The coal fired Brandon Shores Power Plant, on March 9, 2018 in Baltimore, Maryland. Critics say that PJM, which is responsible for coordinating the flow of electricity in 13 states and the District of Columbia, should have been prepared for the retirement of Brandon Shores. (Photo by Mark Wilson/Getty Images)

After years of climbing electric prices nationwide, customers in the United States�� largest power market are about to get squeezed harder.

Last month, PJM, which coordinates the flow of electricity for an area that includes all or parts of 13 states, including part of Kentucky, stretching from the Midwest to New Jersey plus the District of Columbia, released capacity auction results that hit a record high.

The auction, held by the regional transmission organization to ensure there��s enough power generation to meet demand spikes, such as during severe weather and other grid emergencies, produced a price of nearly $270 per megawatt day for much of the footprint (with some areas spiking much higher) compared to nearly $29 per megawatt day during the last auction. That increase, more than 800%, will cost customers across the region of 65 million people nearly $15 billion for the period covered by the auction (June 1, 2025 to May 31, 2026) the Maryland Office of People��s Counsel noted in a report released last week.

The costs will not hit equally across the PJM footprint, however, since utilities that own and operate their own power plants, like Virginia��s Dominion Energy, are both sellers and buyers in the capacity market, which will blunt the impact for their ratepayers. But Exelon, a company that owns six so-called ��wires-only�� utilities with 10.5 million customers in PJM states, expects the capacity prices to trigger double-digit rate increases for some customers, Utility Dive reported.

What makes the capacity costs tougher to swallow is that much of the increase can be laid at the feet of planning shortcomings, market design failures and governance problems at PJM, the organization��s critics contend.

��The tools to enhance reliability are in PJM��s hands,�� said Clara Summers, campaign manager for Consumers for a Better Grid, a watchdog group that is part of the Citizens Utility Board of Illinois. ��Instead PJM is dragging its feet on the clean energy transition and doing everything it can to keep fossil fuel plants online and ultimately ratepayers are the ones who suffer from this shortsightedness.��

��All sorts of problems��

In particular, critics point to PJM��s long delayed interconnection queue, which is the waiting list for generation projects looking for permission to connect to the grid. They say that even as PJM complains about fewer power plants entering its capacity auction and the increasing pace of old generating station retirements, it is seeking exemptions to a landmark new federal rule intended to streamline interconnection processes and get new power resources online quickly.

��PJM is the place with the most acute need for interconnection reform and they��re refusing to do what they��ve been told to do on it rather than be proactive on it,�� said Tom Rutigliano, a senior advocate at the Natural Resources Defense Council who focuses on PJM.

Jeff Shields, a PJM spokesman, said the organization has been working hard to fix its interconnection process and clear the backlog. He pointed out that many projects that have cleared the queue still aren��t getting built because of supply chain, financing or permitting problems that are beyond PJM��s control.

��We are not arguing about whether we need queue reform, we have only taken issue with some details,�� he said.

David Lapp, Maryland��s people��s counsel, an advocate for the state��s residential utility customers, said interconnection delays are just part of the problem at PJM.

Transmission costs �� because of a lack of competitive bidding of projects and a failure to plan for the long term, watchdogs argue �� have also climbed over the past decade.? And a deficient process for managing power plant retirements, along with market errors, have also hurt customers, Lapp said.

��Our customers are bearing the consequences of all sorts of problems at PJM, whether they be problems with the market structure, problems with the interconnection queue, problems related to planning failures or just mistakes,�� Lapp said in an interview with States Newsroom. ��PJM really needs to start taking the interest of customers more seriously into account in terms of how it develops its policies.��

How the retirement of Brandon Shores, a Talen Energy coal-fired power plant southeast of Baltimore, has been handled, exemplifies a lot of what��s wrong with PJM, Lapp added. Lapp and others, including members of Maryland��s congressional delegation, say PJM was caught flat-footed by the plant��s retirement, which should have been foreseeable given the limited amount it was running, a deal with the Sierra Club to quit burning coal and financial troubles for its operating company. PJM counters that it was told the plant would switch to burning oil and continue running.

��It is not reasonable to expect PJM to have anticipated the imminent deactivation of the Brandon Shores units when numerous public statements and direct conversations between PJM and Talen all supported the notion that Brandon Shores was on a path to remain online, albeit using a different fuel source,�� PJM President and CEO Manu Asthana wrote in a December letter to the Sierra Club,

��How much sense does that make?��

Regardless, PJM now has pushed for an urgent suite of transmission projects that will cost Maryland ratepayers about $800 million to bring in enough power to make up for the loss of the Brandon Shores station and another nearby Talen plant, Wagner, that is also retiring. PJM will also keep both plants running under what are known as��reliability must run�� arrangements that could cost Maryland ratepayers $629 million through 2028, the People��s Counsel report says, and comes with no guarantee they will actually be able to produce power when called upon. It also means the plants will exit the capacity market, which is designed to increase prices as energy supply tightens to encourage more generation sources to enter the market. ��The logic was that you want to treat them as gone to send a price signal for new entry,�� Rutigliano said. But even if a new generation source wanted to take advantage of the high capacity prices in the zone affected by the plant closure, the interconnection queue delays mean it could be years before it can participate in the auction.

��With PJM��s interconnection process so far behind that simply doesn��t work,�� Rutigliano said. ��Price signals are worthless if you��ve got a six-year delay in responding to them.��

And since PJM has already decided on a transmission solution to make up for the plant��s retirement, forcing customers to bear the high capacity prices doesn��t make sense, Rutigliano said.

��They exclude them from the market to get a high price signal but build transmission to ease the load pocket. Those are contradictory,�� he said.

The upshot is that Talen gets a windfall (the Office of the People��s Counsel report found the company��s revenues for the 2025-2026 delivery year are $360 million higher than what they would have been had Wagner and Brandon Shores participated in the capacity market) and electric customers in Maryland will be paying extra for plants that may not run much at all. They will also be paying extra for the loss of that plant to the capacity market in order to create a market signal that won��t matter because of the transmission solution PJM has already decided upon, which will also be paid by local customers. Lapp called it a ��triple whammy.��

��We have the illogical situation where customers are paying big dollars for a plant that is not going to run almost all the time,�� Lapp said. ��They still have no performance obligation. There are no consequences if PJM says ��We��re hitting a peak time. We need you to run.�� And Talen says ��We can��t.�� ��? How much sense does that make?��

Shields, the PJM spokesman, says PJM will continue working to improve markets, transmission planning and generator interconnection. But he added that, of the PJM states, Maryland has the second-fewest projects in the queue over the next few years.? ��We encourage Maryland policymakers to analyze why and what can be done to encourage development,�� Shields said. ��There is no debate �C Maryland needs energy infrastructure. Maryland needs generation to produce power for and transmission to move power to the customers who need it. The Maryland Office of People��s Counsel knows all of this to be true, and these critical issues deserve a better discussion than ongoing exercises in finger pointing.��

Seeking variances?

Particularly frustrating for PJM reformers are the exemptions it is seeking to a new Federal Energy Regulatory Commission rule to speed the connection of new power resources to the grid, which seems counterintuitive for an organization that has worried about having enough power to meet demand. PJM did begin its own interconnection reforms prior to the FERC order, and its request for variances indicates it wants to stick to that plan rather than conform completely to the new FERC rules, per a coalition of environmental and consumer organizations that are challenging the request before the commission.

��The interconnection queue in PJM is among the longest in the nation, whether measured by the number of projects, total electric capacity, or how long projects languish awaiting studies,�� the groups wrote in a FERC filing, noting that PJM won��t review new interconnection applications until 2026 at the earliest. ��At the same time, PJM is sounding the alarm about a reliability crisis because new generation cannot come online quickly enough to replace retiring power plants. To accelerate interconnection and bring new generation online to avoid reliability challenges from foreseeable retirements, PJM should welcome Order No. 2023��s reforms with open arms. Instead, PJM resists reform to its interconnection process.��

Mainly PJM is seeking permission for increased study timelines and a laxer penalty structure? and wants to sidestep reporting requirements on how it evaluates grid-enhancing technologies, which can save time and money over traditional transmission solutions. It also wants to avoid the requirement to realistically consider how energy storage resources will affect peak load.

Grid-enhancing technologies have been used for years elsewhere in the world to get more out of existing power systems and in many cases are faster and cheaper than building new transmission lines, but they��ve been slow to catch on in the U.S., in part because American utilities make more money by building big, expensive projects rather than more cost-effective solutions, proponents have said.

PJM wants out of a requirement to demonstrate that it has considered those technologies, said Katie Siegner, a manager who works on markets and electric grids at the Rocky Mountain Institute, a nonprofit focused on decarbonization.

��What they��re saying is, ��We already consider them but don��t make us show you how,���� she said.

The other major exemption PJM wants deals with battery storage resources and what grid upgrades are needed to accommodate them. Some grid operators, including PJM, want to continue to use a worst-case assumption �� that the batteries will charge at times of peak electric demand. That flies in the face of the economic model for grid-connected batteries, which seek to charge when prices are low and discharge when they spike.

��Assuming that storage will charge during a time of peak load is one of those worst-case conditions even though it��s antithetical to the action it will take in the market,�� Siegner said. And even if PJM was concerned about that happening, it could write a prohibition into an interconnection agreement, rather than requiring storage developers to pay for expensive grid upgrades that might never be needed, she added.

��It��s just a nonsensical way of studying these resources that has to change,�� Siegner said.

The bigger problem, said Summers of the Citizens Utility Board, is that at PJM, fossil fuel generators, big utilities and transmission companies hold a lot of sway.

��Many of these companies came of age in the fossil fuel era and their incentives are to try to prevent the fossil fuel transition or make it as expensive as possible. PJM has a pattern of dragging its feet on the energy transition,�� Summers said.

Indeed, how PJM is governed and how stakeholders are voting in lower level meetings is drawing increasing scrutiny from state lawmakers. Four blue state governors with decarbonization goals also recently called for a ��robust process for states to engage with PJM�� on planning decisions.

And for many of PJM��s critics, the fact that projects have made it through the queue but haven��t gotten built doesn��t excuse the mess the interconnection process has become.

��PJM must take responsibility for its role in establishing and maintaining an effective interconnection process,�� Siegner said. ��The faster that interconnection requests are processed, the easier it is to get financing and navigate supply chain hurdles. It��s a lot harder if you��re waiting in the queue for five years and you have no idea what your network upgrade costs will be.��

Nanette Mahler, left, and Tracy O��Neill, walk along Macon Wall Road in Cheatham County, Tennessee, near the site of a proposed Tennessee Valley Authority gas power plant project. Local backlash against the proposal comes as the federal utility faces bipartisan legislation in Congress seeking to boost transparency in its planning process and scrutiny of TVA��s anemic renewable power growth compared to other utilities. (By Robert Zullo/ States Newsroom)

ASHLAND CITY, Tenn. �� When he heard about the sale, Kerry McCarver was perplexed.

In 2020, the mayor of rural Cheatham County discovered that the Tennessee Valley Authority bought about 280 acres of rolling farmland ��in the middle of nowhere�� in his county, which lies just west of Nashville and is home to about 42,000 people.

He asked another county official who formerly worked for the TVA, the nation��s largest public power company, to find out what it planned to do with the land.

The answer they got was ��future use,�� and they speculated a solar farm might be in the works.

��It��s kind of the last we thought about it,�� McCarver said during an interview in his office in May. ��Then a year ago last summer, TVA called here needing a place to have a public meeting.��

The authority was now proposing a 900-megawatt natural gas-fired power plant, battery storage, pipelines and other associated infrastructure for the site, which came as a shock to McCarver and many other locals who felt it was wholly inappropriate for the area.

��I called the county attorney and said ��What��s our options?�� McCarver said. The answer he got: ��It��s TVA. You don��t have any options.��

Opposition to the Cheatham County project dominated a public ��listening session�� of the TVA��s Board of Directors in May, when TVA officials told States Newsroom that the proposed plant is in the early stages of development and just one potential option to meet growing power demand in the region and replace retiring coal power.

��We understand that some members of the Cheatham County community do not view this location as appropriate for a new generating site, and we respect that viewpoint,�� TVA spokesman Scott Fiedler said in late June. ��No decisions have been made.��

However, the backlash comes as the federal utility faces bipartisan legislation in Congress seeking to boost transparency in its planning process as well as its management and salary structure. TVA has also been in the crosshairs of green groups over its planned gas power buildout, which is among the largest proposed in the nation, and anemic renewable power growth compared to other utilities.

��Back when it was created in the 1930s, TVA was on the cutting edge of transforming a region of the country and investing in a lot of infrastructure to create that transformation,�� said Amanda Garcia, an attorney with the Southern Environmental Law Center who has worked on TVA issues for a decade.? ��We��re just not seeing that happen now.��

��Clearly a laggard��?

Created by Congress in 1933 during the Great Depression, the TVA today provides wholesale electricity to 153 local power companies serving 10 million people in Tennessee and parts of six neighboring states.

The authority is replacing major coal-fired units at its Kingston (site of a massive coal ash spill in 2008) and Cumberland plants with gas generation and is planning to retire all of its coal power fleet by 2035. It has set a goal of 10 gigawatts of solar power by 2035 and boasts that 55% of its electric generation is carbon free, most of it hydroelectric and nuclear power. And TVA President and CEO Jeff Lyash says a little less than half of the 10 gigawatts of solar it wants to put in by 2035 is already ��in operation or in development and construction.��

For comparison, though, utility giant Duke Energy had more than 10 gigawatts of solar installed across its 16-state footprint as of 2022. Environmental and clean power groups say TVA, a federal nonprofit power company, could be doing much more to advance a transition to cheaper, cleaner power.

��They, unlike many utilities, have the ability to do big things and do big things faster,�� said Daniel Tait,? executive director of Energy Alabama, a clean energy advocacy organization, and a research and communications manager for the Energy and Policy Institute, a utility watchdog group.

Tait and others say TVA��s leadership has been historically dismissive of the role renewable power can play on the grid.

��TVA is clearly a laggard when it comes to renewable energy,�� said Stephen Smith, executive director of the nonprofit Southern Alliance for Clean Energy who has served on TVA advisory panels in the past. ��Florida Power & Light has deployed more solar in a quarter than TVA has in their whole history.�� Smith, who joked that he��s been ��beating his head against the gates of TVA since 1993, said the authority was created to ��lead on big national issues�� but isn��t living up to its legacy.

��They��re not demonstrating leadership on renewables, they��re not demonstrating leadership on energy efficiency. They��re not demonstrating leadership on (battery) storage,�� he said, partly the result of what he called an ��institutional bias�� against renewable power.

TVA officials reject that notion, with a spokesman telling States Newsroom that TVA is a ��clean energy leader.��

However, Lyash acknowledged at the May board meeting that supply chain challenges brought on by the pandemic, inflation, difficulty securing land for solar and the TVA��s own interconnection delays (it also runs the electric grid in its service area) have created snags.

��We��re not satisfied. We��re? going to revise our processes,�� Lyash said. ��We��re taking a hard look at how we can accelerate the deployment of clean energy assets. It will be a focus of ours in the coming year.��

In an interview, Lyash said the TVA is pursuing new initiatives to advance solar development,? like its pilot Project Phoenix, which would put solar panels on closed coal ash sites.

��If this is successful, and it looks like it will be, this will be replicated across our whole system,�� Lyash said.

An ��incredibly weak board’

Still, TVA, which now has a board largely appointed by President Joe Biden, remains out of step with the president��s own aggressive power sector decarbonization goals, green groups note. (The Sierra Club gave the TVA an ��F�� last year on its latest ranking of how well utilities are living up to their own decarbonization goals and transitioning to cleaner power).

��There��s a lot of room for the Biden administration to deepen their relationships with TVA,�� said Garcia, the SELC attorney. ��If the largest federal utility isn��t even coming close to that, then how can we have hope that we��re going to achieve that target to decarbonize the grid?��

The White House did not respond to an inquiry on TVA��s gas buildout or additional appointments to the board (two members appointed by former President Donald Trump saw their terms expire earlier this year.) Another Biden nomination for the TVA board has been before a U.S. Senate committee since January. TVA��s nine-member board is supposed to be its chief regulator, since TVA does not answer to state utility commissions in its territory. But, critics note, the board is part time, lacks its own staff and usually defers to the TVA executive leadership on big decisions like power plant construction.

Smith called it an ��incredibly weak board led by an executive staff that��s accountable to no one,�� adding that reformers have pushed for the TVA board to attend meetings of the National Association of Regulatory Utility Commissioners and hire their own staff.

��I don��t know how a part-time board with no staff? and no technical capabilities can review something like an integrated resource plan effectively,�� said Dave Rogers, deputy director of the Sierra Club��s ��Beyond Coal�� campaign.

The TVA��s long legacy in the South?

In the U.S. electric utility landscape, there��s really nothing like the Tennessee Valley Authority Created by an act of Congress in 1933 as the nation was mired in the Great Depression, the authority was tasked with, among other jobs, taming flooding and improving navigation along the Tennessee River, reforesting lands, erosion control for farmers, malaria prevention and electric power production, initially through a network of dams and hydroelectric plants.

��This in a true sense is a return to the spirit and vision of the pioneer,�� President Franklin D. Roosevelt said in a message to Congress asking for legislation to create the TVA. The authority looms large in the lore of the region as a result of the surge in economic development and living standards it unleashed in what had been one of the most impoverished parts of the country. Average yearly income in the Tennessee Valley was about $168 in 1933, half the national average at the time.

��The most dramatic change in Valley life came from the electricity generated by TVA dams,�� the National Archives notes. ��Electric lights and modern appliances made life easier and farms more productive. Electricity also drew industries to the region, providing desperately needed jobs.�� During a tour of the area after the TVA��s creation, the journalist Lorena Hickok wrote in a field report to the Roosevelt administration that ��a promised land, bathed in golden sunlight, is rising out of the gray shadows of want and squalor and wretchedness down here in the Tennessee Valley these days.��

Indeed, not too many electric utilities get a shout out in smash country songs.The Bob McDill-penned ��Song of the South,�� which became a hit for the band Alabama in 1989, also speaks to TVA��s legacy: ��Cotton was short and the weeds were tall, but Mr. Roosevelt gonna save us all. �� Papa got a job with the TVA. We bought a washing machine and then a Chevrolet.��

There was a darker side to all that progress, however. Thousands of people across the region were displaced and in some cases entire towns were flooded, creating a number of what the Tennessee State Museum calls ��underwater ghost towns.��

Today, the authority has about 10,000 employees, a budget of more than $12 billion, 29 hydroelectric plants, four large coal plants, three nuclear power plants and 17 natural gas plants, among other assets, and has one of the largest transmission systems in North America �� 16,400 miles of lines covering 80,000 square miles.. It still plays a major role in economic development, but also has suffered some very public black eyes over the years, including a devastating coal ash spill in 2008 and subsequent litigation alleging the workers who cleaned it up, many of whom have since fallen ill and died, were not adequately protected. The TVA was also forced to implement its first-ever rolling blackouts in 2022 during Winter Storm Elliott as fossil fuel plants tripped off line. Since then the TVA has spent more than $123 million on winterization upgrades at the plants and made it through its highest ever peak demand during a cold snap last winter without any blackouts. – Robert Zullo

��More transparent��?

