many other recommendations, it calls for congressional and state legislative action to create reliability rules for natural gas infrastructure to ensure it functions in cold weather

“The report highlights what I’ve called for before: Someone must have authority to establish and enforce gas reliability standards,” said FERC Chairman Willie Phillips.

The other report, NERC’s winter reliability assessment, found that about two-thirds of the country this winter remains at “an elevated risk” of insufficient energy supplies to meet demand in severe conditions.

“Industry cold weather preparations are on a positive trend but generators and fuel supplies in warmer zones are still likely to have performance issues in freezing temperatures,” read a NERC presentation to reporters last week.

‘A real world of hurt’

Mahan, who was living in Texas during Winter Storm Uri in 2021, when millions of people endured blackouts lasting days and an estimated 246 people died, said Elliott posed a similar threat to the entire eastern U.S.

“We were way closer than what a lot of folks realize and too close to have basically done nothing about it in the last year,” he said. “I’m always at a loss to explain to folks how close things were and how dangerous it was because I don’t know if there’s enough adjectives to describe it.”

Gas pressure dropped so low in the system serving parts of New York that, had Con Edison, the gas provider, not taken emergency actions and the frigid temperatures abated, the system was close to a “complete loss” that would have taken months to bring back online, the joint report says.

Jim Robb, NERC’s president and CEO, said at a FERC technical conference on Nov. 9 that New York City dodged a disaster that would have “far exceeded” the 2003 summer blackout, the largest power outage in U.S. history.

“Had that cold front persisted one more day we would have been in a real world of hurt in the Northeast,” Robb said.

In North Carolina, Duke Energy’s struggles also risked a broader grid collapse, with frequency dropping over the weekend.

“Ultimately on the morning of Dec. 24, grid operators maintained frequency by reducing electricity demand, including by shedding over 5,400 MW of firm load, leaving hundreds of thousands of customers without electricity to heat homes for several hours during the extreme cold weather conditions,” the report says.

The joint inquiry noted that Elliott was the fifth event in the past 11 years in which cold weather forced power plant outages that jeopardized the bigger grid. All told, more than 1,700 power generating units saw 3,565 unplanned outages, derates (a loss of generating capacity) or failures to start. Including power plants that were already offline before the storm, about 18% of the anticipated power supply in the U.S. portion of the Eastern Interconnection was unavailable during the worst part of the storm.

As the electric grid has become more reliant on natural gas power plants (which provided about 40% of power generation in 2022) it’s also become more vulnerable to gas system failures. And freezing weather makes it harder to get gas to power plants just when it’s needed most.

“These recurring failures make clear that America’s natural gas infrastructure and electric grid continue to be severely challenged during extreme cold weather events, repeatedly jeopardizing reliability during life-threatening conditions, even when technology exists to protect the vulnerable components,” the report says, noting the primary causes of unplanned generation outages as “freezing issues, fuel issues and mechanical/electrical issues.”

The push to winterize

New cold weather reliability standards developed by NERC after a 2018 cold snap for power plants became effective April 1. They included new requirements to maintain and implement cold weather preparedness plans for freeze protection, annual inspection and maintenance rules and training requirements, among others. But after Uri in 2021 demonstrated a clear need for stronger standards, FERC approved new rules earlier this year, though it told NERC to revise some of the applicability criteria. In October, NERC’s board adopted two new reliability standards for extreme cold weather.

“It is a complex challenge,” said John Moura, NERC’s director of reliability assessment and performance analysis. He noted that the electric system was built around summer peaking, though in recent years winter reliability has emerged as the major concern, mostly because of the rise of gas plants.

The development of standards has been slow, he acknowledged, but because it’s a collaborative “stakeholder” process at NERC, they’re created in concert with industry, less litigated and more likely to stick, Moura said.

“While it might take a long time, the end product is extremely valuable and something everyone gets behind,” he said. “Yes, it’s taken some time but we think we’re getting to that final answer.”

In the meantime 

The Tennessee Valley Authority, which was created in 1933 and had to impose rolling blackouts during Elliott for the first time in its history, says it has “undertaken a massive effort” since the storm to make winterization upgrades on its generation fleet at a cost of about $8 million.

“Mother Nature may hit us hard again this winter, but we have done the hard work — the necessary work — to ensure that we can safely and reliably provide power to our 10 million customers across the valley,” said Allen Clare, a TVA vice president. Louisville Gas & Electric/Kentucky Utilities, which was also forced to cut power to customers during the storm, said it “is looking at potential process improvements, such as public messaging and projects at plants to minimize valve freezing and other cold weather impact,” per the joint report.