A big part of the problem for TVA��s would-be reformers is the so-called integrated resource planning (IRP) process. Though the process varies by state and regulatory regime, many utilities across the country file IRPs with state regulators that lay out forecasts for electric demand and outline how they intend to meet their obligations to customers, including what generation and transmission projects they are likely to build under different scenarios. The process provides an opportunity for ratepayer advocates, environmental groups and large industrial customers, among other intervenors, to challenge utility assumptions about demand growth and the best and cheapest way to provide electric service.

TVA does compile an IRP, and it handpicks a working group of outsiders (who are asked to sign non-disclosure agreements, participants say) to advise on the plan. The last one was published in 2019. The current process has been paused in part because of new power plant carbon rules by the Environmental Protection Agency.

But bipartisan legislation introduced in Congress earlier this year by Tennessee Reps. Steve Cohen, a Memphis Democrat, and Tim Burchett, a Republican from the Knoxville area, is intended to pry open the TVA planning process. The bill would create an Office of Public Participation to ��facilitate a process for meaningful and open public engagement �� including opportunities for intervention, discovery, filed comments and an evidentiary hearing,�� among other duties, a news release says. The bill would also direct TVA to include standard information about long-term sales and peak demand forecast, a summary of transmission investments, scenarios that ��fairly evaluate demand-side and supply side technologies,�� disclosure of modeling assumptions and analyses of fuel costs and environmental regulations, among other requirements.

Crucially it would also require the TVA board to ��issue a decision approving, denying or modifying the plan, like every other utility regulator.��

Burchett and Cohen also introduced legislation that has passed the House and is currently in the Senate that would reinstate the TVA��s annual reporting requirement to Congress on executive and top manager compensation. In May, the TVA board voted separately to restructure its executive pay practices, cutting incentive-based compensation and changing the severance plan. (Lyash earned $10.5 million in 2023, making him the highest paid federal employee.)

��We��re trying to get them more and more transparent and give them some solid guidelines,�� Burchett said in an interview. ��If we say we��re going to let them do it, it��s not going to happen.��

Burchett, who added that TVA had become ��too big and arrogant for their own good,��? said he and Cohen have been friends since their days in the Tennessee legislature.

��We might not agree on a lot of policy things,��? he said. ��But public input and transparency are a couple of things we really agree on.��

Multiple attempts to reach Cohen for an interview were unsuccessful.

At the May meeting several board members acknowledged the need to improve transparency, including in publicizing lists of large capital projects approved during the budget process, and speeding up clean power projects.

��I also know that we need to go further, faster on our renewable energy goals,�� Board Member Beth Geer said. Joe Ritch, the chair, said the board will ��continue to review our governance processes and make changes and updates as appropriate.��

��Everybody wins��

And while representatives of many of TVA��s local power companies showed up at the May listening session to voice support for the authority��s power plant buildout, others have some frustrations with the authority.

Most notably, Memphis Light, Gas and Water in 2022 refused to ink a new long-term contract with TVA, opting for a five-year rolling deal. It had been exploring leaving the authority as local groups pushed for cheaper and cleaner power. (Memphis LG&W turned down an interview request to discuss the contract situation.) Fiedler, the TVA spokesman, said 147 of the authority��s 153 local power companies have signed the long-term contracts.

The Southern Environmental Law Center, on behalf of several environmental groups, sued over the contracts, arguing the ��never-ending�� deals would ��forever deprive distributors and ratepayers the opportunity to renegotiate with TVA to obtain cheaper, cleaner electricity.��

A judge dismissed the suit last year, finding the groups lacked legal standing. The contracts allow local power companies to build local generation resources like solar to meet up to 5% of their average electric needs but some argue TVA should be allowing more..

��It should be 10%,�� said Gil Hough, executive director of TenneSEIA, a state affiliate of the national Solar Energy Industries Association. (Nashville Electric Service��s CEO said the cap should be 15%). Hough said local power companies can often get projects done faster than the TVA and the new generation, especially solar and battery storage, helps mitigate TVA��s concerns about growing electric demand.

Hough cited a partnership between Huntsville Utilities and Toyota in Alabama that will build a 30-megawatt solar system to power about 70% of a local Toyota engine plant as a prime example. The Huntsville Business Journal reported that it was the first time the local utility, taking advantage of the new 5% local generation flexibility option, would be buying power from ��someone besides TVA.��

��Everybody wins,�� Hough said. ��Regular ratepayers win. Economic development. TVA doesn��t have to add more generation. Solar developers win.��

��You feel helpless��

Both Tracy O��Neill and Nanette Mahler describe themselves as Nashville ��refugees�� who were seeking peace and quiet when they moved out to Cheatham County. Now, though, growing power demand in Middle Tennessee is a big part of TVA��s rationale for the gas plant, pipelines and transmission infrastructure proposed for Cheatham.

��They��re taking from us to give to other people,�� Mahler said.

The neighbors aren��t aligned politically (Mahler is a conservative and O��Neill a liberal environmentalist) but they��ve bonded over their mutual dread of the proposed power plant. Both live close to the site and gave a reporter a tour of the area, a collection of old farmsteads and sparsely situated single family homes along narrow country roads.

��Who would have ever thought they��d come out here and do this?�� Mahler said.

They��re both members of Presvere Cheatham County, a local group formed to oppose the project and the massive disruption they fear construction and operation of the plant will bring: heavy truck traffic, pollution, noise and light and wear and tear on flood-prone local roads, among other impacts.

Despite TVA��s assertions that the project is in the early stages and alternatives are being considered, Mahler said TVA��s contractors are telling locals it��s a ��done deal.��

Both fault TVA for what they say was limited outreach to neighbors.

��It feels like they have been intentionally secretive,�� O��Neill said. ��It��s just heartbreaking to think that all of this will be destroyed.��

That feeling of powerlessness extends to McCarver, their mayor, who said the county welcomes industrial development, but only where it makes sense.

��They don��t have a snowball��s chance to get rezoned for something like that in that area,�� he said. ��They just come in as the thousand pound gorilla having their way without having to ask anybody or tell anybody or even work with those neighbors or that community out there.��

State and federal elected officials haven��t been much help, he added. And offers by the county to purchase the land from TVA have been fruitless. The only thing that might derail the project, McCarver added, is some adverse finding during the environmental review that will come if the plant moves forward. TVA��s been under fire for ignoring the Environmental Protection Agency��s critiques of its plans to replace coal-fired units at its Kingston plant with gas generation. The EPA said in a review of the draft environmental impact statement for the plant that TVA fell short in a number of ways, including not evaluating enough alternatives, lapses in cost calculations and other deficiencies. The agency asked TVA to prepare a supplemental analysis, which TVA didn��t perform.

��We appreciate the input from EPA as a cooperating agency in the EIS process, which was completed with the release of the record of decision,�� Fiedler, the TVA spokesman said.

For McCarver, the past year of dealing with TVA��s proposed gas plant in Cheatham has been ��a horrible experience�� that��s made him painfully aware of the authority��s unique powers as a federal entity.

��I��ve always dealt politically with ��not in my backyard.’ This is not a ��not in my backyard�� situation,�� the mayor said ��Their area will never be the same. �� You feel helpless.��

Congress needs to rein in the TVA, and forcing it to follow local zoning would be a good start, McCarver said.

��They put up a good front. They do a good tap dance. But at the end of the day, the feeling is �� they��re going to do what they want to and how they want to do it and when they want to do it, and hopefully you won��t be in their way,�� he said. ��Nobody should be that powerful. Why is TVA that powerful?��

This map from the Federal Energy Regulatory Commission shows planned locations for CP2, a a giant liquefied natural gas export terminal on the Gulf Coast of Louisiana and an associated pipeline. FERC issued crucial approvals for the projects Thursday. (Photo courtesy of FERC)

A massive and contentious liquefied natural gas export project in coastal Louisiana and an associated pipeline got a key approval from federal regulators Thursday.

The Federal Energy Regulatory Commission issued an order granting permission for Venture Global to build and operate the CP2 terminal in Cameron Parish along the Gulf Coast and construct and operate the CP Express Pipeline connecting the terminal to the gas pipeline network in east Texas and southwest Louisiana. Earthjustice, an environmental law group, said the terminal would ��export more liquefied methane gas than any U.S. terminal ever approved.��

Commissioner Allison Clements, who was taking part in her last meeting on the commission after she opted not to seek another term, was the lone dissent. Clements has consistently urged the commission to more fully vet greenhouse gas emissions from natural gas projects.

��The commission has not adequately addressed the project��s environmental and socioeconomic impacts, including adverse impacts on environmental justice communities,�� Clements said.

��These projects will have enormous emissions of greenhouse gasses equivalent to putting more than 1.8 million new gas fueled cars on the road each year. The order does not meaningfully assess those emissions.��

The project will still need an air permit from the Louisiana Department of Environmental Quality and other permits, and it cannot begin exporting gas to countries lacking free-trade agreements (which constitute about 90% of the global liquified natural gas market) without authorization from the U.S. Department of Energy, the Sierra Club noted.

President Joe Biden��s administration implemented a pause on LNG export approvals in January in order to allow the DOE to update its authorization analyses.

��Today, we have an evolving understanding of the market need for LNG, the long-term supply of LNG, and the perilous impacts of methane on our planet,�� the White House said at the time. ��We also must adequately guard against risks to the health of our communities, especially frontline communities in the United States who disproportionately shoulder the burden of pollution from new export facilities.��

In April, 25 Republican governors called on the administration to end the freeze.

��It creates instability and threatens future energy security throughout the world at a time when our allies need us the most. It sends a message that the U.S. is not a reliable energy partner,�� they said in a statement released by the Republican Governors Association.

In a statement reported by an industry publication, Venture Global��s CEO applauded ��the commission and FERC staff for their independent and thorough review and approval of CP2 LNG.��

Friends of the Earth, an environmental group, called the CP2 terminal a ��carbon bomb�� and the Sierra Club said CP2 is a ��disastrous project that puts polluters over people.��

The terminal is planned next to the existing Venture Global Calcasieu Pass LNG facility that has already racked up air pollution violations and about two miles from the proposed Commonwealth LNG facility. The Sierra Club noted that the area ��has more low-income residents than 88% of the country.��

In a news conference after the FERC meeting, Chairman Willie Phillips, who voted to approve the project, said he��s made environmental justice, which aims to protect low income and minority communities from polluting infrastructure projects, a priority.

��I believe we have a duty to those communities. We also have a duty to abide by the law,�� Phillips said, adding that FERC��s evaluation of environmental impact goes ��above and beyond�� what��s required by the National Environmental Policy Act. The order, he said, has ��over 130 conditions regarding public safety, engineering and environmental impacts.��

The Sierra Club said that while FERC has acknowledged the need to do more to protect overburdened communities from environmental injustices, ��it will take more than lip service, and this approval is a clear step in the wrong direction.��

High voltage power lines run along the electrical power grid on May 16, 2024, in West Palm Beach, Florida. The U.S. Senate approved three of President Joe Biden��s nominees to serve on the nation��s top energy regulatory panel this week. Industry, renewable power and environmental groups cheered the vote on the new members of the Federal Energy Regulatory Commission. (Joe Raedle/Getty Images)

Three nominees by President Joe Biden to serve on the nation��s top energy regulatory panel, which had risked losing a quorum, were approved this week by the U.S. Senate.

The vote to approve the new members �� two Democrats and a Republican �� for the Federal Energy Regulatory Commission was cheered by industry, renewable power and environmental groups alike, who said a full a complement of commissioners is essential to the body meeting the challenges posed by an aging electric grid, a fast-shifting generation mix and debates over natural gas infrastructure, among other pressing energy issues.

��We are pleased to see FERC will be restored to a full roster, which will help provide regulatory certainty and the attention needed on key questions impacting our nation��s energy systems,�� said Todd Snitchler, president and CEO of the Electric Power Supply Association, or EPSA, which represents companies that own power plants in competitive electricity markets.

��Having a full complement of five commissioners will allow FERC to keep advancing the vital work needed to deliver reliable, affordable and clean power to everyone around the country,�� said Ted Kelly, director of clean energy at the nonprofit Environmental Defense Fund.

FERC, which regulates interstate transmission and wholesale sales of electricity, as well as interstate transmission of natural gas and oil, among other responsibilities, ��rarely shows up on people��s radar screens,�� said Senate Majority Leader Chuck Schumer, D-N.Y. ��But its mission is essential. Every time you turn on the light or touch the thermostat or see new power lines go up, the rules, regulations (and) policies of FERC are at work.��

Leaving the seats vacants, Schumer said, ��could create serious backlog and delay, potentially slowing down new projects that power people��s homes and cites.��

The new commissioners are: David Rosner, a Democrat and FERC energy industry analyst; West Virginia Solicitor General Lindsay See, a Republican who led the state��s successful legal fight against the Environmental Protection Agency��s carbon rules; and Judy Chang, a Democrat, energy economist and the former undersecretary of energy and climate solutions for the Commonwealth of Massachusetts. She is also an adjunct lecturer and senior fellow at Harvard��s Kennedy School.

They join Chairman Willie Phillps, a Democrat, and Commissioner Mark Christie, a Republican. Commissioner Allison Clements, a Democrat, announced earlier this year she would not seek a second term. 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.

Though the commission will maintain a 3-2 Democratic majority, at least one environmental group has been critical of Rosner��s selection.

Friends of the Earth called Rosner��s fossil fuel ties ��disqualifying�� and blasted his work with the Senate Energy and Natural Resources Committee, headed by the powerful and pro-coal Sen. Joe Manchin, of West Virginia who in May switched his registration from Democrat to independent. Manchin recommended Rosner, who was also previously a senior policy advisor at the U.S. Department of Energy and an associate director at the Bipartisan Policy Center��s energy project, for the commission seat last year, Politico��s E&E News reported. The Koch Industries-linked American Energy Alliance has also criticized Chang��s past opposition to new natural gas pipelines. But for the Senate, at least, the relatively smooth confirmation process appeared to show that having a full complement of commissioners was preferable to picking fights over individual nominees.

��We all know that having a fully staffed FERC is going to make a lot of difference in what we do in this country,�� Manchin told his colleagues Tuesday, adding that each of the nominees had cleared his committee with ��extremely strong�� bipartisan support.

��Each of the nominees demonstrated deep experience on energy and legal matters, a commitment to follow the law and work within the authorities Congress has provided to FERC? and a recognition that all of our nations�� sources play an important role providing affordable, reliable energy to families and businesses across our country.��

Sen. John Barrasso, a Republican from Wyoming and the ranking member on the Energy and Natural Resources Committee, noted that FERC went for seven months without a quorum during the Obama administration, putting many projects ��that help keep the lights on, help heat our homes and aid our allies abroad�� on hold.

��While I may not agree with each of the nominees on all the items all the time, all of them are well qualified,�� he said.

An aerial view shows high voltage power lines on May 16, 2024, in West Palm Beach, Florida. Twenty-one states are joining a push by President Joe Biden��s administration to modernize the nation��s aging electric grid, which is under pressure from growing demand, a changing mix of power generation and severe weather. (Photo by Joe Raedle/Getty Images)

Twenty-one states, including Kentucky, are joining a push by the Biden administration to modernize America��s aging electric grid, which is under pressure from growing demand, a changing power generation mix that includes lots of wind and solar and severe weather.

The administration, which has set a goal of a carbon-free power sector by 2035, announced Tuesday that the states had joined what it called the ��Federal-State Modern Grid Deployment Initiative,�� which is intended to ��help drive grid adaptation quickly and cost-effectively to meet the challenges and opportunities that the power sector faces.��

In exchange for federal technical and financial assistance opportunities, participating states will ��prioritize efforts that support the adoption of modern grid solutions to expand grid capacity and build modern grid capabilities on both new and existing transmission and distribution lines.��

That means in part focusing on ways to get more out of existing transmission lines, since building new ones can take a decade or more in some cases.

��There are technologies we can use to optimize the current infrastructure we have,�� said Verna Mandez, director of transmission at Advanced Energy United, a clean energy trade group.

Those include reconductoring existing lines to handle more juice as well as so-called grid-enhancing technologies, a suite of tools that include sensors, power-flow controls, software and hardware that can better deliver real-time weather data, among other technologies.

In many cases, those technologies have been adopted in other countries but uptake has lagged here, in part because utilities aren��t incentivized to adopt them and generally don��t face consequences as a result of grid congestion, which costs electric customers billions of dollars each year.

��Most transmission providers get more money when they build transmission projects,�� Mandez said.

The White House said in a news release that adopting newer technologies ��means that renewables and other clean sources of power can be integrated sooner and more cost-effectively than waiting for new transmission construction, which will address load growth challenges more rapidly, create good-paying jobs and lower Americans�� utility bills.��

The Federal Energy Regulatory Commission has also in several orders prodded utilities and grid operators to consider more use of grid-enhancing technologies.

And some states are taking action on their own. Virginia, which did not join the initiative announced Tuesday, passed legislation signed by GOP Gov. Glenn Youngkin that requires utilities to consider grid-enhancing technologies in their planning. Last year, Montana passed legislation aimed at increasing use of advanced reconductoring. Minnesota��s legislature also voted this month to add grid-enhancing technologies to the state��s transmission planning process and require some utilities to evaluate the tools for highly congested lines.

��More tools than ever��

To get a more reliable and cleaner electric grid, as well as accommodate electric demand that��s growing for the first time in more than a decade,? the U.S. needs lots of new transmission capacity, experts agree.

Last year, the U.S. Department of Energy found that almost all regions of the country would benefit from more transmission lines and a National Renewable Energy Laboratory study estimated that getting to 100% carbon-free electricity by 2035 could require anywhere from 1,400 to 10,100 miles of new high capacity transmission lines per year starting in 2026.

That��s why the Biden administration has been pushing hard to remove roadblocks to new transmission lines, which can take a decade or more to develop in some cases, and the Federal Energy Regulatory Commission published a landmark new rule on regional transmission planning and cost allocation. Last month the administration also announced a public-private partnership to upgrade 100,000 miles of transmission lines over the next five years and the Department of Energy has identified 10 potential ��national interest�� electric transmission corridors, a designation that would help expedite the projects and give developers access to federal financing.

��The power sector, which is responsible for a quarter of annual U.S. greenhouse gas emissions, now has more tools than ever �C including unprecedented financial support, efficient permitting, and long-term regulatory certainty �C to reduce pollution and upgrade the grid to support more factories, electric vehicles and other growing sources of electricity demand,�� the White House said.

The states joining the effort are Arizona, California, Colorado, Connecticut, Delaware, Hawai��i, Illinois, Kentucky, Maine, Maryland, Massachusetts, Michigan, New Jersey, New Mexico, New York, North Carolina, Oregon, Pennsylvania, Rhode Island, Washington, and Wisconsin.

A solar and battery storage development operated by Entergy in Searcy, Arkansas. Solar power growth is expected to help some parts of the country meet electric demand this summer. (Robert Zullo/ States Newsroom)

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 last week. 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 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.

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.��

Electric power lines are seen attached to transmission towers on Sept. 28, 2023, in the Everglades, Florida. The Federal Energy Regulatory Commission on Monday issued a long-awaited overhaul of how regional electric transmission lines are planned and paid for. (Photo by Joe Raedle/Getty Images)

A divided Federal Energy Regulatory Commission on Monday 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.