Duke Energy, which initiated blackouts that affected about 500,000 customers in the Carolinas, faces an inquiry by regulators in both states. South Carolina’s Office of Regulatory Staff found numerous “areas for improvement” in the company’s cold weather preparations, noting that Duke significantly underestimated demand, failed to make supply planning adjustments and update forecast estimates, experienced plant and software failures and had problems communicating effectively with customers. An inquiry into cold weather reliability of gas, water, wastewater and electric systems that was initiated in 2022 by the North Carolina Utilities Commission remains open.

In a statement to a South Carolina news station, Duke, which agreed to a corrective action plan and said it has competed the majority of the 101 action items identified, added that it “learned from that historic day and continue to use what we’ve learned from this regional event to help deal with unusual and severe weather in the future.”

The nation’s largest grid operator, PJM, which coordinates the flow of electricity for all or parts of 13 states and the District of Columbia, was not forced to resort to rolling blackouts during Elliott. But it alarmed electric grid experts when it begged customers in its region to conserve electricity, since it was known to have a huge surplus of generation capacity.

In the wake of the storm, PJM is asking FERC to approve changes to its capacity market, which is intended to make sure there’s enough electric supply at critical times by providing extra payments to generators who commit to being available when demand spikes. PJM says they’re “designed to support reliability of the electric grid now and in the future amid increasingly extreme weather and a changing generation fleet.” The reforms are intended to better reflect actual risk of outages by generation type (such as common failures by natural gas plants), get more accurate accreditation of power sources to better assess their value to the grid and “improve generator testing, including operational and seasonal requirements.”

The proposed changes are a mixed bag, according to Tom Rutigliano, a senior advocate with the Natural Resources Defense Council’s Sustainable FERC project who focuses on PJM. He called reforms that more accurately take into account gas plants’ reliability risks a good step but criticized a plan to reduce penalties for generators that are paid to be available when called upon but fail to deliver.

“They’re betting that the savings from cost cutting will be more than the penalties they might have to pay,” Rutigliano wrote. “Reducing penalties is a direct message to power plant owners that they should spend less on preventative maintenance and preparation for emergencies.”

‘The rhythm of it all’

In an interview, Rutigliano said the fresh memory of Elliott in the minds of grid operators, power plant operators and utilities could be enough to instill vigilance in the event of severe weather this winter.

“If the past is any indicator, you have these freeze-offs and big problems that largely come down to negligence,” he said. That’s followed by a period of heightened awareness with lots of “sub rosa” actions that grid managers, utilities and other power system operators can employ to tighten up, he said. Unfortunately though, that tends to slacken after a few years, he added.

“That seems to be the rhythm of it all,” Rutigliano said. “I’d be less worried this winter because cold weather performance is on every power plant owners’ mind.”

Mahan, of the Southern Renewable Energy Association, said getting state utility commissions to better vet winterization efforts, improving power demand forecasting, diversifying generation resources, building more transmission to better link regions and getting new power sources like wind, solar and storage connected to the grid all have a role to play in protecting reliability.

“There’s no silver bullet,” he said. “With something like this, having a multi-pronged approach is the way to prepare for the future. … When you go into the woods you want to have a Swiss army knife.”

Getting gas right 

In the long run though, major regulators like NERC and FERC agree, toughening winterization standards and Congressional action on improving the reliability of the gas system and forcing better coordination with the electric power industry are necessary.

“The electric utility network is highly dependent upon the uninterrupted performance of the gas production and delivery network,” a report issued by the North American Energy Standards Board issued in July says. “Without the latter, the former cannot meet its own performance requirements.” When the gas system fails to deliver for power generation, the results can be catastrophic, the authors wrote.

“During Uri, gas needed for power generation vanished during periods of peak winter demand for both gas and electricity, tragically resulting in excess of 240 lives lost and economic damage estimated as high as $130 billion,” the report says.

The board made 20 recommendations. Some had broad support by both the electric and gas sectors, such as more state encouragement of demand response programs (which can cut electric and gas demand when supply is insufficient), aligning industry scheduling timelines and changing strategies for “unit commitment,” which refers to deciding when and which power generating units will start and shut down.

Others, however, like timely reporting of natural gas pipeline website data and encouraging states to “consider the development of weatherization guidelines appropriate for their region/jurisdiction” were generally widely supported by the electric industry but drew more opposition from the gas sector.

“As much as we are heartened by the strong support for some recommendations, the divergence of support between the two sectors on others is profoundly disturbing,” the report says. “it reflects a fundamental lack of agreement regarding the lessons learned from these past two winters and the challenges ahead in ensuring that outages no longer occur owing to a failure between these two systems. … We did not regard any of our 20 recommendations to be so burdensome or so profoundly altering that they would engender strong opposition.”

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Aerial view of a dirt road leading up through the Thacker Pass Lithium mining area. (Getty Images)

Policy, politics and progressive commentary

The decarbonized, electrified future envisioned by the Biden administration, state governments, automakers, utility companies and corporate sustainability goals depends to a huge degree on minerals and metals.

Lots more lithium will be needed for car and truck batteries, as well as the big banks of batteries that are increasingly popping onto the electric grid to balance the intermittency of wind and solar power. Those batteries, as well as wind turbines and solar panels, also need copper, cobalt,, nickel, zinc and “rare earth” elements used in electric car motors and other clean technologies, among other materials.

The problem is that not enough of those materials are mined in the United States or other friendly countries to meet the projected demands of a decarbonizing nation. At present, China dominates the market for most battery raw materials, for example, which “presents geopolitical and environmental risks,” per a presentation on May 10 by S&P Global on challenges facing the global battery sector.

”This is part of what the legislative environment is gearing up to help us counter,” said Graham Evans, an S&P Global research director focused on auto supply chain and technology. “We don’t want to be too heavily reliant on any one country.”

But even as new federal legislation like the Inflation Reduction Act and the bipartisan infrastructure law created big incentives for renewable power, electric vehicles and production tax credits for critical minerals, mining operations under development in Nevada, North Carolina, Minnesota and Arizona, among other locations, haven’t exactly been met with open arms.

And mining organizations and renewable trade groups say the long permitting timelines and litigation delays for mining projects are incompatible with the urgent demand for materials needed to decarbonize the economy.

‘You need the natural resources’

That dynamic in part led to some clean energy groups joining with traditional industry, fossil fuel interests and their allies in Congress in an ultimately unsuccessful push to include permitting reform as part of the deal between President Joe Biden and Congressional Republicans to raise the debt limit. In the wake of a controversial federal court decision involving an Arizona copper mine project, there’s also separate bipartisan legislation sponsored by Nevada Democrat Catherine Cortez Masto in the Senate to clarify rules around where mining-support activities like waste or processing can take place on federal land.

“You need the supply chains, you need the natural resources. … We don’t do that unless we do more domestic production,” said Harrison Godfrey, managing director at Advanced Energy United, a clean energy trade group.

“We need permitting reform if we’re going to undertake this mining. We think you can maintain reasonable environmental regulations and move forward around this. … Our permitting regime has been misused to try and stop anything and everything really in excess of what’s reasonable to protect the environment and communities.”

Numerous environmental groups, though, have blasted the debt ceiling deal, which includes provisions intended to get the contentious Mountain Valley Pipeline — a natural gas project through West Virginia and Virginia that has been plagued by environmental violations and seen numerous critical permits tossed out by federal courts — over the finish line.

They also assailed attempts to streamline the National Environmental Policy Act (NEPA) in order to speed projects up. The Sierra Club urged Congress to reject it while the Center for Biological Diversity called it “an injustice and moral failure to have to choose between defaulting on our national debt or bankrupting the health of people and the planet.”

‘Benign neglect’

Mark Compton, executive director the American Exploration and Mining Association, a trade group, said there’s been a long history of “benign neglect” of the American mining industry that has resulted in a dependence on foreign sources, a problem that’s been underscored by the fallout from the Russian invasion of Ukraine and the global pandemic.

“To decarbonize our economy is causing a demand increase in minerals that really is staggering,” he said. “The supply chain issues have really come to the forefront.”

Compton said new American mining projects average seven to 10 years to make it through the permitting stages, compared to two to three years in Canada and Australia, which have comparable environmental protections.

“We’re not talking about needing to lower environmental standards,” he said. “The environmental standards, the regulations that are in place, that’s not the problem. It’s really an inefficient and often duplicative permitting process through NEPA that simply takes longer than it has to.”

The permitting process is only part of the picture, he added. Most hard-rock mining, Compton said, happens on federal lands in the western U.S. About half of it is currently off limits to mining.