Southwest Power Pool runs a portion of the American electric grid that runs from the Canadian border to Texas and includes all or part of 17 central and western states. The organization has successfully integrated thousands of megawatts of variable wind power into its system. (Courtesy of Southwest Power Pool)

A little more than two years ago, a clean energy record was broken. For the first time, a regional transmission organization met more than 90% of its electric demand, called load, with renewable power.

But if you don��t follow the electric industry closely, you might be surprised where it happened.

On March 29, 2022, Southwest Power Pool, based in Little Rock, Arkansas, and the grid operator for a red-state heavy portion of the central U.S., hit a renewable penetration level of 90.2%, almost all of it from wind power.

��In a decade��s time, our region has gone from thinking of 25% renewable-penetration levels as nearly unreachable to a point where we regularly exceed 75% without reliability concerns,�� said Bruce Rew, SPP��s vice president of operations, in a news release.

Growing electric demand, major coal plant closures and more wind and solar power have been seen by some policymakers, regulators and clean power critics as harbingers of a coming electric reliability crisis.

During a campaign event last year in Iowa �C which got more than 64% of its electricity from wind turbines in 2022 �C former President Donald Trump criticized intermittent power and mused about a couple unable to watch TV because the wind wasn��t blowing. The Project 2025 plan organized by the conservative Heritage Foundation for a future GOP administration said? President Joe Biden��s carbon reduction targets, as well as corporate and state clean power goals, ��have thrust the United States into a new energy crisis,�� including a less reliable grid.

However, in parts of the country that are home to tens of millions of people, grid operators every day are finding that a cleaner electric grid isn��t necessarily a less reliable one, though it does come with new problems to solve.

��The future is already here, it��s just unevenly distributed,�� said Ric O��Connell, executive director of GridLab, a nonprofit that provides technical assistance to renewable power advocates and regulators on electric grid issues.

��Some kind of magic amount��

Nationwide, wind and solar accounted for a little more than 14% of utility-scale electric generation in 2023, according to the federal Energy Information Administration. But in Texas, California and the states that make up SPP, among other areas, the amount of renewable power on the grid at any given time is often much larger.

California has seen wind, solar and hydropower production exceeding 100% of demand in some cases for hours at a time in the area managed by the California Independent System Operator.

The Electric Reliability Council of Texas, which runs most of the Texas electric grid, has also been setting new renewable penetration records.? At 2:13 p.m. on March 29, nearly 76% of the generation on the system was renewable, mostly wind and solar.

��I think it��s really important to recognize that we get to these points in time on the grid that we get to these extremely high levels of renewables and the lights are not going out,�� said Elise Caplan, vice president of regulatory affairs at the American Council on Renewable Energy, a nonprofit representing renewable developers, investors, manufacturers, utilities, corporate power buyers and other firms.

However, it��s important to note that those records being set are snapshots at certain times. As some experts have pointed out, traditional power plants still need to run even when renewables are surging to balance that variability. And, of course, the wind isn��t always blowing and the sun isn��t always shining. For perspective:? Averaged out over the year, wind was about 37% of the Southwest Power Pool��s generation mix in 2023, with natural gas and coal power plants accounting for about 54% and hydropower and nuclear making up the rest.

But the numbers do show that grid operators are successfully integrating renewable power at thresholds that were thought unworkable not so long ago.

Michael Milligan, an independent power consultant who spent more than two decades focusing on wind and solar integration at the National Renewable Energy Laboratory, where he was the lab��s principal researcher before retiring, said utility engineers in years past routinely assumed there were limits on how much intermittent power the grid could handle, usually a ��single digit percent.��

��There was kind of a sense that once we get beyond some kind of magic amount it��s going to get too difficult,�� he said. ��Actual experience is really valuable.��

Fifteen years ago, ��nobody thought we��d have the amount of penetration we have today,�� said Howard Gugel, vice president of regulatory oversight for the North American Electric Reliability Corporation, which develops and enforces standards for the power system. But the growth in wind, solar and batteries �C also known as inverter-based resources because they convert electricity from direct current to alternating current to send the power onto the grid �C has posed new reliability concerns.

Inverter-based resources lack the heavy rotating generators at traditional power plants, which are generally synchronized to the grid frequency of 60 Hz, said Greg Brinkman, an engineer in the grid operations planning group at the National Renewable Energy Laboratory. The natural inertia those synchronous generators provide can help them through grid disturbances without incident, whereas inverter-based resources need software and programming to do so.

Gugel said NERC has reviewed several incidents in which grid ��perturbations�� caused several inverter-based plants, generally solar, to trip off at the same time. ��That began to give us some concerns,�� he said.

Last year, the Federal Energy Regulatory Commission directed NERC to come up with reliability standards for inverter-based resources, which the organization is currently developing.

��We have a lot of clean energy and renewable energy resources that are being connected to the grid and this new rule is a great step to address what we see as reliability concerns regarding this transition,�� FERC Chairman Willie Phillips said in October. ��When appropriately programmed, IBRs can provide operational flexibility and the ability of IBRs to perform with precision, speed and control could mitigate disturbances on the bulk power system.��

Transmission as ��a great enabler’

Rew, the senior vice president at Southwest Power Pool, which has members in 14 states and about 18 million people living in its footprint, said in an interview that production tax credits helped incentivize a surge of wind power development, which also pushed technological advances that increased the operating capabilities of the turbines, including increased ��cut-out�� speeds, the wind speed at which the turbine needs to shut down to avoid damage.

A major regional transmission planning and expansion process the organization embarked on in the late 2000s helped knit together what had been a collection of systems individually built for numerous individual utilities and positioned the organization to accommodate large amounts of wind generation.

��These regional projects really opened up transmission constraints and allowed us to operate as a single unit a lot better.That provided us the opportunity to really dispatch throughout the system and allowed us to get additional renewables transferring all around the system,�� Rew said.

It was a forward-looking approach that is still paying dividends, he added.

��I think in a lot of ways we were visionary in recognizing what transmission could do as a great enabler,�� Rew said. ��It enables us not only to have greater reliability because we don��t have the transmission constraints and limitations that we did before but also greater economics and just? greater use of all the generation in the footprint.��

Of course, having large amounts of variable power also comes with challenges. SPP has about 33,000 megawatts of ��nameplate�� wind capacity, meaning the maximum amount those turbines can generate at optimal conditions. Even though Rew said the SPP region has some of the best wind resources in the world, it runs below that maximum output as a result of outages, differing wind speeds and other factors. That means wind and weather forecasting becomes even more critical to managing the grid. A drop in wind speeds, or an icing event, can mean losing thousands of megawatts of generation quickly. That��s a problem because supply and demand on electric grids need to be balanced in real time to avoid issues that can lead to blackouts or other calamities.

��We��re able to look out 10 days and project what the wind��s going to be, project what the load is going to be and be able to prepare our system to be able to operate with those changes,�� Rew said. ��There��s a lot that goes into making it successful every day.��

SPP��s electric markets also play a crucial role, since traditional power plants like gas and coal need incentives to be available when needed even though they might be running less often or at reduced output.

��That��s what we��re looking at for our market in terms of how we price the services that are necessary to maintain a reliable system and making sure that, one, we have market products that reflect what we��re using for grid operations,�� Rew said. ��And, two, that we have a pricing mechanism that appropriately compensates them for those services.��

The grid of the future

For the parts of the country that are lagging in renewable power, adding transmission is seen by clean energy advocates as a major piece of the puzzle.

��There is no perfect resource,�� said Caplan, the vice president of regulatory affairs at the American Council on Renewable Energy. The most recent high-profile power grid crises were the result of fossil fuel power plants, mostly gas powered, failing to perform in cold weather, either because of inadequate weatherization or fuel shortages. Wind and solar are weather dependent, but the increasing surge in battery power helps smooth out those variances, storing juice when it��s needed. And transmission lines can create a grid bigger than the weather.

��We recognize that those resources are not always available but through this growth of storage and especially through the growth of transmission you can access renewables across a broader geographic area,�� Caplan said.

That��s why a lot of eyes will be on a long-awaited rule from FERC expected to come next week that is intended to address thorny debates over regional transmission planning and how costs for new lines are allocated. Rew, the SPP executive, noted that with SPP��s high quality wind resources, developers outside the footprint might have to build twice as many turbines to get the same power output. Does it make sense to do that to meet, for example, a state renewable energy goal? Or is it better to build where the wind is stronger and use long transmission lines to get the power to where it��s needed?

��It doesn��t make sense for our ratepayers to pay for that in SPP, to export wind out for somebody else to get the benefit,�� he said ��So how do we do that from a national perspective?��

Groups like ACORE want a national planning rule that recognizes that? ��an expansion of the nation��s grid is necessary to reliably and affordably accommodate new generation and improve reliability in the face of increasing severe weather events and wildfires.�� They want broader accounting of the full benefits of transmission, ��a mechanism to determine a cost allocation method when the states are unable to agree��? and other pro-renewable provisions. However, conservatives, including FERC Commissioner Mark Christie, a former Virginia utility regulator, have chafed at what they characterize as an attempt to force others to pay for the policy decisions of states that are pushing renewable power.

��It would be grossly unfair for FERC to force consumers in other states to pay for projects implementing the policies of politicians they never got the chance to vote for, when their own states�� policy-makers have not agreed to pay for those projects,�� Christie wrote in response to a letter from four New York congressmen. ��Such an imposition is contrary to American principles of democracy, a core principle of which is that the people have the right to elect the policy-makers who impose costs on them, so the people can hold them accountable.��

AES Indiana��s Petersburg Generating Station in Petersburg, Indiana, has been burning coal since the 1960s but will shutter all of its coal-firing units over the next few years. The U.S. Environmental Protection Agency on Thursday released a sweeping set of rules aimed at cutting air, water and land pollution from fossil fuel-fired power plants. (Robert Zullo/States Newsroom)

The U.S. Environmental Protection Agency on Thursday released a sweeping set of rules aimed at cutting air, water and land pollution from fossil fuel-fired power plants.

Environmental and clean energy groups celebrated the announcement as long overdue, particularly for coal-burning power plants, which have saddled hundreds of communities across the country with dirty air and hundreds of millions of tons of toxic coal ash waste. The ash has leached a host of toxins �� including arsenic, mercury, lead, cadmium, radium and other pollutants �� into ground and surface water.

��Today is the culmination of years of advocacy for common-sense safeguards that will have a direct impact on communities long forced to suffer in the shadow of the dirtiest power plants in the country,�� said Ben Jealous, executive director of the Sierra Club, one of the nation��s oldest and largest environmental organizations. ��It is also a major step forward in our movement��s fight to decarbonize the electric sector and help avoid the worst impacts of climate change.��

But some electric industry and pro-coal organizations blasted the rules as a threat to jobs and electric reliability at a time when power demands are surging. They also criticized the rule��s reliance on largely unproven carbon capture technologies.

America��s Power, a trade organization for the nation��s fleet of about 400 coal power plants across 42 states, called the number of new rules ��unprecedented,�� singling out the new emissions standards that will force existing coal plants to cut their carbon emissions by 90% by the 2032 if they intend to keep running past 2039.? Michelle Bloodworth, the group��s president and CEO, called the rule ��an extreme and unlawful overreach that endangers America��s supply of dependable and affordable electricity.��

��This forces that��

Many experts expect the regulations to be litigated, particularly the carbon rule, since the last time the EPA tried to restrict carbon emissions from power plants, a group of states led by West Virginia mounted a successful legal challenge that went to the U.S. Supreme Court.

But Julie McNamara, deputy policy director with the Union of Concerned Scientists, said the agency took great pains to conform the rule to the legal constraints outlined by the court.

��This rule is specifically responsive to that Supreme Court decision,�� she said. ��Which doesn��t mean that it won��t go to the courts but this is so carefully hewn to that decision that it should be robust.��

The four rules EPA released Thursday mainly target coal-fired power plants.

��By developing these standards in a clear, transparent, inclusive manner, EPA is cutting pollution while ensuring that power companies can make smart investments and continue to deliver reliable electricity for all Americans,�� EPA Administrator Michael S. Regan said.

In some ways, they attach a framework to a sea change in electric generation that is already well under way, McNamara said.

Coal accounted for just 16% of U.S. electric generation in 2023, according to the U.S. Energy Information Administration. In 1990, by comparison, it comprised more than 54% of power generation. However, some states are more reliant on coal power than others.

In 2021, the most coal-dependent states were West Virginia, Missouri, Wyoming and Kentucky, per a 2022 report by? the EIA.

��This rulemaking adds structure to that transition,�� McNamara said. ��For those who have chosen not to assess the future use of their coal plants, this forces that.��

Heather O��Neill, president and CEO of the clean energy trade group Advanced Energy United, said the new regulations are a chance for utilities to embrace cheaper, cleaner and more reliable options for the electric grid.

��Instead of looking to build new gas plants or prolong the life of old coal plants, utilities should be taking advantage of the cheaper, cleaner, and more trusty tools in the toolbox,�� she said.

The carbon rule

In 2009, the EPA concluded that greenhouse gas emissions ��endanger our nation��s public health and welfare,�� the agency wrote, adding that since that time, ��the evidence of the harms posed by GHG emissions has only grown and Americans experience the destructive and worsening effects of climate change every day.��

The new carbon emissions regulation will apply to existing coal plants and new natural gas plants. Coal plants that plan to operate beyond 2039 will have to capture 90% of their carbon emissions by 2032. New gas plants are split into three categories based on their capacity factor, a measure of how much electricity is generated over a period of time relative to the maximum amount it could have produced. The plants that run the most (more than 40% capacity factor) will have to capture 90% of their carbon emissions by 2032. Existing gas plants will be regulated under a forthcoming rule that ��more comprehensively addresses GHG emissions from this portion of the fleet,�� the agency said.

Michelle Solomon, a senior policy analyst for Energy Innovation, an energy and climate policy think tank, predicts that most coal plants will close rather than install the costly technology to capture carbon emissions.

��Climate goals aside, the public health impacts of the rules in securing the retirement of coal fired power plants is so important,�� she said. Coal power in the U.S. has been increasingly pressured by cheaper gas and renewable generation and mounting environmental restrictions, but some grid operators have still been caught flat-footed by the pace of coal plant closures.

��I think the role of this rule, to provide that certainty about where we��re going, is so crucial to get the entities that have control over the rate of the transition to start to take action here,�� she said. But the National Rural Electric Cooperative Association��s CEO, Jim Matheson, called the rules ��unlawful, unrealistic and unachievable�� noting that it relies on technology ��that is not ready for prime time.��

And Todd Snitchler, president and CEO of the Electric Power Supply Association, a trade group for competitive power suppliers, called the rule ��a painful example of aspirational policy outpacing physical and operational realities�� because of its reliance on unproven carbon capture and hydrogen blending technologies to cut emissions.

A beefed up Mercury and Air Toxic Standards rule

The EPA called the revision to the Mercury and Air Toxic Standards ��the most significant update since MATS was first issued in February 2012.�� It predicted the rule would cut emissions of mercury and other air pollutants like nickel, arsenic, lead, soot, sulfur dioxide, nitrogen oxide and others. It cuts the mercury limit by 70% for power plants fired by lignite coal, which is the lowest grade of coal and one of the dirtiest to burn for power generation.

For all coal plants, the emissions limit for toxic metals is reduced by 67%. The EPA says the rule will result in major cuts in releases of mercury and other hazardous metals, fine particulate matter, nitrogen oxides and carbon dioxide.? The agency projects ��$300 million in health benefits,�� including reducing risks of heart attacks, cancer and developmental delays in children and $130 million in climate benefits.

Stronger wastewater discharge limits for power plants

Coal fired power plants use huge volumes of water, and when the wastewater is returned to lakes, rivers and streams it can be laden with mercury, arsenic and other metals as well as bromide, chloride and other pollution and contaminate drinking water and harm aquatic life.

The new rule is projected to cut about 670 million pounds of pollutants discharged in wastewater from coal plants per year. Plants that will cease coal combustion over the next decade can abide by less stringent rules.

��Power plants for far too long have been able to get away with treating our waterways like an open sewer,�� said Thomas Cmar, a senior attorney at Earthjustice, a nonprofit environmental law organization, during a briefing on the new rules earlier this week.

Closing a coal ash loophole?

Coal ash, what��s left after coal has been burned for power generation, is one the nation��s largest waste streams. The 2015 EPA Coal Combustion Residuals rule were the first federal regulations for coal ash. But that rule left about half of the ash sitting at power plant sites and other locations �� much of it in unlined disposal pits �� unregulated because it did not apply to so-called ��legacy impoundments�� that were not being used to accept new ash.

��We��re going to see a long-awaited crackdown on coal ash pollution from America��s coal plants, and it��ll be a huge win for America��s health and water resources,�� said Lisa Evans, a senior attorney with Earthjustice. ��They are all likely leaking toxic chemicals like arsenic into groundwater and most contain levels of radioactivity that can be dangerous to human health.��

Groundwater monitoring data shows that the vast majority of ash ponds at coal plants are contaminating groundwater, said Abel Russ, a senior attorney with the Environmental Integrity Project. But under the old rule, Russ said, facilities could dodge cleanup requirements by blaming contamination on older ash dumps not covered by the regulation.

��This is a huge loophole,�� Russ said. ��You can��t restore groundwater quality if you��re only addressing half of the coal ash sources on site.��

However, several attorneys on the Earthjustice briefing said the new rules, which will require monitoring at clean up and hundreds of more ash sites, will only be as good as the enforcement.

��It��s meaningful only if these utilities obey the law. Unfortunately to date, many of them have not,�� said Frank Holleman, a senior attorney with the Southern Environmental Law Center.

A natural gas plant in Florida. Utilities, particularly in the South, are pushing to add new natural gas plants. (Getty Images)

The nation��s largest public power company, the Tennessee Valley Authority, which serves 10 million people in Tennessee and parts of six neighboring states, has put forward plans for eight new natural gas plants since 2020.

In South Carolina, Dominion Energy and Santee Cooper are pushing the state legislature to pave the way for a 2,000-megawatt natural gas power plant. Farther north, Dominion also plans new gas generation in Virginia. In its most recent plan filed with state regulators, Georgia Power is looking to add new gas turbines. Likewise, Duke Energy in North Carolina is proposing new gas plants and delaying coal power retirements.

The companies point to spiking electric demand, driven by data centers, new manufacturing facilities, increasing transportation electrification and other sources.

Georgia Power��s CEO said new businesses are creating a thirst for new power at ��both a record scale and velocity.�� Duke and TVA both cited ��tremendous�� economic and population growth in their service areas.

But a new report by an energy and climate policy think tank warns that some utilities, particularly in the South, are making a ��panicked rush to gas�� and calls on state officials to explore cheaper options and carefully vet plans that could saddle electric customers with billions in costs.

��What we really want is for policymakers to ask good questions,�� said Eric Gimon, a senior fellow at Energy Innovation, and one of the authors of the brief for utility regulators, in an interview with States Newsroom.

��Less risky alternatives��

After about 15 years of stagnation, U.S. electric demand is growing. A December report by an electric sector consulting firm noted that the utilities and regional transmission organizations that run the North American electric grid had almost doubled growth projections. At the same time, transmission line construction has nearly ground to a halt and there��s limited ability to move power between regions as the generation mix increasingly shifts to renewables and batteries in many parts of the country.