“Minerals are located where they are and we can’t move them,” he said, noting that economically viable pockets are rare. “We have to have access to federal lands to be able to develop and explore for minerals.”

Allowing mining on public lands, however, can be extremely fraught, as in the case of the long-contested Twin Metals project in the Superior National Forest in Minnesota. “Copper for wind power and broadband networks. Nickel for electric cars and medical devices,” the company website says. “Cobalt for smart phones and batteries. The world demands more and more metals every day. The minerals we have in Minnesota can help supply this demand.”

But environmental groups have warned the deposits lie too close for comfort to the Boundary Waters area, which the state tourism office calls “one of America’s most beautiful and remote places.” The Sierra Club says on its website that “there is currently no sulfide mine in existence that is not polluting the groundwater.” And in January, the Biden administration imposed a 20-year mining ban on 225,000 acres of federal land near the wilderness area.

Twin Metals said it was “stunned.”

“This region sits on top of one of the world’s largest deposits of critical minerals that are vital in meeting our nation’s goals to transition to a clean energy future, to create American jobs, to strengthen our national security and to bolster domestic supply chains,” the company said in a statement.

There are also major concerns over irreversible impacts to Native American sites, as in the case of the Lithium Americas project in Thacker Pass, Nevada, where the project has divided tribal communities and sparked protests and litigation, and the Resolution copper mine project in Arizona. According to Morgan Stanley Capital International, 97% of nickel, 89% of copper, 79% of lithium and 68% of cobalt reserves and resources in the U.S. are located within 35 miles of Native American reservations.

Compton acknowledged that past practices have created a reputation problem for the mining industry.

“It is true that mining projects meet a lot of resistance. I think that stems from a long history of mining in this country before we as a nation even thought about environmental laws or regulations,” he said, though he added that today’s industry is highly regulated and the most “environmentally responsible in the world.”

How much to mine?

However, even modern mining, of course, is inherently destructive. Open pit mining opens vast holes in the ground, creates huge quantities of waste rock that must be managed and potential water contamination problems from processing, seepage from tailings, which consist of the rock, chemicals and other waste products remaining after extraction, and acid rock drainage. There is also loss of wildlife habitat. Although there are efforts to produce, for example, lithium in new and more sustainable ways, the race for crucial minerals and metals has prompted some to question the eagerness for more extraction.

“Large-scale mining entails social and environmental harm, in many cases irreversibly damaging landscapes without the consent of affected communities,” says a January report from the University of California-Davis’ Climate and Community Project, which recommends achieving zero emissions and minimizing new mining by reducing car dependence, shrinking battery sizes and maximizing recycling.

“As societies undertake the urgent and transformative task of building new, zero-emissions energy systems, some level of mining is necessary,” the report says. “But the volume of extraction is not a given. Neither is where mining takes place, who bears the social and environmental burdens, or how mining is governed.”

Others see ensuring that a robust recycling and reuse chain comes with the new clean energy economy as key to reducing the impact of mining minerals. CNBC reported last month that a growing number of start up businesses are getting to work on solar, wind and battery recycling operations.

“Over the medium-to-long-term, the development of domestic recycling and reuse sectors will not only help to mitigate the need for new critical mineral production but will also help reduce our reliance on geostrategic competitors for these resources and technologies,” Advanced Energy Economy says in a policy paper.

Max Wilbert, an environmental activist who had helped organize a protest camp at the Thacker Pass site in Nevada, favors what many consider a radical “degrowth” solution to climate change, pollution and ecological collapse rather than trying to maintain current lifestyles with new sources of power that come with their own environmental problems.

“Some people might say that’s a dream,” he said. “I think the real dream is trying to maintain the status quo with a new energy source.” 

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Scott Anderson, a researcher at the Idaho National Laboratory's Irradiated Materials Characterization Lab, works with materials in a "glovebox" as part of the lab's research into how exposure to radiation alters reactor components. The lab's research is aimed at understanding how materials and fuels respond to radiation, which is crucial data as licenses for existing nuclear reactors are extended. (Photo: Robert Zullo/ States Newsroom)

Policy, politics and progressive commentary

IDAHO FALLS, Id.  — At the sprawling array of laboratories and test facilities in the southeastern Idaho desert where the U.S. nuclear power industry was born more than 70 years ago, past, present and future are converging.\

Not far from where the first reactor to ever produce usable electricity made history in 1951, Idaho National Laboratory nuclear engineer Yasir Arafat and his team have been working to design, build and fire up what they hope will be the world’s first modern “microreactor.” 

The MARVEL (Microreactor Applications Research Validation and Evaluation) project, expected to be built by the end of 2024, is part of a new wave of advanced nuclear technology that energy start-ups, electric utilities and state and federal policymakers are eyeing to maintain reliability in a decarbonizing grid, power hydrogen production, replace jobs and tax revenue in struggling towns where coal power plants are closing and bring zero-emissions electricity to remote areas of the globe. 

“Think about one energy source that can give you 24/7 reliable carbon-free electricity on demand regardless of geographical location — that’s nuclear,” said Arafat, who is pushing to achieve “criticality” (when the fission reaction is self-sustaining) in the small 100-kilowatt reactor. “My hope is that companies would actually take this, leverage this technology and actually come up with commercial versions that can be cost competitive with solar and wind and oil and gas and be able to deploy them everywhere.”

At the lab and among boosters across the country, expectations are high for new nuclear reactors. But critics question whether nuclear power, historically slow and expensive to build, will be left behind by the rapid deployment of cheaper renewables and development in battery storage and other technologies.

“We should have a very clear-eyed view of what the costs of these prototypes are, what their attributes are, what their flaws are and whether or not it has a viable place in a competitive and low carbon power market,” said Geoffrey Fettus, senior attorney in the nuclear, climate and clean energy program at the Natural Resources Defense Council, which is skeptical of the hype around the nuclear industry. “And it’s going to take a lot of years to figure that out.”

‘The decarbonization imperative’

Representatives from  23 states have joined a new collaborative organized by the National Association of Regulatory Utility Commissioners (NARUC) and the National Association of State Energy Officials intended to help state leaders and regulators answer questions surrounding new nuclear power generation. Some states may have never had a nuclear power plant within their borders and, even in the states that do, some utility commissions may not have any staff left who dealt with a reactor project, since almost all of them were built decades ago, staffers from the national organizations said in an interview. 

“There’s a certain proactiveness to this. The state energy offices and public utility commissions are interested in understanding the technology while it’s not yet deployed,” said Kirsten Verclas, senior managing director at NASEO, adding that states want to “get ahead” of some of the information before a utility comes to regulators for approval of a new nuclear project. 

Utility commissions, in particular, have “a lot of questions” about cost, spent fuel and waste management and translating that into “just and reasonable” electric rates, said Kiera Zitelman, a technical manager at NARUC. 

“They’re really concerned with how to do that,” she said. But some state officials also see opportunity, from staving off reliability worries as wind and solar become larger parts of the electric generation mix to the jobs and revenue new nuclear power plants can bring.

“There’s a lot of interest in how advanced nuclear can provide economic development and workforce development,” said Kelsey Jones, a senior program manager at NASEO.

In January, the Nuclear Energy Institute, a nuclear industry policy group that has long pushed to deposit nuclear waste at Yucca Mountain in Nevada, said there were 16 advanced nuclear projects in the planning or consideration stages in 10 states. 

And many states have adopted or are considering legislation or regulations creating zero-emission credits for carbon-free electric generation, incorporating nuclear power into clean energy requirements and state energy plans, as well as pushing for carbon pricing, tax exemptions and other policies that could benefit the nuclear industry. Last year’s federal Inflation Reduction Act contains production tax credits to keep existing reactors — which provide about half of the nation’s carbon-free power — running, major tax incentives for new advanced reactors and $700 million to develop a domestic supply chain for the high-assay low-enriched uranium fuel the advanced reactors will need.

A federal Department of Energy report from March says that modeling suggests that, “regardless of level of renewables deployment”  the U.S. will need between 550 and 770 gigawatts of additional “clean, firm capacity” to reach the Biden administration’s net-zero carbon goals. Right now there’s about 100 gigawatts of nuclear power generation in the nation. 

“Nuclear power is one of the few proven options that could deliver this at scale, while creating high-paying jobs with concentrated economic benefits for communities most impacted by the energy transition,” the report says. 

That all amounts to a lot of momentum for an American industry that in many respects had largely gone dormant for decades. New nuclear power plants have been vanishingly rare over  the past 30 years, and the few projects that have been attempted have been plagued by massive cost overruns, scandal and failure. 

“You’re seeing interest in new nuclear for a number of reasons. But foremost among them is the decarbonization imperative,” said John Kotek, senior vice president of policy development and public affairs at the Nuclear Energy Institute. More than 80% of U.S. electric customers are served by a utility that’s pledged to go largely carbon free, Kotek said. Wind, solar and battery storage at present can only get you so far, which makes nuclear an attractive option to offset the intermittency of renewable power, which is reliant on the wind and the sun, he added.