That��s been coupled with a growing dependence on natural gas power plants, which have taken the role coal used to play in the nation��s power mix but which have also failed in large numbers during recent severe weather.

Gimon said gas plants are often treated as a magic bullet solution to resource adequacy �� an electric industry term for having enough power to meet peak demand. If the vision of the utilities pushing for lots of new gas power comes to pass, one of two things will happen, Gimon contends.

��Either they don��t get used very much,�� he said, and thus become a stranded asset customers are stuck paying for anyway. ��Or they get used a lot and they��re busting through their climate goals and EPA regulations.��

In a recent post , two Natural Resources Defense Council staffers warned that the huge planned Southeastern gas buildout will jeopardize emission reduction targets and hike electric costs, ��leaving customers on the hook for potentially expensive, dirty and ultimately stranded assets that may or may not be usable for their typical, carbon-intensive lifespans.��

Gimon and one of his co-authors, Mike O��Boyle, Energy Innovation��s senior director for electricity, also pointed out that gas plants can��t always be counted on when they��re needed most. In the region run by PJM, the nation��s largest grid operator, gas plants accounted for 70% of the power plant outages it suffered during Winter Storm Elliott in December 2022.

��We��re not talking about a capacity resource that is dependable for 100% of its nameplate capacity during a winter peak either,�� O��Boyle said. ��I think regulators�� jobs are to help ensure that utility investments are prudent and part of that means have they considered more affordable alternatives and less risky alternatives.��

Sarah Durdaller, a spokesperson for the Edison Electric Institute, which represents investor-owned utilities like Dominion Energy, Southern Company and Duke Energy, said its member companies ��are committed to delivering reliable, affordable and resilient clean energy to their customers.��

Durdaller said carbon emissions from the power sector are at their lowest point in almost 50 years, despite electricity generation doubling in that time frame. Natural gas power, she said, ��is an essential partner for deploying renewables and maintaining grid reliability.��

As far as the thousands of megawatts of gas plants companies are proposing, she said that utility plans ��always evolve as new technologies emerge, as costs decline, as demand forecasts change and as new policies are fully implemented.��

��Better solutions��

One aspect for policymakers to consider is the reliability of the demand projections themselves.

��Utilities consistently over forecast,�� said Gudrun Thompson, a senior attorney at the Southern Environmental Law Center, which has been tracking southeastern utilities�� gas plant proposals. ��I would not be surprised if that is happening now.��

Transparency is also a concern, she added, noting that a single data center project could be in negotiations with multiple utilities and get counted by all of them in their load projections.

In 2007, the U.S. Energy Information Administration predicted 1.5% annual growth in electric demand, which would have been a 21% increase over 15 years. It never materialized, mostly because of energy efficiency programs, federal and local building codes and appliance standards and voluntary industry efforts, the Energy Innovation report says.

��Efficiency was a primary cause of flat demand after 2008 and could be a major factor in mitigating the pressure that new demand growth puts on the electrical grid,�� the report notes.

Coming electric load increases aren��t illusory but the report��s authors argue that ��better near-term and long-term solutions exist and should be deployed first.��

For example, Gimon said, battery storage is growing by leaps and bounds in Texas and California, and it��s already playing a growing role in helping to meet peak demand. However, in their planning some Southeastern utilities are treating battery storage ��like it��s some new technology from Mars,�� Gimon said.

The Energy Innovation report��s other recommendations include:

• Taking advantage of existing locations with power infrastructure onsite to build renewable power and battery storage, skipping the long wait times to connect to the grid plaguing many new power projects across the country. The Rocky Mountain Institute, a green energy nonprofit, calls it ��clean repowering�� and says there��s 250 gigawatts (the rough equivalent of 250 large power plants) of new renewable potential at former fossil sites scattered across the country that could be harnessed to create billions in savings and cleaner power generation.
• Look to meet large customer demands with onsite power, such as solar panels, and take better advantage of demand response programs, which enroll large customers who voluntarily agree to reduce power consumption in exchange for savings. Many of those customers include large corporations that have their own carbon reduction targets. Shaving that large customer demand could avoid some or all new peak gas capacity, the report says. ��The utilities�� responses to load growth are coming into conflict with the explicit goals of their own customers who are driving that load growth,�� O��Boyle said.
• Improve how the existing electric system is used by implementing grid-enhancing technologies like dynamic line ratings, power flow controllers and other systems. They��re common in other countries but have been slow to take root in many parts of the U.S. where utilities make the most money by building the most expensive solution they can get approved, not necessarily the one that��s most cost-effective for customers. ��The fact is any data center is hooking into a system,�� Gimon said. ��That system is remarkably underutilized.��
• Improve regional connections, particularly in the Southeast, which is fast becoming one of the few remaining parts of the country without any real regional wholesale electric market. In 2022, Southeastern utilities created the Southeast Energy Exchange Market, but it��s been criticized as a market in name only, since the volume of actual trades has failed to amount to much. ��Research from Energy Innovation and Vibrant Clean Energy found that sharing capacity between non-RTO states in the Southeast would yield more than $10 billion in cost savings annually, revealing a region replete with spare capacity if utilities can figure out how to share it,�� the report says.

It will fall to state utility regulators and policymakers to gauge how desperately their residents actually need all the new gas power being proposed and whether there are cheaper ways to meet climbing demand.

Adding more rooftop solar, energy efficiency programs and residential batteries, known as distributed resources, which can be aggregated into what��s known as a virtual power plant, might mean lower electric sales, the report noted.

��In some states, the electric utility is also the gas utility and can benefit from rate-basing new gas infrastructure. These circumstances create incentives that can skew utility decisions toward well-worn solutions like gas plants and typically disincentivize regional coordination,�� the report says. ��Ultimately, policymakers need to demand more from their utilities and be skeptical of the ��usual suspect�� solutions.��

Thompson, the SELC attorney, called the amount of new gas southern utilities are proposing ��staggering.�� The organization estimates that if all the new gas plants proposed get built, it will eclipse the amount of coal generation southern utilities plan to retire over the next 15 years by roughly 8 gigawatts. Regulators, she said, need to ��look very hard at the load growth projections and take a hard look at choices that the utilities are making,�� including pending EPA carbon regulations that could require expensive carbon capture technology or co-firing with hydrogen and whether the plants will require new pipeline infrastructure. ��If all of these plants get approved and built we��re just not going to achieve the carbon reductions that we need to be on a path to averting the worst effects of climate change.��

Electric transmission lines near Clark, South Dakota. A trade group representing clean energy businesses is grading how well seven regional transmission organizations are doing at getting new projects approved to connect to their grids. (Robert Zullo/States Newsroom)

Across the country, electric demand is growing and could explode if green goals like electrifying home heating, industry and transportation come to fruition. At the same time, many states, utilities and businesses have pledged to decarbonize, helping push older coal and gas power plants that have struggled to stay economically competitive into retirement.

Yet in the queues run by the organizations that manage the electric grid in much of the nation, more than two million megawatts of potential new power sources, chiefly solar, wind and batteries, are languishing awaiting interconnection studies.

That dynamic prompted Advanced Energy United, a trade group representing clean energy businesses, to publish a first-of-its-kind scorecard grading how well the seven regional transmission organizations, which coordinate the flow of electricity for roughly two thirds of American electric customers, are doing at getting new projects approved to connect to their grids.

The short answer? Not so great. But some regions have been better than others, according to Caitlin Marquis, managing director at AEU. Both the Electric Reliability Council of Texas and the California Independent System Operator, organizations that manage the grid in most of their respective states, got Bs. The other five organizations got grades of C-? or lower.

��Grid managers have moved too slowly to adapt to changing market conditions, allowing the process of connecting new electricity to the transmission grid to become dysfunctional,�� she said in a statement. ��Without urgent improvement, the U.S. grid may struggle to keep up with growing energy demands, threatening our ability to keep the lights on and reach our climate goals.��

Grid operators push back on ratings

In many regions, interconnection �C the usually multi-year process to connect new power generators to the transmission system, including studies of any upgrades needed to ensure reliability �C has been a well-known problem for years.

Last summer, the Federal Energy Regulatory Commission issued new rules intended to help clear the backlogs. And indeed, some grid operators questioned the point of the scorecard, which uses data that in some cases is several years old. They said the problems have long been acknowledged and that they��ve been working to overhaul their interconnection processes.

��The report is an assessment of conditions and practices that no longer exist,�� said Jeff Shields, a spokesperson for PJM, the nation��s largest grid operator with a service area that includes 65 million people. ��PJM and its stakeholders acknowledged those issues over three years ago and reformed our interconnection process.�� PJM got a D- on the scorecard.

Mary Cate Colapietro, a spokesperson for ISO New England, which got a D+ from AEU, also questioned the merits of the exercise.

��It is not clear what the value of such a report is given that ISO New England and other regional system operators are in the process of developing significant changes to the interconnection process,�� she said.

Both PJM and MISO, the grid operator for a large swathe of the central U.S., pointed out in their responses that thousands of megawatts�� worth of new energy projects have made it through their queues but haven��t been built because of financing, siting and supply chain problems.

��This is the challenge we need to confront as an industry rather than looking back on problems that have been largely addressed,�� Shields said.

Brandon Morris, a MISO spokesperson, said more than 50 GW of new generation facilities have? been approved by MISO, ��but many are not going into service on schedule due to supply chain issues and permitting delays that are beyond MISO��s control.��

Nonetheless, AEU says the report is an important baseline that will help gauge how well the grid operators implement the fixes federal regulators have mandated.

��This report reflects the challenges that project developers and engineers are dealing with not just a few years ago, but right now,�� Marquis told States Newsroom. ��While reforms are being planned, and in some cases implemented, they don��t address all the concerns outlined in the report, and they aren��t yet fully in effect. One thing the report demonstrates is that even when procedures work on paper, they don��t always work so well in practice.��

Rob Gramlich, an electric grid expert and president of Grid Strategies, a consulting firm that helped prepare the scorecard, pointed out that the 12 interviews conducted with generation developers and engineering firms are all people who are going through the interconnection process now. The grades were determined by considering six factors, two of which were customer perspectives on timeline and costs. The others are speed and certainty, number of interconnection agreements signed, average costs and cost certainty.

��We would expect all of them to improve somewhat if we did it in a year or two,�� Gramlich said. ��We were just looking at a snapshot today.��

MISO

The Midcontinent Independent System Operator manages a portion of the North American electric grid stretching from Manitoba, Canada, to the Gulf of Mexico. In that territory are all or parts of 15 states and 45 million people.

MISO��s interconnection study process is ��unreliable and slow,�� the report says.

��MISO��s timeliness challenges have become particularly evident recently, as queue sizes have increased,�� the scorecard says. �� While MISO used to share details with interconnection customers on the reasons for delays, over the past two years these updates have become less dependable.��

Brandon Morris, a spokesperson for MISO, said the organization��s approach to bringing new power resources into the system ��continues to be one of the most efficient in the electric industry�� and that its process was highlighted by FERC as a ��positive example�� for other organizations.

��We have implemented reforms over the past few years to ensure our interconnection process is not an impediment to having the necessary generator resources available when needed,�� Morris said.

However, developers working with MISO aren��t so sure things will get much better, the scorecard says.

��Although MISO��s recent study enhancements to limit system impact study duration are intended to reduce queue processing to 373 days, interconnection customers still anticipate that most projects will take three or more years to complete, especially in MISO-West,�� according to the report.

PJM

The nation��s largest grid operator, PJM��s service area includes 65 million people in all or parts of 13 states and the District of Columbia. It has long been the poster-child for interconnection queue reform, according to critics, and it got the worst grade from AEU, a D-.

��The most frustrated interconnection customers note that PJM��s interconnection study process for new projects has come to a full stop, with the hope that projects from 2019 may complete the process six years later in 2025,�� the report says. ��One interconnection customer has ceased developing projects in PJM, and other interconnection customers are uncertain whether their projects are getting studied or not.��

It added that some customers report that the organization has ��no regard for reasonableness and decorum when it comes to communicating deadlines.��

Shields, the PJM spokesperson, said the grid operator implemented new rules last year that are speeding up processing, specifically moving from a first-come, first-served process to a ��first-ready, first-served�� approach. By mid-2025, PJM expects to process about 72,000 MW in projects and 230,000 MW over the next three years, Shields said. Nearly all of those are? renewable or storage.

��That is real progress,�� he said. ��PJM realizes that further reforms will likely be needed to meet the needs of the energy transition, and we will consider additional potential interconnection policy reforms with PJM members.��

A coalition of climate justice groups organized a rally Feb. 26 outside the Washington, D.C., hotel where the National Association of Regulatory Utility Commissioners was holding its winter policy meeting. The speakers, including? Christine Pendzich, center, of Montgomery County, Md., took aim in part at energy company and utility sponsorship of the event. (Robert Zullo/States Newsroom)

After a string of scandals and amid rising bills, lawmakers in statehouses across the country have been pushing legislation to curb utilities spending ratepayer money on lobbying, expert testimony in rate cases, goodwill advertising, charitable giving, trade association membership and other costs.

At least a dozen states have considered bills to limit how gas, water and electric utilities can spend customers�� money, according to a tracker maintained by the Energy and Policy Institute, a watchdog group funded by environmental and climate-focused foundations that concentrates on utilities and fossil fuel interests.

Another, Louisiana, has opened a proceeding at its public service commission to investigate use of ratepayer cash on trade association dues, ��activities meant to influence the outcome of any local, state, or federal legislation,�� advertising expenses and other costs.

Michigan joined the party last week with the introduction of legislation to ban utility political spending. In states like Illinois, the push has been joined by groups like the AARP and the Citizens Utility Board, a state watchdog group, which said the legislation would ��stop electric, gas and water utilities from charging us for a long list of expenses they rack up trying to raise our rates and further increase their political power.��

Three states? �� Maine, Colorado and Connecticut �� have already signed similar bills into law. The legislation comes as natural gas bills have fallen but average residential electric prices in the U.S. climbed from 13.66 cents per kilowatt hour in 2021 to 15.93 cents per kilowatt hour in 2023, per the U.S. Energy Information Administration. That would mean a monthly bill going from $136.60 in 2021 to $159.30 in 2023 for a house that uses 1,000 kilowatt hours per month.

��It absolutely is a growing trend,�� said Matt Kasper, the Energy and Policy Institute��s deputy director. ��There��s a lot of eyes on the industry, how it��s operating.��

The institute published a report last year that scrutinized how electric and gas utilities use ratepayer money to ��fund political machines that push legislation, curry favor with regulators and alter the outcomes of elections, sometimes even breaking laws in the process.��

Some of the lowlights include:

• A massive bribery scandal in Ohio involving FirstEnergy, a utility holding company that? paid nearly $61 million in bribes to the Ohio house speaker��s political organization in exchange for a nuclear plant bailout worth $1 billion to the company. A U.S. attorney called it ��one of the largest public corruption conspiracies in Ohio history.��
• In Illinois, the state��s largest electric utility, Commonwealth Edison, or ComEd, showered the state House speaker��s allies with jobs, contracts and payments to grease the wheels for the company��s legislation. Three ex-lobbyists and a former CEO of the company were convicted by a federal jury last year for their roles in the scheme. The speaker��s trial is scheduled for later this year.
• Florida Power & Light, one of the largest utilities in the nation, is facing calls for a federal investigation over accusations of using political consultants to back ��ghost candidates�� in legislative races to draw votes away from candidates it opposed. It also took over a news website as ��part of an elaborate, off-the-books political strategy to advocate for rate hikes, agitate for legislative favors, slam political opponents and eliminate anything? �� (that) might undermine its near monopoly on selling power in the Sunshine State,�� the Miami Herald reported. That��s not to mention accusations of hiring private investigators to follow a newspaper columnist who was critical of the company.

Other examples of questionable spending abound. In 2018, South Carolina lawmakers were flooded with bogus emails encouraging them to support Virginia utility giant Dominion Energy��s takeover of SCANA Corp., a company struggling under the weight of a failed nuclear project. Dominion denied having anything to do with the fake emails, which were sent by the Consumer Energy Alliance, a group that was then supported by Dominion. (The company is no longer listed as a CEA member).

Consumer Energy Alliance was also involved in a 2016 campaign to support a natural gas pipeline running through Ohio that involved sending 347 letters to the Federal Energy Regulatory Commission using the names of locals �� more than a dozen of whom signed affidavits denying they signed the letters ��? including ��an Ohio man who has been dead since 1998,�� The Plain Dealer reported.

In Louisiana, Entergy was fined $5 million by the New Orleans City Council after actors hired by a public relations firm working for the utility showed up at public hearings to support a proposed power plant.

Arizona Public Service, which has 1.4 million electric customers in the state, spent $10 million in 2014 that was funneled to dark money groups to help elect its preferred members of the State Corporation Commission, which regulates utilities. That spending wasn��t revealed until 2019, when the company complied with a subpoena to release documents.

��Utilities are often using their ratepayer-funded political machines to slow the nation��s urgently-needed transition away from fossil fuels and toward clean energy,�� the Energy & Policy Institute wrote. ��Working hand-in-hand with their trade associations, the Edison Electric Institute and American Gas Association, utilities continue to fight tooth-and-nail against policies that enable the adoption of essential technologies like rooftop solar power, energy efficiency and building electrification.��

��The appetite is there��

However, bills to curb utility influence spending can face an uphill fight, demonstrating the stronghold that the companies can have on state governments.

In Virginia, for example, another round of legislative attempts to prevent candidates from accepting donations from public service companies like Dominion Energy, the state��s largest electric utility and long the biggest corporate donor in Virginia politics, died in House and Senate committees. Both houses are controlled by Democrats.

��Time will tell what will happen,�� Del. Josh Cole, a Democrat who was carrying the House version of the legislation,told the Virginia Mercury.? ��The appetite is definitely there for it.��

A separate proceeding at the Federal Energy Regulatory Commission has been looking into the ��rate recovery, reporting and accounting treatment of industry association dues and certain civic, political and related expenses.��

The Edison Electric Institute, which represents investor-owned electric utilities and is one of the trade groups affected by some of the state-level legislation, said electric customers benefit when its member companies ��have a seat at the table,�� adding that they are among the most regulated businesses in the nation.

��We engage on their behalf through lobbying, advocacy and regulatory proceedings as part of our work to ensure that electricity customers have the affordable, reliable and resilient clean energy they want and need. Engaging in discussions with policymakers and regulators is essential to achieving these outcomes,�� EEI spokeswoman Sarah Durdaller said in a statement. ��We bring unique expertise and insights on how policy proposals will affect business operations, the cost for capital, and, ultimately, our customers. �� There are strict laws in place already to ensure that lobbying activities are always funded by shareholders not customers.��

The American Gas Association, which represents natural gas utilities, did not respond to a request for comment.

On Monday, across the street from the Washington, D.C., hotel where the National Association of Regulatory Utility Commissioners was holding its winter policy meeting, a group of climate justice organizations held a rally to call attention to energy company influence, taking aim at corporate sponsorship of the event and a lack of progress on renewable power.

��When we see events like this where utility execs fund gatherings and hobnob with regulators ��? we need to speak out,�� said Sukrit Mishra, D.C. program director at Solar United Neighbors, a nonprofit that helps communities form solar co-ops. He voiced support for state legislative efforts as well as federal legislation introduced by U.S. Rep. Kathy Castor, a Florida Democrat, to prevent utility companies from using ratepayer dollars to fund political activities.

��The public is ready to hold utilities accountable. We need regulators to do the same.��

(Photo by Mark Wilson/Getty Images)

PJM, the nation��s biggest grid operator, is changing how it plans transmission upgrades needed to ensure reliable service for the 65 million people who live in its footprint.

The effort comes after plenty of criticism of how the regional transmission organization, responsible for coordinating the flow of electricity in all or parts of 13 states and the District of Columbia, has traditionally conducted planning. Clean energy advocates and some state regulators are pushing for a more holistic, forward-looking approach that evaluates options besides traditional transmission lines and better incorporates the policy goals of PJM states, particularly those, like Illinois, Delaware, Maryland, Michigan, Virginia and New Jersey, that have set aggressive decarbonization targets.

Anjali Patel, a consultant for Americans for a Clean Energy Grid, a nonprofit advocacy group, said past transmission planning has put economic needs, reliability needs and state interests in ��separate buckets�� and has been relatively short-sighted, even though transmission investments can last 40 or 50 years.

��We need more proactive planning,�� she said. ��PJM is one of the main places that needs to occur.��

And yet some see backsliding in the process to develop the new framework could imperil states�� goals and waste crucial time.

��It started off going pretty well,�� said Tom Rutigliano, a senior advocate for climate and energy at the Natural Resources Defense Council who focuses on PJM. ��The fossil fuel states complained. �� PJM agreed to plan for a fictional future to appease the fossil fuel states.��

The changes, however, haven��t been finalized, and could be affected by a pending Federal Energy Regulatory Commission rule on transmission planning and cost allocation, said Jeff Shields, a PJM spokesman.

Why planning matters

In a November letter, the Organization of PJM States, a group of utility regulators from PJM��s territory, wrote that it was concerned about ��our region��s reactive stance�� amid a major shift in the electric power industry, with infrastructure aging, older fossil fuel plants retiring and power demand climbing.

��Within the PJM footprint, rapid changes in both load forecasts and available supply are creating pronounced grid reliability issues that challenge PJM��s existing planning tools,�� the group said. In response, PJM said it ��agrees that processes that may have served us well in the past need to continue to evolve to meet current and future needs of the grid.��

How regional transmission organizations like PJM manage power plant retirements, solve the electric capacity problems they create and plan for the future during a time of unprecedented change for the U.S. electric grid can get thorny quickly. But those decisions make a difference on customers�� electric bills and can affect what generation sources come online in replacement, among other impacts.

For a test case on how things can go awry �� from the perspective of PJM��s critics, at least �� look to Maryland.

The state��s Office of People��s Counsel and the Public Service Commission took PJM to task in complaints to the Federal Energy Regulatory Commission over a suite of urgent transmission projects that PJM approved to fix anticipated electric reliability problems caused by a retiring coal plant about nine miles southeast of Baltimore. In the complaints, which FERC rejected, they argued PJM shouldn��t have been caught flat footed by the plant��s retirement, which they said will saddle Maryland electric ratepayers with about? $786 million in new transmission costs in addition to a pricey ��must run�� agreement that will keep the Brandon Shores plant burning coal until the projects are complete in about four years.

��PJM��s response to the recently announced retirement of Brandon Shores �� illustrates the risks of failing to proactively plan for the retirement of large coal generators,�� the Sierra Club��s Maryland Chapter wrote to PJM��s CEO in November.

The Maryland Public Service Commission said that by focusing on a transmission solution, PJM��s process ��precludes consideration of viable alternatives, with the prospect of exposing Maryland ratepayers using the transmission facilities to unreasonable costs.�� The commission noted that Maryland law requires installing 3,000 megawatts of energy storage, ��more than double the Brandon Shores facility��s total capacity.�� That storage power, it said, could ��possibly negate the need for the PJM-approved transmission upgrade.��

PJM rejected those arguments.

��Protesters suggest that PJM should have acted outside of its clearly defined planning authority and processes; predicted that the Brandon Shores coal-fired units were retiring when specifically told otherwise; and relied on resources and technologies that do not solve the engineering problem,�� the organization responded in a filing with FERC. ��There is no existing technology that can cure the reliability problems that Brandon Shores will create when it deactivates other than transmission.��

FERC Commissioner Allison Clements, though concurring with the commission��s order approving PJM��s transmission plan, noted that the objections ��paint a troubling picture with regard to PJM��s grid planning.��

She questioned whether PJM could have ��carried out planning activities sooner and in doing so identified potential solutions that more expeditiously address the reliability need, cost less, or that deliver greater value to customers.��

��Really hard for those states to agree��

What some advocates want is a process that allows PJM to work with states and utilities to come up with solutions that better incorporate state policy goals as well as consider lower cost options.

��PJM can��t take an integrated look at how to replace a retiring plant,�� Rutigliano said. ��Their plan is very rigid, very reactive and doesn��t allow anyone to come forward with better options.��

Rutigliano and others argue PJM doesn��t need to reinvent the wheel, pointing at its RTO neighbor to the west, the Midcontinent Independent System Operator, which ��has been doing long term planning since at least 2011, and has developed a robust planning process that supports utility and state future resource plans while ensuring that consumers benefit from low cost power and high levels of reliability,�� NRDC said.

��We hoped it would be something like MISO is doing,�� said Jon Gordon, policy director at Advanced Energy United, a trade group for clean energy businesses. ��There was a great model out there right next door.��

A crucial difference between MISO and PJM, however, is that PJM does not have the authority to develop or impose cost allocation schemes since who pays for what can be the biggest sticking point in transmission planning and construction.

Gordon, Rutigliano and others are also wary of PJM��s currently proposed tiered approach, which proposes to weigh three different scenarios for transmission planning. The ��base�� scenario is focused on reliability and only state public policy goals that deal with forcing power plants into retirement are taken into account, such as Illinois�� Climate and Equitable Jobs Act.

The ��medium�� and ��high�� scenarios factor in policies that promote new renewable power. Those scenarios ��allow states to voluntarily sponsor additional transmission needs and solutions�� through what��s called the ��state agreement approach,�� in which a given state��s electric ratepayers foot the bill for transmission upgrades needed to accommodate new renewable power sources, as New Jersey did with PJM to meet its offshore wind goals.

In a presentation in November, PJM staff said the organization had fielded concerns ��on whether it is appropriate to model, plan and cost allocate all public policy requirements as reliability projects.�� Some states have balked at paying for transmission upgrades needed to accommodate fossil plant retirements or renewable energy growth in others.

The majority of PJM states, for example, agree that the costs of one state��s public policies shouldn��t be paid by electric customers in other states, the National Association of Regulatory Utility Commissioners wrote in comments filed with FERC.

��PJM is challenged in that the states that make up PJM have very different policy goals,�� Gordon said. ��In MISO states agreed on cost allocation policies that made the MISO process work better. �� We have some states in PJM that are really progressive clean energy states and we have states that are really closely aligned with fossil interests. When you get into cost allocation it��s really hard for those states to agree.��

��Cautiously optimistic��?

However, experts like Rutigliano fear that siloing off state policy goals could lead to duplicative building of transmission infrastructure, since PJM would only be looking at the loss of fossil fuel plants and failing to seriously consider the renewable power that would replace them.

��That��s one of our big worries,�� he said. ��They��ll build new transmission to make up for the void rather than acknowledging or building the transmission for the clean replacements. ..? The cost allocation for clean energy projects shouldn��t be punitive.�� It also forces one state��s electric ratepayers to cover costs for transmission that can have benefits beyond its borders.

Patel, the Americans for a Clean Energy Grid consultant, also said state policies need to be better incorporated into PJM planning.

��They��re policies of the utilities operating in PJM, they��re the policies of the businesses operating in PJM,�� she said. ��These interests cut across partisan lines and cut across our economy.��

However, she��s more sanguine on the progress PJM is making.

��We��re cautiously optimistic this can move us in the right direction,�� she said.

Wanting more reliable access to backup fuel, utilities in the U.S. are planning to add liquified natural gas storage tanks at their existing plants. Such storage is already being done in the UK and Germany. Here are storage tanks at the Dragon Liquefied Natural Gas plant in Wales. (Photo by Polly Thomas/Getty Images)

As the U.S. electric power system has become more reliant on natural gas plants, it��s also become more vulnerable to gas system failures.

During Winter Storm Elliott in 2022, about 18% of the anticipated power supply in the portion of the grid that serves the entire eastern half of the United States, called the Eastern Interconnection, was offline. Of the power plants that failed to perform, 47% were natural-gas fired, according to a joint inquiry by the Federal Energy Regulatory Commission and the North American Electric Reliability Corporation.

Natural gas fuel problems accounted for 20% of all generation outages, the report noted.

However, in an era when building new gas pipelines, along with other infrastructure, has proven increasingly fraught, some utilities see a solution to gas shortages: adding liquified natural gas storage onsite.

Virginia utility giant Dominion Energy is proposing to add liquefied natural gas storage to serve two large power plants it operates near Emporia in southern Virginia. And in South Dakota, Otter Tail Power Company is planning to add gas storage at its Astoria combustion turbine plant in Deuel County. A spokesman for Duke Energy, a large North Carolina-based utility company which was forced to cut power to customers during Elliott last year, said it is ��exploring all on-site storage options, including LNG and other alternative fuel storage technologies for future use.�� A 2021 study by researchers at Carnegie Mellon University found that storing gas onsite could also yield benefits for electric customers in New England, where gas supply is tight.

Some pro-renewable energy analysts, though, are wary about the costs and impacts of adding new gas infrastructure at a time when cutting emissions to mitigate climate change is becoming ever more pressing. There are also safety and environmental concerns.?

?��Ensuring access to fuel��?

Having backup fuel on site is common at many natural gas power plants, though the go-to option is typically a distillate fuel oil (like diesel), said Michael Caravaggio, director of research and development at the Electric Power Research Institute, an independent nonprofit research organization. The main advantage is ease of storage and management over a long period of time, whereas liquefied natural gas needs to be kept at extremely low temperatures, (about -260 degrees Fahrenheit). That means that adding LNG storage involves either liquefying pipeline gas onsite or transporting LNG in for storage in specialized tanks.

��That��s a lot of infrastructure for backup fuel,�� Caravaggio said. ��The vast majority of the U.S. would likely pencil out with diesel and distillate oil as the onsite backup and that��s what we see currently.��

But Bill Swanson, manager of supply operations and planning for Otter Tail Power Company, which has about 133,000 customers in Minnesota, North Dakota and South Dakota, said adding LNG at the company��s 245-megawatt Astoria plant made the most economic sense. Winter Storm Uri in 2021, which sent gas production plummeting, and Elliott last year prompted the company to pursue LNG backup fuel.

��During Winter Storm Elliott we had a situation where we couldn��t get gas out of the pipeline,�� he said.

The company explored fuel oil but found it would require modifications to the gas turbine. Burning the oil, he added, also reduces the output of the plant more than 10% and increases emissions.

��On an evaluated cost basis, LNG was lower cost,�� Swanson said, though when asked he said the total cost of the gas storage project is not public. If Otter Tail had to liquefy the gas onsite instead of trucking it in from a nearby facility, ��economics might flow back to fuel oil,�� he added.

Jeremy Slayton, a spokesman for Richmond-headquartered Dominion Energy, said Elliott, Uri, and the Colonial Pipeline cyberattack in 2021 all underscored the need for backup fuel.

The company is proposing to add a 25 million gallon LNG storage facility that will enable its two large combined cycle plants at Brunswick and Greensville to run at full bore for up to four days each. Those plants alone generate enough electricity to power 700,000 of its 2.6 million Virginia customers�� homes.

A cost estimate for the project was not available, Slayton said.

��We are in the process of finalizing the project design, specifications and cost estimates,�� he said.

Whether other electric ratepayers elsewhere across the country will be asked to pick up the tab for natural gas storage is unclear. Scott Fiedler, a spokesman for the Tennessee Valley Authority, which is the largest public power company in the U.S. and operates 17 natural gas power plant sites across its footprint, is not considering adding onsite liquefied natural gas storage at current or future plants. Fiedler cited cost, supply chain issues, regulatory and permitting challenges and safety as considerations.

Since 2011, LNG plant operators have reported 39 incidents to the U.S. Pipelines and Hazardous Materials Safety Administration, an agency spokesperson told States Newsroom. Eight of those ��indicate the released commodity ignited,�� the spokesperson said. A 2022 fire and explosion at the Freeport LNG import and export facility on Quintana Island, Texas, was attributed to testing and operating procedure failures, human error and fatigue, Reuters reported. In North Carolina, where Dominion is building another large LNG storage facility designed to serve gas customers, the facility is expected to emit 65,579 tons of greenhouse gasses a year, among other pollutants. Similar storage projects intended to serve gas customers have been built or are being developed in New Mexico and Wisconsin.

Sarah Durdaller, a spokeswoman for the Edison Electric Institute, a trade group for investor-owned utilities, said the organization does not track individual projects but added that gas storage is valuable.

��Natural gas is a partner to reliability and clean energy. It��s helping accelerate the clean energy transition by allowing our member companies to integrate more renewables into the energy grid while ensuring resilience and reliability,�� she said. ��Storage, both onsite at power plants and regional hubs, along with other redundancies ensure natural gas is available when customers and the energy grid need it most.��

Todd Snitchler, president and CEO of the Electric Power Supply Association, which represents competitive power producers, said their membership is ��constantly evaluating the options available to ensure reliable operation of their assets, including ensuring access to fuel.��

��Not the answer��?

Yet, at a time when urgent action is needed to mitigate the effects of climate change, investing more money in natural gas infrastructure doesn��t make sense, said Mark Specht and Paul Arbaje, energy analysts at the Union of Concerned Scientists who authored a report released Jan. 9 on the failures of gas power plants during five severe winter storms over the past 13 years.

��More gas infrastructure is not the answer. Utilities should be instead focused on diversifying and reducing their reliance on gas,�� Arbaje said in an interview with States Newsroom, noting that the U.S. Energy Information Administration is predicting that battery storage installations will nearly double in 2024.

Specht noted that about 70% of gas plant failures in the storms they studied were caused by freezing equipment and other problems unrelated to fuel availability.

��That picture would not change if you have onsite gas storage,�� he said. ��One of the conclusions from our report is they really should have someone regulating the reliability of the gas system. That might be a more sensible solution.��

A green-tech hydrogen production plant in Wesseling, Germany. Hydrogen at the plant is manufactured by electrolysis, which uses electricity to produce hydrogen from water. The U.S. Department of the Treasury has proposed rules to ensure that hydrogen electrolyzers in this country don��t siphon clean electricity from the grid that must be replaced by ramping up coal and gas power plants. (Photo by Andreas Rentz/Getty Images

The October announcement that the U.S. Department of Energy had selected seven regional hub projects for billions in federal money to spur the production of clean hydrogen was met with considerable fanfare from the fledgling industry, seen as crucial to helping decarbonize the American economy.

But when the Biden administration��s Treasury Department released proposed regulations last month for how a key hydrogen production tax credit will be implemented, the reception from some corners of the industry was a lot less warm.

Frank Wolak, president of the Fuel Cell and Hydrogen Energy Association trade group, said the regulations would place ��unnecessary burdens on the still nascent clean hydrogen industry,�� adding that they fly in face of Congress�� intent in the Inflation Reduction Act, the landmark 2022 climate law.

��Congress intended the tax credit to spur domestic clean hydrogen production and allow the United States to maintain an international competitive advantage, not to be an inadvertent backdoor to regulate use of the electric utility grid,�� Wolak said, adding that the regulations ��will unnecessarily hold back our domestic industry, driving investment, manufacturing and technology leadership overseas.��

The Edison Electric Institute, which represents investor-owned electric utilities, also criticized the rules, saying they don��t ��offer sufficient flexibility to allow the scale up that will be necessary to support a U.S. hydrogen economy.��

Some Democratic senators have also pushed for looser regulations, including Sherrod Brown of Ohio and Pennsylvania��s John Fetterman and Bob Casey. ��For an administration that wants to reduce emissions and fight climate change, it makes no sense to kneecap the hydrogen market before it can even begin,�� U.S. Sen. Joe Manchin, a West Virginia Democrat, said in a statement.

Environmental groups, other lawmakers and the administration, however, say the restrictions are necessary to ensure hydrogen subsidized by the credits doesn��t actually increase greenhouse gas emissions.

��I��m grateful to see the Biden administration listening to experts to ensure that hydrogen production is adding new clean energy to the grid, protecting consumers and the environment, and expanding clean-energy jobs,�� said Pennsylvania State Rep. Danielle Friel Otten, a Democrat and a member of the National Caucus of Environmental Legislators.

What the credit does

The hydrogen production tax credit ranges from 60 cents per kilogram of hydrogen produced to $3 per kilogram, depending on the lifecycle emissions from the facility. Those emissions are determined using a federal model called GREET (Greenhouse Gases, Regulated Emissions and Energy Use in Transportation) and the credit is available for 10 years for projects that begin construction before 2033. The credit starts on the date a hydrogen production facility goes into service, meaning some facilities will be eligible for the credit into the 2040s, the Treasury Department says. That��s a lot of potential money at stake.

��It��s very lucrative,�� said Julie McNamara, deputy policy director with the Climate and Energy Program at the nonprofit Union of Concerned Scientists. ��Because there��s so much money on the line, this tax credit will shape the hydrogen that ends up getting produced.��

For proponents, clean hydrogen has applications in hard-to-decarbonize industrial sectors like steel, cement, long haul transportation and potential natural gas blending in power production. But most hydrogen right now is produced using a process called steam-methane reforming that also releases carbon emissions and other air pollutants.

To qualify as ��clean�� for the tax credit, facilities using natural gas to produce hydrogen must capture and store most of the carbon produced. However, most of the wrangling and lobbying has been over what proponents call the ��three pillars approach�� that the Treasury Department included in the draft rule and would affect hydrogen manufactured by electrolysis, which uses electricity to produce hydrogen from water.

The provisions �� called additionality (or incrementality), time-matching and deliverability �� are intended to ensure that new hydrogen electrolyzers don��t create more greenhouse gas emissions by siphoning clean electricity from the grid that must be replaced by ramping up coal and gas power plants.

��It��s clean at the point of production,�� McNamara said. ��But it��s extremely energy intensive. �� It takes a lot of electricity to produce that hydrogen.��

So the proposed tax rules say electrolyzers connected to the grid that are seeking the clean hydrogen production credit must use ��energy attribute certificates�� to demonstrate their purchase of new clean power, either from a new power facility or from added capacity at an existing plant, provided they are built within 36 months of the electrolyzer coming online. Electric power that is currently being curtailed, meaning it��s available but not being used by the grid because of transmission constraints or other reasons, can also count, McNamara said.

The time-matching provision is intended to ensure the use of electricity by the electrolyzer matches when the power it claims to be using is produced. Until 2028, electrolyzers will only have to match those figures annually. But after that, they��ll have to perform hourly matching to qualify for the credit.

McNamara cited the example of Florida, which has abundant solar resources. But an electrolyzer running at night clearly wouldn��t be using solar power.

��If you look on an annual basis, there could be a mismatch,�� she said.