‘The question is going to be whether they can compete’

In particular, small modular reactors — which are expected to be able to built in factories and shipped to sites for shorter construction times and theoretically reduced costs and have the ability to be scaled up to meet different power demands (from tens of megawatts to hundreds) — are seen as an attractive option to replace coal plants and potentially pair with renewables.

Another recent Department of Energy report said that hundreds of coal plant sites could convert to nuclear, availing themselves of the grid connections and perhaps even some of the plant equipment to shave costs. The federal Nuclear Regulatory Commission certified the first small modular reactor design, for Portland, Oregon-based company NuScale Power, earlier this year.

NuScale sees a wide range of applications for its VOYGR power plant design, which can contain up to 12 power modules for a maximum capacity of more than 900 megawatts, including taking the place of the scores of U.S. coal power plants that may retire by 2035, complementing intermittent renewable power generation and providing power to critical infrastructure like hospitals, military bases, data storage centers and industry. NuScale says the plant will use just a fraction of the land (.05 square miles, as opposed to 94 square miles for wind and 17 for solar) that a comparable output wind or solar development requires.

“The NuScale plant is the only near-term deployable and commercially viable advanced nuclear generation solution for states across the country that seek a reliable, safe, and carbon-free solution,” said Diane Hughes, NuScale’s vice president of marketing and communications.

“Right now, SMRs don’t exist,” Fettus said. “There is not one that is producing power for the domestic grid. … We don’t see deployment happening until the 2030s at the earliest.” 

Fettus noted that it took NuScale more than six years to get NRC approval. It is the first small modular reactor design approved by the U.S. Nuclear Regulatory Commission.

“This is not about the NRC being slow. That’s about changes in the design and the serious process of getting a design approved when you’re fissioning atoms,” he said, noting that new nuclear reactors will be competing with emerging low or zero-carbon technology like long duration battery storage, natural gas plants with carbon capture and others. “There’s no evidence that they’ll get cheaper at scale. … We’ll build a few on subsidies. The question is going to be whether they can compete in the energy markets.” 

NuScale says its first American plant will be the Carbon Free Power Project, a 462-megawatt nuclear project that will be owned by Utah Associated Municipal Power Systems — which provides whole electricity to community-owned power systems throughout the Intermountain West—  and built on Idaho National Laboratory land. More than $1 billion in U.S. Department of Energy funding has gone to development and the plant is expected to be fully operational by 2030.  However, construction cost estimates for the project have also climbed, from roughly $5 billion in 2021 to $9.3 billion. Per UAMPS, the project will get $4.2 billion in Department of Energy cost-sharing funds and benefits from the Inflation Reduction Act. 

‘There’s a lot going on in nuclear right now’ 

Nevertheless, there’s little doubt at the Idaho National Laboratory that nuclear power is on the cusp of a major resurgence.

During a media tour this month at the 890-square mile national laboratory site, home to 5,700 researchers and support staff, the sense of history coming full circle was a common theme. 

“There’s a lot going on in nuclear right now in this decade. Not in the 2040s,” said John Wagner, the lab’s executive director. “The last time we took a new novel reactor operational on this site was 1973. So when the MARVEL reactor right here comes online next calendar year, it will have been 50 years since we operated a new reactor on this site.”

The lab is working not just on testing new reactors but helping to smooth the path for private developers by exploring new construction methods and materials, testing fuels and components to evaluate their performance and exploring how reactors can function as part of microgrids. The lab’s National Reactor Innovation Center has also developed a siting tool that can help developers avoid wetlands and cultural resources, incorporate environmental justice concerns as well as gauge “nuclear sentiment” in a given community, said Stephanie Weir, the siting and regulatory strategy manager at the lab’s National Reactor Innovation Center. 

“It’s been awhile but we have done this before,” Weir told reporters. “This nation built 52 reactors over a period of about 25 years, which shows us that we as a nation can innovate and demonstrate rapidly when we focus on it and when we have an urgent need to do so. We’re learning from the things that have happened over the last 50 years and so we’re going to do things a little bit differently. … We’re going to do it better by engaging closely with the public, private sector and tapping the innovators into the world class capabilities of our national lab system.”

The Idaho National Laboratory provided travel assistance to States Newsroom for its media days event.