The ��deliverability�� rules require the power a hydrogen facility claims to be using to be in the same grid region as the electrolyzer.

��Without each of these three requirements, there is a strong likelihood that hydrogen production would result in increased grid emissions and would exceed the maximum emissions intensity permitted to qualify for the credit,�� the White House said in a statement.

��Not a free buffet��

The rules, which are out for public comment now, do leave some questions open, McNamara said, including a push by the nuclear power industry to have all nuclear power, not just curtailed electricity, count for clean tax credit purposes. Since nuclear plants produce about 20% of U.S. electricity, that could mean more coal and gas plant electricity needed to backfill the power diverted to hydrogen, she said.

��This is an industry play for profit,�� she said.

Three of the hubs that got initial funding approval from the Department of Energy plan to use nuclear energy, including the Midwest Alliance for Clean Hydrogen (MachH2) hub.

��Today��s award is proof positive that DOE and the administration want existing nuclear energy to play a vital role in jumpstarting domestic hydrogen production and we look forward to final Treasury Department guidance,�� said Joe Dominguez, president and CEO of Constellation Energy, in October. Constellation plans to build a hydrogen facility at its LaSalle County Nuclear Generating Station in Illinois as part of the Midwest hub. There are also questions around plant retirements and relicensing, and how biomethane (for example gas produced from landfills, sewage treatment plants and manure lagoons) should be valued, among other facets of the rule.

��This is not a free buffet for public funds,�� McNamara said. ��It��s an intended tax credit to build out the industry we need for the future.��

Attempts to reach representatives of the Pacific Northwest, Heartland, Gulf Coast, Mid-Atlantic and Appalachian hubs for comment were unsuccessful.

Jeff Phillips, a spokesman for the Midwest Alliance for Clean Hydrogen, which includes Illinois, Indiana and Michigan, said the hub��s leadership and sponsors ��are actively reviewing�� the Treasury tax guidance.

��We will provide further updates as we are able to,�� he said.

Coal ash has long been used as filler material in residential areas, schools, highways, bridges and various infrastructure projects. The Environmental Protection Agency now says coal ash fill may create an elevated cancer risk. (Photo by Spencer Platt/Getty Images)

Coal ash, what��s left over after coal is burned to generate electricity, is one of the largest waste streams in the U.S., with hundreds of millions of tons of it lying in hundreds of sites across the country.

However, a lot of that ash, which can contain a host of toxic metals, isn��t just sitting around in a landfills or disposal pits, it��s also been a cheap source of fill material, with 2 million tons of it being used for that purpose in 2021 alone, according to the American Coal Ash Association, a trade group. EarthJustice, an environmental group, citing the association��s numbers, says 180 million tons of coal ash has been used for fill since 1980. Ash has been used on everything from a golf course in Virginia to playgrounds in Tennessee and much of an entire Indiana town.

��Coal ash structural fill has been used to construct stable base layers for roads, bridges, airfields and large buildings across the state. �� The availability and often low cost of coal ash made the product attractive to developers and landowners, especially during the 1980s and 1990s,�� North Carolina��s Department of Environmental Quality says on its website. The state is one of few that has actually attempted to track where ash was used as structural fill.

And, in a draft risk assessment published last month by the U.S. Environmental Protection Agency as part of a proposed broader revision of its coal ash management rules, the agency now says using coal ash as fill may create elevated cancer risk from radiation.

��This is the first time EPA has identified the threat from radioactivity from ash use as fill,�� said Lisa Evans, a senior attorney at EarthJustice, an environmental law group. ��Which is really important because ash has been used as fill for 100 years. �� We didn��t really worry about the radioactivity until EPA pointed it out in this draft risk assessment.��

Coal ash, according to the EPA assessment, is recognized as ��a type of technologically enhanced naturally occurring radioactive material,�� meaning that naturally occurring radium has ��has been concentrated or altered, such as through combustion, in a way that increases the potential for exposure.��

In addition to groundwater contamination, risk depends on a host of factors, such as how much coal ash was mixed with soil and how much soil was used to cover the ash, called ��coal combustion residuals�� (CCR) in agency jargon.

��EPA also found greater potential for risk from gamma radiation as CCR comes to be located closer to the ground surface due to a reduction in shielding,�� the EPA wrote in the assessment. ��An additional sensitivity analysis identified potential for further risk if CCR becomes mixed with surface soil. Accumulation of CCR can result in elevated cancer risk from incidental ingestion of arsenic and radium, in addition to direct exposure to gamma radiation from radium.��

More than 150 groups sent a letter to the EPA Dec. 11 urging the agency to take several steps to protect the public from risks associated with using ash as fill.

They want EPA to quantify the full range of health risks, from radiation in particular, investigate where ash was placed near residential areas and require clean up, craft a rule that prohibits the use of ash as structural fill and issue a public advisory recommending an immediate halt to use of ash as fill in residential areas. The letter notes that EPA found cancer risks even when small amounts of ash (1 to 2% of the soil mix) are used.

��EPA action to remedy these hazardous sites and prevent further dangerous use of toxic coal ash is needed because EPA��s current regulation of coal ash fill is grossly inadequate,�� the groups wrote, noting that there are no restrictions on ash placement for volumes less than 12,400 tons. ��For larger volumes, the lack of enforceable safeguards and oversight is equally disastrous. In most states, coal ash fill can be placed directly next to or under dwellings, drinking water wells, aquifers and playgrounds. Further, there is often no requirement to even cover the toxic waste.��

A spokesperson for the agency said it would ��review the letter and respond through the appropriate channels.��

The U.S. Nuclear Regulatory Commission has approved for construction a non-water-cooled nuclear reactor in Oak Ridge.

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.

AES Indiana��s Petersburg Generating Station in Petersburg, Ind., has been burning coal since the 1960s but will shutter all of its coal firing units over the next few years. The plant is converting some generating units to natural gas and will also host an 800 megawatt-hour battery storage system expected to come online late next year. (Robert Zullo/States Newsroom)

PETERSBURG, Ind. �� AES Indiana��s Petersburg Generating Station, which towers over the White River here in southwest Indiana, has been burning coal to generate electricity since the late 1960s.

That era, though, will come to an end soon. Two of the power plant��s four coal-burning units have already retired and the last is planning to shut down in 2025.

��AES Indiana will be the first utility out of coal in the state,�� said Kelly Young, a spokeswoman for the company, which has more than half a million customers in the Indianapolis area.

Power generation, however, will continue. Two of those coal units will be switched out to cleaner burning natural gas, and the company is also building an 800 megawatt-hour battery storage array at the Petersburg plant to take advantage of the existing grid connections and meet its electric capacity obligations, banking power when prices and power demand is low and discharging when demand climbs and the regional grid operator, the Midcontinent Independent System Operator (MISO) needs the juice for the electric grid.

��The batteries are basically a time machine,�� said Aaron Cooper, the company��s chief commercial officer for U.S. utilities. Cooper said the company opted for batteries after an exhaustive review of its obligations to its customers and the larger grid, (especially under MISO��s new winter rules that require more reserve margins) while also taking into account the costs and specifications of available generation technologies and new favorable tax rules for renewables as part of its long range planning process.

AES�� project isn��t alone. Those same factors, along with the increasing resistance to new greenfield wind, solar and storage development, as well as massive backlogs in the queues to connect new power projects to the grid, mean former mine lands and the plants that burned the coal they produced are increasingly attractive spots for new renewable development.

Conversion of old coal plant sites to new storage and renewable projects is happening in New Jersey, Nevada, Louisiana and elsewhere across the country.

��Reuse of these interconnections is critical to driving down the cost of replacement generation,�� said Justin Tomljanovic, a vice president of corporate development at Xcel Energy, which has 3.1 million electric customers in eight states and is building two battery arrays near retiring coal plants in Becker, Minnesota, and Pueblo, Colorado.

��We��re thinking about this at every single place where we��re retiring a coal plant. �� It is a company strategy that we think enables us to hit our carbon goals and our states�� carbon goals cost effectively.��

Once and future ��energy communities��

States can play a major role in speeding these transitions, said Harry Godfrey, a managing director at Advanced Energy United, a trade association representing wind, solar, energy efficiency, battery storage and other businesses. On the one hand, renewable energy and decarbonization mandates are helping spur the transition to cleaner electricity. Twenty three states have 100% clean energy goals. Other policies, such as ��securitization�� legislation, can blunt the costs to consumers of retiring coal plants before the end of their useful lives. ��They��re finding interesting financing options to manage those stranded costs,�� Godfrey said.

Illinois has a grant program specifically designed to incentivize retiring or shuttered coal plants to install energy storage.

Also, tax credits in the landmark Inflation Reduction Act, the biggest piece of climate legislation in U.S. history, include a bonus 10% credit for ��energy communities,�� defined as brownfield sites, areas with large historic levels of employment or tax revenue derived from coal, oil, gas extraction or communities where a coal power station closed after 2009 or a coal mine closed after 1999, among other criteria.

��The Inflation Reduction Act is designed not just to lower energy costs and combat climate change, but to promote broad-based economic opportunity and create jobs in communities that have been at the forefront of energy production, especially coal communities,�� said Deputy Secretary of the Treasury Wally Adeyemo in a statement in June. ��Treasury is focused on ensuring all Americans benefit from the growth of the clean energy economy, particularly those who live in communities that have depended on the energy sector for jobs.��

(The Department of Energy keeps a map of eligible energy communities here.)

States that want to help speed the transition from old fossil fuel sites to new renewable energy facilities and take advantage of the jobs and tax revenue they can bring need to get on the ball, Godfrey said.

That means inventorying and packaging sites in a similar fashion as states do to lure developers for other big economic development projects like trying to attract a factory or distribution center, he said.

��The IRA is intentionally designed to promote these conversions,�� he said. ��The state��s role in economic development is really pivotal.��

Mine lands and brownfields

Danny Van Clief, CEO of Sun Tribe Development, part of Sun Tribe Solar, a Charlottesville, Virginia, company that��s one of the largest clean energy companies in the mid-Atlantic, said it��s become increasingly difficult to get large solar farms approved. ��Some of that resistance is rational and some of that resistance is somewhat irrational. We��re actually battling organized resistance to the deployment of renewables,�� he said.

That opposition, Van Clief said, ��causes us to be incredibly thoughtful about where we site potential projects.�� Former mine lands and other ��previously disturbed areas�� tend to be less controversial sites and inject investment into communities that mined the coal that powered the United States for most of its industrialized history but have fallen on hard times since.

Sun Tribe, along with another solar developer, Washington, D.C.-based Sol Systems, is working with The Nature Conservancy to build solar projects on former coal mine lands in Southwest Virginia, Eastern Tennessee and Eastern Kentucky, that fall within its Cumberland Forest Project, one of the group��s largest conservation efforts at 253,000 acres.

In Virginia, the state Energy Department, formerly the Department of Mines, Minerals and Energy, helped The Nature Conservancy identify non-forested former mine lands near existing utility lines and other infrastructure, which were then whittled down to avoid areas with important wildlife, habitat or other considerations that made them unsuitable for solar development.

The Nature Conservancy, which holds conservation easements on about 3.1 million acres in 49 states and is one of the largest landowners in the nation, is looking to take that approach across the country. Nels Johnson, senior adviser for renewable energy at the conservancy��s Climate Mitigation Program, said some of the land the organization controls doesn��t have ��direct conservation value.�� They may be buffer areas, or part of a larger property that was purchased for conservation or agricultural leases next to a natural area, and may be suitable for renewable development.

A forthcoming report, Mining the Sun, will lay out a case for ��strategically siting new energy infrastructure on degraded lands like mining sites, landfills and brownfields�� in order to help meet the ambitious decarbonization goals of states, corporations, utilities and the federal government. The organization also has a hand in the development of the Bright Night Starfire Renewable Energy Center, an 800-megawatt solar project that is billed as the largest renewable power project in Kentucky and one of the largest in the nation to be built on former minelands.

��That uncertainty that minelands and brownfields introduce compared to greenfields is one of the challenges we��re trying to address,�� Johnson said.

In the case of the Cumberland Forest project, the conservancy and the Virginia Department of Energy helped assure Sun Tribe that it wasn��t ��onboarding additional liability�� as a result of building on the former minelands, said Betsy Arlen, the company��s vice president of real estate.

Building solar on former mineland is picking up steam across the country, from West Virginia and Vermont to Ohio and Nevada. The U.S. Environmental Protection Agency says there may be as much as 43 million acres of brownfields suitable for renewable power development.

States can inventory the minelands in their state (and in some cases under their control) then analyze where nearby electric infrastructure is in order to gauge the possibilities for renewable power, Johnson said. Then they could explore whether redevelopment authorities could help turn brownfields into power projects by creating streamlined permitting processes and other incentives.

Meeting decarbonization targets will require a buildout of electric infrastructure on the scale of the U.S. highway system, Johnson said, and it makes sense to find the least controversial sites for development.

��There��s definitely a need for us to think more clearly about how do communities that host these projects receive benefits,�� Johnson said. ��Every community in the country is going to see clean energy projects over the next several decades.��

A coal-fired power plant in Romeoville, Illinois, as a polar vortex increased demand from power systems across the Midwest, Feb, 1, 2019. (Photo by Scott Olson/Getty Images)

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 American electric grid 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 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 FERC meeting Thursday, 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.

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)

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, including Kentucky, 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.��

A hydrogen hub is a a cluster of assets that produce and process hydrogen fuel as an alternative to fossil fuels. (Screenshot from Office of Energy Efficiency and Renewable Energy)

The Friday announcement that seven projects had been selected to receive $7 billion in seed money to kickstart the production of clean hydrogen across the country was billed by President Joe Biden��s administration as a major step toward slashing carbon emissions, creating thousands of domestic jobs and positioning the U.S. as a clean energy leader.

��I��m here to announce one of the largest advanced manufacturing investments in the history of this nation,�� Biden said during an appearance in Philadelphia.��Seven billion dollars in federal investments that��s going to attract $40 billion in private investments in clean hydrogen.��

However, there��s also criticism over a lack of transparency by the Department of Energy around the application and selection process and those who are dubious about the ways some of the newly minted ��hydrogen hubs�� intend to produce the gas, which the administration called ��crucial to achieving President Biden��s goal of American industry powered by American clean energy.��

Hydrogen, which releases no carbon emissions when burned, is seen broadly as a key part of cutting emissions from hard-to-decarbonize sectors of the economy, such as steelmaking and cement manufacturing, aviation, shipping and other areas. There��s more controversy around uses like blending it with natural gas to burn in power plants or for heating. How climate-friendly hydrogen is depends on how it��s produced. Currently most hydrogen in the U.S. is produced using natural gas, so-called ��gray�� hydrogen. ��Green�� hydrogen is produced by an electrolysis process with clean energy. ��Blue�� hydrogen is fossil-fuel derived but coupled with carbon capture, in which CO2 is filtered out of emissions and stored.

Four of the projects (the Appalachian, Gulf Coast, Heartland and Midwest hydrogen hubs) that the DOE announced as winners will use fossil fuels to produce hydrogen. (In the bipartisan infrastructure law, Congress required that at least one hub ��demonstrate the production of clean hydrogen from fossil fuels.��)

��There are so many ways hydrogen can go wrong. �� We��re really concerned with the number of projects that rely in part or in whole on fossil fuel-based hydrogen production,�� said Julie McNamara, a deputy policy director at Union of Concerned Scientists�� climate and energy program. ��For hydrogen to be a clean energy solution, it has to be cleanly produced and it has to be strategically used.��

In some scenarios, environmental groups worry the hydrogen could actually increase U.S. greenhouse gas emissions.

A report last month by the Institute for Energy Economics and Financial Analysis, an Ohio nonprofit, found that the U.S. government ��significantly understates the likely impact of producing hydrogen from fossil fuels on global warming.�� The assumption that 1% of the methane being used to produce hydrogen will be emitted into the atmosphere is ��far less than recent peer-reviewed scientific analyses have found and that has been identified by airplane and satellite emission surveys,�� the report says. It also notes that using fossil fuels to make hydrogen cleanly depends on the ��overly optimistic and unproven assumption that hydrogen production projects will be able to capture almost all of the carbon dioxide they create.��

In short, said David Schlissel, one of the report��s authors, blue hydrogen is not a great idea when you consider emissions from the entire process, from producing natural gas to shipping and storing the hydrogen and the unknowns of trying to use carbon capture and storage at scale.

��We fear, and it��s based on our analysis, that the money the government is going to spend on blue hydrogen production is going to result in the continued emission of greenhouse gases for decades,�� he said. ��We worry about the waste of money. But we really worry about the waste of time and giving fossil fuel companies the opportunity to build infrastructure that depends on their continued operation. That��s the real concern, to keep the world addicted to fossil fuels.��

That��s the concern with all of this hydrogen hype.��

Schlissel and other critics also questioned the lack of details released by the Department of Energy about the projects, noting that much of the application materials have been treated as trade secrets by the states and the DOE. It��s unclear how the DOE scored the projects for funding, he added.

��How much hydrogen is going to be produced? What are going to be the CO2 emissions? How much CO2 is going to be captured? Then, where is it going to be used?�� he said. ��DOE and the applicants have taken the position that everything is confidential.��

The department��s press office did not respond Friday to a list of questions, including one about how projects were evaluated.

��We would encourage the DOE to be as transparent as they possibly can, especially for the communities where they��ll be proposed,�� said Patrick Drupp, director of climate policy for the Sierra Club, one of the nation��s largest environmental groups.

��This is not trivial��

Perhaps even more important than the hub applications that were selected, Drupp and McNamara say, are the debates ongoing at the Internal Revenue Service around the final rules for the hydrogen tax production credit created by the 2022 Inflation Reduction Act.

��While these hubs are large and there is a significant amount of money on the table, the hydrogen production tax credit could potentially dwarf that amount of money,�� McNamara said. ��That makes it all the more critical that how the administration determines what is truly clean energy is rigorously done.��

The final shape of those rules, which are linked to the intensity of greenhouse gas emissions of the hydrogen source, could be the difference between a boon and a boondoggle on the scale of the biofuels industry, a pair of climate economists wrote in a recent Washington Post op-ed.

��Using fossil-generated electricity or siphoning off renewables subsequently back-filled by fossil power to operate electrolyzers �� which would occur under loose guidance �� generates at least twice the carbon emissions that status-quo gas-derived hydrogen emits,�� a coalition of environmental groups, developers and other organizations wrote to the Treasury Department in February. ��Weak guidance could therefore force Treasury to spend more than $100 billion dollars in subsidies for hydrogen projects that result in increased net emissions, in direct conflict with statutory requirements and tarnishing the reputation of the nascent ��clean�� hydrogen industry.��

Groups like the Natural Resources Defense Council and the Rocky Mountain Institute say the final rules should incorporate a ��three pillars�� approach. The first is ��additionality,�� meaning a new hydrogen electrolyzer that is connected to the electric grid is responsible for ensuring the added electric demand they are creating is being met by new low-carbon generation. The second is ��time-matching,�� requiring electrolyzers�� electric consumption to match its hydrogen production. The third pillar, deliverability, would require hydrogen producers to get clean electricity from within their region.

McNamara said the guidance is expected to be finished by the end of the year.