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Solar and wind are expected to together account for 16% of total U.S. electric power generation in 2023, according to the U.S. Energy Information Administration. (Photo by Jeniffer Solis)

Policy, politics and progressive commentary

Despite supply-chain problems amid the lingering effects of the pandemic, 2022 saw major increases in solar and wind power in the United States, though that growth varied by state, according to a report released last month by a nonprofit focused on climate change.

Nationally, electricity generated from solar and wind grew 16% from 2021, with wind accounting for about 74% of that, per Climate Central’s ”WeatherPower Year in Review: 2022” report.

The New Jersey-based group analyzed data from its WeatherPower tool, which combines data on installed solar and wind facilities with observed and forecast weather information to create predictions of daily wind and solar generation by state, county, media market or congressional district in the lower 48 states. Alaska and Hawaii were not included because of data limitations, the report says. (However, Yale’s Climate Connections broke down 2021 numbers on where electricity generated in all 50 states comes from).  

President Joe Biden’s administration has set a goal of a 100% clean electric grid by 2035 and net zero carbon emissions for the entire U.S. economy by 2050. As of November, 36 states and the District of Columbia have established a renewable energy goal or a renewable portfolio standard, which generally requires electric suppliers to provide customers a minimum share of electricity from renewable sources.

“We wanted to help people understand how much renewable energy is being used, how it has grown and how much more it needs to grow in order to help meet climate goals,” said Jen Brady, manager of analysis and production for Climate Central. “In particular we discussed the climate goal of reaching net-zero emissions in the U.S.”

If historic trends continue, Brady said, the U.S. will fall short of those goals, though taking into account data from the Federal Energy Regulatory Commission on approved renewable projects, “we are seeing an increase in renewables that could lead us to satisfying net-zero goals.”

The electric power sector accounts for about a third of U.S. carbon emissions, which makes decarbonizing power production key to mitigating the effects of climate change. Though U.S. energy-related carbon emissions increased in 2021 by about 6% over 2020, that followed “a rise in economic activity and energy consumption once the initial economic impacts of the COVID-19 pandemic began to subside,” according to the U.S. EIA. Despite the increase, 2021 emissions were still lower than 2019 by about 5%, and 19% lower than the 2007 historical peak, the EIA said.

Solar and wind are expected to together account for 16% of total U.S. electric power generation in 2023, up from 14% in 2022, according to the U.S. Energy Information Administration. All told, the Climate Central report says, the 683,130 gigawatt hours generated across the country from wind and solar were enough to power 64 million average American households, defined as a residential customer who uses about 886 kilowatt hours per month. 

But there can be big differences as far as what’s being built in individual states. And to understand the Climate Central findings, it’s crucial to know two different electric industry terms: capacity and generation. Capacity, measured in megawatts, is a measure of the maximum output of a given electric generation plant under optimal conditions, like strong winds or full sun. Generation, measured in megawatt hours, is how much electricity is actually produced.

Texas led the nation in both wind capacity (nearly 37,400 megawatts) as well as actual generation (nearly 130 million megawatt hours). California led the nation in installed solar capacity (about 28,500 megawatts) and solar generation (nearly 59 million megawatt hours). Texas was also second place in both categories in solar, though Florida, North Carolina and Arizona were also in the top five for solar generation. In wind capacity and generation, Iowa and Oklahoma followed Texas.

In a different analysis, the American Clean Power Association, an industry group, said 18 states installed more wind, solar or battery storage in 2022 than in 2021. Six states that installed no new capacity in 2021 — Delaware, Idaho, Kentucky, Louisiana, New Hampshire and Tennessee — installed new capacity in 2022, the group said, noting that Mississippi, Washington and Hawaii saw the highest growth in annual installations from 2021 to 2022. The association said the top states for renewable projects in development are, from biggest to smallest, Texas, California, New York, Indiana, Virginia, Arizona, Illinois, Nevada, Ohio and New Jersey. 

“Certain locations are more suitable to certain types of renewable energy,” said Brady. “With the exception of offshore wind, which may increase wind power in smaller states along the East Coast, it is reasonable to expect places with more open land (and more wind) to install more wind turbines. Solar is a bit more universal, but locations still may weigh its suitability versus using more wind power, for example.”

To achieve 100% clean energy by 2035, solar and wind need to provide 60% to 80% of U.S. electric generation, according to a least-cost scenario modeled by the National Renewable Energy Laboratory. Big transmission upgrades are also required, mostly to bring electricity from wind-rich but sparsely populated areas to big urban and suburban areas with large electric demand.

“To achieve those levels would require rapid and sustained growth in installations of solar and wind generation capacity,” the report says. 

In 2022, wind provided a little more than 10% of U.S. electricity, while solar supplied 3.4%, per the EIA.

The post Here’s where renewable power is increasing (and where it’s not) appeared first on Nevada Current.

Fort Worth in 2021. Utility standards have always “reflected the industry lowest-common denominator” and represent a “floor, not a ceiling,” says an energy consultant. (Photo by Ron Jenkins/Getty Images)

Policy, politics and progressive commentary

Two years after Winter Storm Uri, which caused a massive power failure in Texas that caused more than 200 deaths, and just two months after another storm, Elliott, forced blackouts in parts of the South, the Federal Energy Regulatory Commission has approved new extreme cold reliability standards for power plants. 

However, the vote last week on the standards came with the acknowledgement by the commission that the new rules don’t go nearly far enough. The commission sent the North American Electric Reliability Corporation (NERC), the nonprofit regulator that sets and enforces reliability standards for the bulk power system in the U.S., back to the drawing board in several respects.

“There are a number of good measures in what we accept today to be sure,” FERC Commissioner Allison Clements said. “But the critical generator weatherization requirements as they were proposed, to be frank, are not up to the task.” 

Extreme cold weather, like the temperatures seen during Uri and Elliott, can knock out power plants that haven’t been adequately winterized.

During Uri, natural gas, coal and nuclear plants, as well as wind turbines, failed to hit their expected output, per a report by the University of Texas at Austin. More than 52,000 megawatts of generation went offline during the event, about 40% of the total capacity in the Electric Reliability Council of Texas, which runs the electric grid for most of the state. Problems included frozen lines and valves, boiler issues, iced turbine blades and other problems. In 2021, natural gas generation made up more than 50% of ERCOT’s capacity in 2021, with wind about 25%. 

In December, as Elliott sent temperatures rapidly plunging across much of the central and eastern United States, gas and coal plants tripped offline, forcing Duke Energy in North Carolina and the Tennessee Valley Authority to order rolling blackouts in their respective territories. PJM, the largest U.S. grid operator, overseeing an area that includes 65 million people and all or part of 13 states and the District of Columbia, implored customers to conserve electricity as 46,000 megawatts of power generation, mostly natural gas and coal plants, went offline because of fuel supply problems and equipment failures. 

And in Texas this winter, despite new weatherization standards for power plants approved last year, power plants still failed to perform because of both fuel shortages and other problems.

“We are not adequately winterizing power plants today, even under the ERCOT standards,” said Alison Silverstein, an energy consultant and former FERC senior adviser who also worked at the Public Utility Commission of Texas and Pacific Gas and Electric. “The failure of those power plants and our gas supply is putting human lives at risk. FERC is absolutely right to tell NERC to do better and do better faster.”

The new standards adopted by FERC last week include freeze protection steps, better cold weather preparedness plans, requirements to identify freeze-prone equipment, corrective action for freezing problems, training requirements and other procedures.

“These new standards will help to prepare our nation’s grid and our grid operators so they can provide power to consumers in the face of extreme weather,” FERC Chairman Willie Phillips said in a statement.

But FERC also found “areas for improvement” and directed NERC to “address concerns related to applicability, ambiguity, a lack of objective measures and deadlines and prolonged, indefinite compliance periods.” 

Clements noted, for example, that the standards only require existing power generators to weatherize so they can operate at extreme cold temperatures for one hour starting in April 2027.

“Yeah. One hour, starting in 2027. Needless to say that doesn’t bring total comfort that we will ensure we get through the next multi-day event like Winter Storm Uri,” she said. “And waiting four additional winters before weatherization requirements actually kick in does not reflect the urgency we feel.”

In a statement, NERC said it “appreciates FERC’s focus on reliability matters and will continue to work toward assuring the reliability and security of the North American bulk power system.”

Silverstein said NERC standards have always “reflected the industry lowest-common denominator” and represent a “floor, not a ceiling,” adding that regional grid operators can implement tougher standards.

“This isn’t just some minor engineering issue. This is provably life and death. And the frequency and ferocity of cold weather events over the past decade has changed enough that it is essential that this be handled as soon as possible,” she said.

“This is a way to put some fire under the NERC drafting committee and the board of trustees so they do what needs to be done.”  

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