��This is not trivial,�� she said. ��Hydrogen can be a valuable tool for the clear energy transition but it is not a given �� and getting it wrong comes with enormous consequences for climate and public health.��

Electric utilities spend billions of dollars across the country on smaller lines and replacement lines that fall below the requirement for state or federal review and then pass those charges on to customers. (Photo by Robert Zullo/States Newsroom)

Electric customers have fallen into a ��regulatory gap�� that��s allowed billions of dollars of transmission construction to happen without oversight of need, prudence or cost effectiveness, according to a complaint filed with federal regulators by the Office of the Ohio Consumers�� Counsel.

And though the complaint to the Federal Energy Regulatory Commission was made on behalf of Ohio ratepayers, the same concern exists across much of the nation, so much so that the commission itself has weighed whether more monitoring of transmission spending is necessary.

FERC has broad authority over electric transmission, but utilities are taking advantage of what critics call an inadequate regulatory regime and spending billions of dollars across the country on smaller lines, replacements for old wires or new projects that fall below the threshold for federal or state review as to whether they��re actually needed or make financial sense.

��Pretty much in every state there��s going to be some subset of transmission that��s not going to be subject to some regulatory scrutiny,�� said Nick Guidi, a senior attorney with the Southern Environmental Law Center who focuses on transmission planning and other electric grid issues.

Often what utilities make on those projects are set through FERC ��formula rates,�� which, instead of relying on a contested rate case to establish the utility��s cost of service for transmission, allows the companies to file information with FERC in various categories �� including rate of return, operations and maintenance, depreciation, taxes and other factors �� that is used to calculate what they��re able to charge customers.

��Formula rates are a vehicle for avoiding burdens of proof and limiting protests. The commission��s default presumption that all transmission expenditures are prudent allows utility costs to flow through to consumers�� bills without scrutiny,�� wrote Ari Peskoe, director of Harvard University��s Electricity Law Initiative, in comments filed with FERC last year. The rules, Peskoe said in an interview, ��push utilities to invest locally because that��s where you can get the easy money.��

Andrew French, a member of the Kansas Corporation Commission, said last year that transmission costs on an average Kansas electric customer��s bill had gone from $4 a month about a decade ago to $20 in 2022, a situation that ��screams out for more oversight.�� In North Carolina, a state regulator told FERC officials last year, state regulatory review is only triggered for lines 161 kilovolts or larger, which leads to lots of construction of smaller lines that his office doesn��t find out about until ��it shows up in rates.��

At 16.42 cents per kilowatt hour, Ohio ranked 18th in the nation (highest to lowest) for residential retail electric prices as of June 2023, according to the U.S. Energy Information Administration. That was up from 9.76 cents per kilowatt hour in 2021, when the state ranked 32nd. Transmission and distribution costs are only a portion of that, but they have led to ��significant increases�� in customers�� bills, the consumers�� counsel said in its complaint, filed Sept. 28. However, a spokesman for the office said it does not have ��comprehensive data on how the transmission and distribution charges (as a percentage of total electric rates) on individual customer bills have increased over time.��

The consumers�� advocate complaint says that more than 85% of utilities�� proposed new transmission spending was for ��supplemental projects,�� meaning local projects that are not subject to need, prudence or cost effectiveness review by the state��s Public Utilities�� Commission, its Power Siting Board, or PJM, which is the regional grid operator for Ohio.

��Instead, these PJM governing documents assume that state regulatory authorities will adequately protect consumers regarding the need, prudence and cost of supplemental projects,�� the complaint says. ��That assumption is misplaced.��

The Ohio Power Siting Board is responsible for overseeing environmental effects, reviewing potential alternative locations and the need for some electric facilities, but that authority is limited to transmission facilities rated at 100 kilovolts and above and it does not review any projects for cost effectiveness, the consumers�� counsel says. The Public Utilities Commission of Ohio ��likewise has declined to review the need, prudence and cost-effectiveness of these planned local transmission facilities in Ohio, despite OCC requesting it to do so,�� the complaint notes.

Tammy Ridout, a spokesperson for American Electric Power, one of the utility companies named in the filing, said the company is reviewing the complaint. AEP Ohio has more than 1.5 million customers in the state.

��We��re committed to transparent transmission planning as we work to provide reliable, affordable service to customers,�� Ridout said. She added that PJM��s existing process for planning so-called supplemental projects ��is one of the most robust and transparent processes in the nation�� and a similar framework is being proposed for other regions by FERC in a new rule the agency is working on dealing with transmission planning and cost allocation.

In a news release last year, AEP said it plans to spend $26 billion between 2023 and 2027 on transmission and distribution operations ��to continue building a modern, efficient, reliable and resilient energy grid.��

Ferreting out ��gold-plating��

Jeff Shields, a PJM spokesman, said FERC ��has made it clear that certain asset management activities, such as end-of-life decisions that do not expand the transmission system, are specific to the individual transmission owners.�� For those supplemental projects, he said the organization has ��successfully worked with stakeholders to enhance the transparency of planning�� and incorporated them into PJM��s bigger regional planning efforts.

The Consumers�� Counsel wants FERC to put in a ��backstop�� to protect Ohio electric customers by changing the rules (called a ��tariff��) that govern PJM.

��By this mechanism, FERC would review the need, prudence and cost-effectiveness of local transmission projects in Ohio,�� the complaint says. ��Any utility gold-plating �� should be ferreted out by regulators.��

The Edison Electric Institute, an association for investor-owned utilities, projected that its members would spend about $87.8 billion on transmission and distribution this year. Given that, and how much work is needed to upgrade an aging grid to bolster reliability and accommodate the transition to more renewable power, it��s crucial to make sure ratepayers aren��t being subjected to ��gold-plating,�� meaning overspending on capital projects to boost profit margins, Guidi said.

��It makes rates go up but it also makes utilities a lot of money. It��s important that it��s carefully policed,�� Guidi said. ��Otherwise utilities are going to make a lot of money at the expense of ratepayers without a lot of appreciable gain.��

The Ohio Consumers�� Counsel also encouraged FERC to appoint an independent transmission monitor to review ��planning, need, prudence and cost-effectiveness of local transmission projects for consumers in Ohio.�� Independent monitoring has been part of discussions between FERC commissioners and state regulators, many of whom say they often lack the expertise and authority to vet utilities�� local transmission spending.

The Ohio agency also wants FERC to bar Ohio utilities from using formula rates for transmission, preferring that Ohio transmission utilities get prior FERC approval ��for all local transmission projects at or exceeding a set cost threshold.��

��FERC needs to step in now and halt the harm to Ohio consumers,�� the complaint says.

What the commission might do is unclear.

The commissioners could dismiss the complaint by finding that the consumers�� counsel hasn��t made the case that the rates resulting from the lack of transmission oversight are unjust and unreasonable, said Guidi, the SELC attorney. Or it could ��kick the can down the road,�� he said, and examine the issue as part of a bigger proceeding

The agency is grappling with several transmission issues, including its draft rule on transmission planning and cost allocation. On Oct. 4, more than 230 state legislators from 43 states sent a letter to FERC asking the commission to finalize and strengthen that rule.

The Ohio complaint, Peskoe said, is more evidence of a broken system for transmission development oversight.

��FERC already has reams of evidence that its rules fail to protect consumers and incentivize utilities to rebuild last century��s transmission network,�� he said. ��FERC is, first and foremost, a utility regulator that is supposed to prevent monopolists from abusing their local market power.��

A fire large enough to be seen from space erupted at a crude oil refinery at the Philadelphia Energy Solutions Refining Complex on June 21, 2019, in Philadelphia. The refinery exceeded emission limits for benzene, a toxic pollutant, both before the explosion and for two years after it closed, but the EPA took no action against it, according to a report from the EPA��s inspector general office. (Photo by Eduardo Munoz Alvarez/Getty Images)

The federal Environmental Protection Agency must do a better job ensuring that oil refineries that exceed emissions limits for benzene, a toxic, carcinogenic pollutant, cut those concentrations, the agency��s inspector general found.

��Thirteen of the 118 refineries we reviewed had benzene concentrations above the action level in 20 or more weeks after the initial exceedance,�� says the report released Sept. 6, by the EPA��s Office of Inspector General. ��These refineries may not have accurately identified the root cause of their exceedances or taken appropriate corrective actions. Despite the existence of potential issues, the EPA and delegated authorities took limited formal enforcement-related actions at refineries under the benzene fenceline monitoring regulations.��

The EPA estimates that most benzene pollution from refineries comes in the form of ��fugitive emissions�� like leaks from tanks or equipment and don��t come from a stack or vent, making them difficult to monitor. In 2015, the agency required oil refineries to monitor benzene concentrations along their perimeters, called ��fencelines.�� If annual average concentrations exceed a so-called ��action level�� of 9 micrograms per cubic meter, the facilities are supposed to find the cause of the emissions and take action to reduce them, the IG report says.

That action level is based on modeling, not on a health standard or risk to nearby communities. The EPA reasoned that refineries wouldn��t have benzene concentrations above the fenceline action level if they were complying with pollution control requirements. A separate concentration of 29 micrograms cubic meter has been established by the Agency for Toxic Substances and Disease Registry and serves as ��an estimate of the amount of benzene a person can breathe each day for up to two weeks without an appreciable risk of adverse noncancer health effects.��

Of the 25 refineries across the country that exceeded the action level, 18 also exceeded that minimum risk level in sampling periods, the report says. Fourteen of them are in communities with environmental justice concerns, specifically those with high percentages of low-income residents and or residents of color.

��If refineries do not reduce their benzene concentrations after exceeding the action level, nearby communities could be exposed to benzene concentrations that increase the risk of adverse health effects,�� the Inspector General Office said.

In a podcast published by the IG office, Andrea Martinez, the auditor in charge of the report, said her office examined 118 refineries that submitted their fenceline monitoring data to the EPA between February of 2018 and September of 2021. Over that span, average benzene concentrations for all the refineries decreased, but 25 refineries, or 21%, exceeded the action level standard at least once.

��Three never did manage to reduce their benzene concentrations to or below the action level during our period of analysis, while another six that successfully reduced their benzene concentrations ended up once again exceeding the action level,�� Martinez said.

She noted that refineries exceeding pollution limits may not be finding the true root cause of the pollution or not taking appropriate action.

��For example, we looked at eight corrective plans submitted by four refineries and found that only one refinery managed to reduce and keep its benzene concentration to or below 9 micrograms per cubic meter for 10 subsequent weeks,�� Martinez said.

Of the nine refineries with the worst benzene pollution, EPA only took action against one.

That refinery was the HollyFrontier��s Navajo Refinery in Artesia, New Mexico, which got a notice of violation in May of 2020. The IG noted that EPA, however, did not take action against the second-highest scoring facility for benzene concentrations, Philadelphia Energy Solutions, which exceeded action level in 44 sampling periods and submitted a corrective action plan in June of 2019, shortly before massive explosions at the refinery.

��The refinery exceeded the action level in the majority of two-week periods for more than two years after ceasing operations, and no enforcement action was taken,�� the report says.

Neither did state agencies, who are delegated by EPA to enforce environmental laws like the Clean Air Act, didn��t initiate enforcement action against any of the facilities over their benzene pollution, the report found.

��For example, one state told us that enforcement of the regulations is challenging because an exceedance of the action level is not in and of itself a violation,�� the IG Office said. ��In addition, one state told us that enforcement is challenging because the regulations do not contain a time frame or number of sampling periods by which a refinery must correct an exceedance. Thus, delegated authorities may be unsure when enforcement action may be warranted or should be taken.��

Eric Schaeffer, a former EPA director of civil enforcement who now heads the Environmental Integrity Project, which advocates for effective environmental law enforcement, said part of the problem is a lack of a clear ��finish line�� for corrective action plans in the existing regulations.

In effect, a refinery can wind up in a ��doop loop�� of pledging fixes and submitting corrective plans while still exceeding benzene limits.

��They have the authority to do something. And they should use it,�� Schaeffer said of the EPA. ��And that authority would be to come in, investigate and say ��You��re not doing enough.����

An EPA spokesman said the agency had no comment on the report.

However, in its response to the inspector general, the EPA said it agreed with recommendations to provide more guidance to state and local agencies that have delegated authority to enforce rules on what constitutes violations of the benzene regulations. The agency also largely agreed with recommendations that it develop an internal strategy for refineries that fail to reduce their benzene levels, including best practices for monitoring concentrations, verifying that an ��appropriate corrective plan that addresses the root cause and actions�� has been submitted and taking action at refineries that fail to do so, among others.

Schaeffer said the revelation in the report that benzene levels have been falling generally is welcome news. ��The encouraging thing is the numbers have come down for many refineries.. It��s just there��s a group that hasn��t broken the pattern. There hasn��t been enough action,�� he said.

The IG report comes as the EPA is proposing to extend the fenceline monitoring system to chemical plants, he noted. ��It points to a serious loophole that really needs to be closed to make it work and it should to protect public health,�� he said.

EPA enforcement staff, he added, know ��that fenceline monitoring makes a difference and gives them a way to track what��s getting out of the facility.��

CORRECTION: An earlier version of this story gave an incorrect number for the refineries reviewed by the EPA Office of the Inspector General because of an error in the original report. The article has been corrected to reflect the correct number, 118, and link to the corrected report.

A PPL Electric Utilities employee installs a dynamic line rating sensor onto a transmission line in Pennsylvania from a helicopter. The sensors allow utilities to take into account wind speed, cloud cover and other conditions to determine if a line has more capacity.? (Courtesy of PPL Electric Utilities)

Of the many challenges confronting the nation��s aging, straining electric grid, the need for a lot of new transmission capacity is among the most pressing, experts and policymakers say.

Earlier this year, the U.S. Department of Energy said the nation will need thousands of miles of new lines to better link regions to handle extreme weather, reduce costs and connect new renewable energy projects.

But building a new interregional transmission line can take a decade or more �� chiefly because of siting and permitting delays, local resistance, planning problems, cost allocation and other obstacles.?

And while Congress has taken some steps on permitting reform (in this summer��s debt limit deal), there��s a suite of technologies that proponents and some state and federal regulators agree could get more out of the existing transmission system right now and potentially reduce the need for new wires.

They��re called ��grid-enhancing technologies,�� or GETs in industry shorthand, and in many cases they��ve been embraced elsewhere but have been slower to take root in the United States.

��If we don��t squeeze every drop out of the existing system it��s going to be a tough sell as we consider the costs involved in transmission expansion,�� said Dan Scripps, chair of Michigan��s utility commission, at a Federal Energy Regulatory Commission task force meeting last month. ��And I believe that grid-enhancing technologies can help us do that to maximize the value from the infrastructure that we have today. ��

What are GETs?

Grid-enhancing technologies include a variety of tools to maximize the ability of the grid to handle the flow of electricity. They include sensors, power-flow devices, software and hardware that can better deliver real-time weather data and other technologies like topology optimization, which can identify the best grid configurations and route power flow around bottlenecks. Think of the electric grid as a road system and grid-enhancing technologies as traffic control devices and variable speed limits that can help alleviate congestion, a Department of Energy paper says.

And congestion on the nation��s electric grid is a real problem. Defined broadly, congestion in electric terms means any time physical constraints on the power system prevent the cheapest power from flowing to customers, which, naturally, raises costs.

��For example, the flow of power may be restricted by the maximum thermal limit of a transformer or power line conductor,�� the Department of Energy says. ��Therefore, operators are forced to reroute power through less optimal paths and rely on more expensive power generation, like conventional fossil fuels, while curtailing renewable wind or solar to safely meet the demand of their customers.��

A report released in July by Grid Strategies, a consulting firm that works to integrate renewable power into the electric grid, found that congestion costs (after doubling between 2020 and 2021) rose to $12.1 billion in 2022, an increase of 56% from 2021, in regions of the country controlled by six large regional transmission organizations. By extrapolating that increase to the rest of the U.S., the firm estimated that the total cost to electric customers of congestion in 2022 was nearly $21 billion.

��The best way to reduce transmission congestion is to increase transmission capacity. However, very little of transmission spending is on new large-scale, high-voltage transmission lines,�� Grid Strategies wrote. ��In addition, few U.S. utilities have adopted dynamic line ratings, advanced power flow control or topology optimization (together known as Grid Enhancing Technologies or GETs) to make more efficient use of existing grid infrastructure.��

Why adoption of GETs has lagged

There was broad consensus at the seventh meeting last month of FERC��s Joint Federal-State Task Force on Electric Transmission that GETs could yield big cost and reliability benefits for grid operators and electric customers.

��Perhaps the most compelling case to me for these technologies is that right now they can reduce grid congestion allowing our markets to consistently access lower cost power and to respond to real time reliability issues. And that��s particularly important when we��re dealing with extreme weather events,�� said Andrew French, a member of the Kansas Corporation Commission who serves on the task force.

So why aren��t these types of technologies more prevalent in the United States?

The biggest reason, grid experts say, is how utilities earn money for grid upgrades and how their performance is measured.

��Utilities are not necessarily directly economically impacted by the inefficient use of transmission infrastructure,�� said Darcie Houck, a California utilities commissioner who also serves on the task force, adding that often utilities pass on congestion costs to power generators and customers. ��Utilities are financially motivated to build more capital-intensive transmission projects to grow their rate base which they earn a return on. �� GETs may defer or negate the need for such capital projects thereby reducing utility revenues.��

Part of the reluctance also stems from a need for grid operators to ��validate the technologies on their own system because there are not references publicly available on performance, integration, and deployment,�� the Idaho National Laboratory wrote in a report last year.

Also creating hesitance is a lack of industry standards and specifications for some of the technologies, as well as potential security concerns, said Andrew Phillips, vice president of transmission and distribution at the Electric Power Research Institute, during the FERC task force meeting.

��When a new technology comes to market, we need a spec to buy to. We need to be confident it��s going to last 30 or 40 years. And that��s a really important thing and often a barrier,�� Phillips said, adding that EPRI, a research and development nonprofit, has developed testing for some technologies like advanced conductors and is working on standards for others.

��We need an industry accepted way of evaluating these technologies, incorporating them into our plans and then exercising those plans.��

Yet, despite the past resistance, some see attitudes among utilities changing.

��Ratepayers aren��t going to pay for twice as much grid as we have today so they have to look at other solutions,�� said Julia Selker, chief operating officer at Grid Strategies as well as the executive director of the WATT Coalition, which is pushing for broader adoption of GETs. ��I see a mindset shift.��

A push from FERC and the states

FERC has taken recent steps to get more out of the existing transmission system and push for consideration of new technologies.

In 2021, FERC issued a final rule requiring transmission providers to use ��ambient-adjusted ratings�� for transmission lines that take into account actual air temperature and other weather conditions, instead of limiting a line��s capacity based on conservative, worst-case assumptions.

The order also opened the door for transmission owners to explore ��dynamic line ratings,�� a more real-time rating that can account for other factors that might increase line capacity, like wind speed, cloud cover and other conditions.

This summer,? PPL Electric, which has about 1.4 million customers in eastern and central Pennsylvania, won an industry award for being the first American electric company to install and integrate a dynamic line rating system within its transmission management and market operations. The technology will save its customers�� an estimated $23 million per year in congestion costs, the company says. A 2021 report commissioned by the WATT Coalition contends that deploying GETs nationwide would save more $5 billion a year in energy costs, against an upfront investment of $2.7 billion in the first year.

In July, as part of its effort to help clear backlogs of new power projects seeking to connect to the grid, FERC also required transmission providers to consider grid-enhancing technologies in their interconnection studies. And another proposed rule could also require their consideration in transmission planning.

��GETs belong in long-term planning,�� Selker said. ��If you��re not considering GETs than you��re not making the most efficient decisions for customers.��

But there��s been some reluctance among FERC commissioners to mandate any specific technology.

��We need to really listen to the engineers on this,�� Commissioner Mark Christie, a former Virginia utility regulator, said. ��There��s tremendous benefit if you get it right. There��s not benefit if you don��t.��

In a concurrence filed on the new interconnection rule, Christie acknowledged the vested interest of transmission owners in building ��costly new transmission assets�� instead of potentially less expensive technologies that could get more out of existing lines. But he also said there was ��plenty of rent seeking�� as well by companies who sell grid-enhancing technologies and the organizations they fund who stand to profit from any regulation mandating their use.

��Striking the appropriate balance �C one that is in the public interest �C is a challenge,�� Christie said.

But there��s also a role for states. Selker said utility regulators in several states, including Michigan, Nevada and North Carolina, have asked their companies to report on their pursuit of federal funding for grid upgrades. There��s about $14 billion in federal funding available to states, tribes and utilities over the next several years for grid-enhancing technologies and other upgrades.

Caitlin Marquis, a managing director at Advanced Energy United, a trade group for clean energy companies, called the FERC requirement that GETs be considered in interconnection a small first step.

��There is a requirement to evaluate these technologies, there is a reporting requirement, but there is a lot left to transmission providers�� discretion. �� It��s to be seen whether it results in increased use of GETs,�� she said. ��GETs is definitely an area where there is state interest and states could definitely be playing a bigger role in ensuring they get considered.��

Several state regulators on the FERC task force took a similar view.

��We need to squeeze every bit of value out of our existing system for the benefit of our ratepayers,�� said Kimberly Duffley, a North Carolina utilities commissioner. ��One thing state commissions can do is evaluate their existing rules to ensure they��re creating conditions for GETs to be considered where appropriate.��

Marissa Gillett, chair of the Connecticut Public Utilities Regulatory Authority, said it��s up to state and federal regulators to develop shared savings and other programs to push utilities to consider ��non-wires�� grid solutions, combining ��a healthy disincentive with potential incentives.��

��Our ratepayers need us as regulators, whether state or federal level, to define the rules of the road and to insist on a fuller accounting of how an incumbent [utility] lands on a capital intensive solution,�� she said. ��I do think we need to go beyond the simple instructions that GETs should be considered.��

She noted that utility decisions on what to build aren��t made just on engineering merits in a vacuum.

��We should all trust but verify but also encourage and enforce if necessary,�� she said.

The Blue Creek wind farm in Ohio consists of 152 wind turbines with a total capacity of 304 megawatts. The Federal Energy Regulatory Commission has finalized new rules that are expected to help ease the backlog of new wind, solar and battery storage projects awaiting regulatory approval. (Robert Zullo/ States Newsroom)

The Federal Energy Regulatory Commission on Thursday finalized long-awaited new rules intended to reform how power generation projects get connected to the electric grid, seen as a major step in smoothing the path for thousands of mostly renewable power projects currently waiting to plug in.

��This rule will ensure that our country��s vast generation resources are able to interconnect to the transmission system in a reliable, efficient, transparent and timely manner,�� FERC Chairman Willie Phillips said, adding that there are 2,000 gigawatts of power projects stuck in interconnection queues across the nation. ��We have as much generation waiting to be connected to the grid as double the amount of generation currently on the grid.��

Those projects, mostly wind, solar and battery storage plants, have been stuck in massive backlogs while grid managers conduct interconnection studies needed to gauge how bringing them online would affect the broader system and determine whether any upgrades are needed.

��We have wait times of over five years. The average project needed today won��t even begin construction until 2028,�� Phillips said.

Existing processes were set up at a time when there were relatively few new power plants (generally gas fired) coming online and there was plenty of excess transmission line capacity, said Ari Peskoe, director of the Electricity Law Initiative at Harvard Law School. Now, the vast majority of the projects in the queue are renewables that are generally more numerous and diffuse and smaller in output. And there are many areas where transmission is constrained.

The resulting delays are imperiling states�� renewable power goals, causing projects to wither on the vine as developers confront rising costs and supply chain problems and depriving local economies of jobs, not to mention the carbon-free electricity they promise to deliver, critics contend.

FERC��s new rule requires transmission providers to use ��cluster�� studies that allow for studying numerous proposed projects at once rather than individually in a ��first-come, first-served�� fashion. A cluster approach that is redone each year also is better able to adapt when interconnection customers who are higher up in the queue drop out, reducing the need for ��cascading restudies,�� FERC staff said. At the same time, the rule requires increased financial commitments for interconnection customers to enter and remain in the queue, meet more stringent site control requirements and imposes penalties on customers who withdraw from the queue.

��These reforms will discourage speculative, commercially non-viable interconnection requests and allow transmission providers to focus on processing interconnection requests that have a greater chance of reaching commercial operation,�� FERC staff wrote.

For transmission providers, which can be big, regional entities called regional transmission organizations or independent system operators, or individual utilities depending on the part of the country, there are also firm study deadlines and penalties if they are not met, and uniform modeling standards.

And, among other components, another major piece pushes more adoption of technological advances into the interconnection process, such as allowing more than one generation facility to co-locate on a shared site behind an single interconnection point and share an interconnection request. There��s also a requirement that transmission providers model battery storage resources in the way they are actually used rather than unlikely worst-case scenarios and require evaluation of a suite of options called ��grid-enhancing technologies�� that can save money and time.

��It��s fair,�� said Commissioner Allison Clements. ��The final rule requires everyone to do their part to address the cause of interconnection backlogs.��

Reforms a start, but problems will remain

Though renewable energy industry representatives and clean power proponents called the reforms a good start, they say the rule, first proposed last summer, will leave many problems the energy transition has presented for grid managers and regulators unresolved.

��The bigger picture issues of why we don��t have enough transmission in this country are not going to be solved through this rule,�� Peskoe said.

John Moore, director of the Sustainable FERC Project at the Natural Resources Defense Council, said the rule ��will raise the floor on action, but the ceiling will depend on grid operators taking leadership and increasing the capability and capacity of the grid. The devil will be in the details.��

Roughly two-thirds of American electric customers live in an area where electric flow is managed by a regional transmission organization (RTO) or an independent system operator (ISO), who also run power markets. In the rest of the country, the grid is run by utilities that are typically vertically integrated (meaning they��re responsible for generating, transmitting and distributing electricity to their customers) who do their own transmission planning. The new rule will apply to both types of regimes, which will have to submit filings to FERC explaining how they��ll comply, Peskoe said. Several RTOs have already been implementing their own queue reform, however.

��We need to fashion this in a way that moves the ball but doesn��t get in the way of what they��re already doing,�� Commissioner Mark Christie said.

The Midcontinent Independent System Operator, or MISO, which coordinates electric flow for a region of the central U.S. and Gulf Coast that includes all or part of 15 states, proposed a series of reforms that includes increased interconnection payments and penalties for withdrawal.

��Changes are needed to better manage the number of speculative requests in future queue cycles, which will reduce processing time and ensure more certain and timely study results,�� a MISO spokesman said.

PJM, the largest U.S. regional transmission organization, also began a transition to a new interconnection process this month.

Faster approvals could bring jobs

In a report released last month that looked just at PJM, the American Council on Renewable Energy, a nonprofit working to accelerate the transition to renewable energy, found that if PJM was approving projects at the same pace as it did from 2011 to 2016, the 34 gigawatts of renewable power in its queue would be operating within the next four years. That would mean thousands of jobs and about $33 billion in investment for the PJM region, which includes 65 million people in all or parts of 13 states and the District of Columbia. Virginia, Illinois, Ohio and Indiana were the biggest potential beneficiaries.

In interviews, several grid experts said fixing transmission planning and making upgrades is equally, if not more, important than interconnection reforms for getting large amounts of new resources connected to the grid quickly.

��If a transmission provider says ��Congratulations, you��ve got your agreement, this is going to take six plus years before you can interconnect,�� that��s going to be fatal to a lot of projects,�� said Jason Burwen, vice president of policy and strategy at GridStor, an Oregon company that has 2 gigawatts of battery storage projects under development.

Peskoe noted that much of the nation��s transmission planning is being driven by individual projects�� interconnection process, which he called a ��piecemeal, inefficient way to go about building an interstate transmission system.��

Several other experts compared it to building a highway system one lane at a time.

FERC is working on another proposed rule on regional transmission planning and cost allocation that it will finalize ��in the months ahead,�� Phillips said.

��Together, this interconnection queue reform, with long term and regional planning �� we will have the greatest transmission reforms in a generation to come out of FERC,�� he added. ��This is a good day.��

Several fossil fuel plants went offline during recent winter storms either because their equipment froze or because they couldn��t get fuel, leading to blackouts in some regions. (Photo by Scott Olson/Getty Images)

From winter storms to sweltering summer heat, there��s a consensus among experts that increasing extreme weather, a shifting electric generation mix, delays in getting new power generation projects connected and the difficulties in getting new transmission lines and other infrastructure built all pose an increasing risk to the grid.

At U.S. Senate committee hearings as well as Federal Energy Regulatory Commission meetings, there have been plentiful warnings over the past few months about a coming reliability crisis.

Much of the debate has centered on what U.S. Sen. John Barrasso, a Wyoming Republican, characterized at a hearing last month as ��reckless policies�� aimed at limiting pollution from existing power plants, retiring older fossil fuel generation facilities and speeding the transition to cleaner sources of energy to mitigate the consequences of climate change.

But there��s been less sound and fury about one of the biggest factors in recent severe weather blackouts, like those across parts of the South during Winter Storm Elliott, when large numbers of fossil fuel plants, particularly those fired by natural gas, tripped offline because of freezing equipment, inability to secure fuel and other failures.

��The overwhelming threat to reliability right now is fossil plants failing to perform in the winter,�� said Tom Rutigliano, a senior advocate at the Natural Resources Defense Council��s Sustainable FERC program.

And though FERC approved new power plant winterization standards in February, one? commissioner flatly said they don��t go far enough and pointed out that they don��t become enforceable until 2027.

Winter might seem far off right now with much of the country in the grips of a punishing heat wave, but as it approaches, the grid is still very much vulnerable to severe storms like Elliott and Winter Storm Uri, which caused a catastrophic collapse of the Texas electric grid in 2021 that killed an estimated 246 people.

��Nothing really has fundamentally changed since last winter,�� said Michael Goggin, vice president of Grid Strategies, a consulting firm focused on clean energy integration. ��It��s just a question of do we get lucky and avoid another cold snap.��

��Implement these recommendations now��?

During Elliott, which brought rapidly plummeting temperatures to many parts of the country over the Christmas weekend, rolling blackouts were instituted by the Tennessee Valley Authority, which provides electricity for 153 local power companies serving 10 million people in Tennessee and parts of six surrounding states, Duke Energy in the Carolinas and several utilities in Kentucky, cutting power to hundreds of thousands of customers.

PJM, the nation��s biggest regional transmission organization, coordinating electric flow for 65 million people in parts of 13 states and the District of Columbia, urged its customers to cut usage and avoided blackouts despite losing about 47,000 megawatts of capacity.

TVA said 38 of its 232 generating units were ��negatively impacted, mostly due to instrumentation that froze,�� during the storm, taking thousands of megawatts of power offline as demand surged to historic levels.

In Duke Energy��s territory in the Carolinas, the company lost about 1,300 megawatts of power output mostly from coal and gas (though no plants failed entirely) due to instrumentation issues from the cold and power imports from out of state that failed to materialize, a company spokesman said. Duke��s problems threatened the broader reliability of the broader electric grid that serves more than half the country, called the Eastern Interconnection.

In PJM, gas power plants accounted for 70% of the outages. ��Most outages were caused by equipment failure likely resulting from the extreme cold, though broader issues of gas availability also contributed to the outages,�� PJM staff wrote in a report released July 17.

��There has been a lot of talk that we must preserve the current resource mix, which in PJM is made predominantly of natural gas, coal and nuclear resources,�� said Greg Poulous, executive director the Consumer Advocates for PJM States, at a FERC forum on PJM��s capacity market last month. ��However I have yet to hear someone say that having 20% of coal resources and 23% of natural gas resources fail to perform during Winter Storm Elliott is acceptable. That seems to be lost in all of this.��

In a separate proceeding on an inquiry into what went wrong during Elliott, FERC Chairman Willie Phillips noted that extreme weather has become more commonplace.

��This is the fifth winter storm event that we��ve had in the past 11 years,�� Phillips said. ��So what seems to have been a once-in-a-generation event is now every other year.��

Per a presentation by FERC staff, more than 70,000 megawatts of power generation went offline across the country during the storm, and for strikingly similar reasons as in winter storms in 2011, 2014, 2018 and 2021.

��We��re finding that unplanned generating unit outages continue to be the primary challenge that are seen in all of these events,�� said Heather Polzin, who works in FERC��s Office of Enforcement.

Both FERC and the North American Electric Reliability Corporation, which is charged by federal law with setting and enforcing reliability standards for the North American power system, have repeatedly urged power generators to make the upgrades necessary to improve performance during severe weather.

��Implement these recommendations now,�� Phililps said. ��Right now. We know, to borrow a phrase, winter is coming. Let��s get ready. Let��s stop this. We can do this.��

But there��s been some resistance, particularly from independent power producers who sell their electricity on the open market.

The Electric Power Supply Association, a trade group for competitive power generators, filed a request for a rehearing on the new winterization standards FERC approved, arguing that the standards lacked a cost-recovery mechanism and that their members could be put at a competitive disadvantage. Vertically integrated utilities, which are generally responsible for generating, transmitting and distributing electricity in a given territory, can simply pass the costs of winterization upgrades onto their ratepayers, the association said.

��Competitive generation owners lack similar opportunities,�� EPSA argued, noting that some power plants will also be exempted from the new rules (for technical, commercial or operational reasons). ��The Feb. 16 order not only neglected to give this issue special attention, it gave this issue no attention at all.��

FERC denied the request for another hearing.

��To the extent competitive generators believe that their existing rates do not offer an opportunity to recover the costs �� they may make appropriate filings,�� the commission wrote.

A ��tricky�� fix

So if a major cause of blackouts in severe weather is power plant failures, why can��t federal regulators simply force them to quickly make the upgrades necessary to improve cold weather performance?

It��s not that simple, said Jim Robb, NERC��s president and CEO of NERC.

��In all of our standards that we��ve passed, particularly if they require a change in operating practices or capital investment, you have to give the sector some time to respond to that, so there��s a delay from when you pass the standard to when it��s enforceable,�� Robb said in an interview with States Newsroom. ��In between there, we jump up and down and try to promote early action as quickly as we can.��

The other quandary for regulators, at a time when there��s widespread concern about the pace of power plant retirements, is getting better performance from those units without prompting them to shut down.

��We don��t want to cause an event that would prematurely retire any generation. �� All the stuff that��s kind of the backbone of the electric grid are all under pressure economically and because of other regulatory actions. Our goal isn��t to compound that,�� Robb said.

He added that winterizing plants in the South can be particularly challenging, since they must be able to operate in extreme heat as well as cold.

��At the same time we want to be clear that these plants need to be able to perform under the kind of conditions that we��ve seen five times over the last 11 years, three times over the last five and each of the last two winters,�� he said. ��That��s becoming the norm and that��s got to become much more the planning case for the grid.��

He noted that FERC is directing his organization to take another look at exceptions related to technical feasibility in the new rules that would allow power plants to avoid making the upgrades. When they do come into effect, though, Robb said NERC believes the new standards will prevent the types of power plant failures seen during Uri and Elliott.

��It��s a tricky problem to work through but that��s what FERC came back and said we want tighter language around that,�� Robb said. ��I don��t disagree with them at all.��

The future of gas?

Though the U.S. is currently seen as being in the midst of a big single electric transition (from fossil fuels to renewables) it��s actually at the tail end of an earlier one (from coal to gas) that hasn��t been fully reckoned with from a reliability perspective, according to some grid experts, like Rutigliano of the NRDC.

Natural gas has become a crucial part of the electric generation mix. Coal fell from 52% of U.S. power generation in 1990 to 18% in 2022 as gas climbed from 12% to 40% over that time. That��s made the electric grid that much more vulnerable to outages from gas plants, which depend on deliveries from gas pipelines and don��t typically have fuel on site like coal or nuclear power plants.

��Natural gas has failed at a very disproportionately high rate,�� Rutigliano said.

Although during severe weather many gas power plants failed because of freezing equipment, others were unable to run because they weren��t able to get fuel.

��Where we haven��t seen much progress is making sure the fuel supply is firmed up,�� said Devin Hartman, director of energy and environmental policy at the R Street Institute, a Washington think tank focused on policy solutions. ��We really have to talk about gas industry reforms as well. There��s only so much juice we can squeeze out of this lemon on just the electric side.��

But with gas projected by some to be part of the U.S. electric generation mix for the foreseeable future, it��s crucial to make sure it can perform when called upon. Like it or not, that means more investment in gas infrastructure, Robb said, even as technologies like battery storage come into more widespread use.

��We have like five gigawatts of batteries in California right now, which is spectacular,�� said Robb. ��That is a ton of batteries. It��s a drop in the bucket compared to what you would ultimately need to not have natural gas on the system. �� The batteries we have are doing a lot of really great things, they��re just not everything we need them to do and nor are they likely capable of doing that.��

Hartman said it��s time to have a ��conversation about prudent investment in the gas industry�� so it can perform when needed, such as during severe weather.

��Natural gas, to be totally frank, is going to play a very major role in the electric fuel mix for at least a couple of decades,�� he said.

A 2019 paper prepared for the American Petroleum Council noted that although natural gas power plants had become the largest users of the interstate pipeline system, ��power plants, particularly those in the regional competitive wholesale electricity markets that cover most of the country, are reluctant to contract for firm transportation.�� Firm contracts are those that cannot be interrupted except ��under unforeseeable circumstances,�� per the U.S. Energy Information Administration.

The gas industry is designed, operated and incentivized primarily to serve what Robb called its ��core customers,�� local gas distribution companies, not power plants.

��The gas-electric coordination issues are really very, very significant and also very challenging to resolve. Otherwise they��d be solved,�� Robb said. ��So we��ve got to figure out how to make that interface work in a way that it��s not right now because the failure of natural gas generation has been the common theme throughout each of the five major winter events that we��ve studied.��

However, the North American Energy Standards Board has worked for about a year and a half on a list of recommendations to improve coordination between the gas and electric power industry, he said. They would not be binding though.

Local and regional fixes

While the new power plant standards approved by federal regulators won��t become enforceable until 2027, that doesn��t mean states and the regional entities that coordinate electric flow in much of the country are toothless.

PJM is proposing changes to its capacity market, which was created to ensure power generators provide enough electric generating capacity to meet demand when the grid is under stress, such as during severe summer heat or frigid winter weather. But there��s widespread concern that the system of incentives and penalties to get generators to show up when they��re needed isn��t working.

In North Carolina, regulators at the Utilities Commission are reviewing Duke Energy��s failures during Elliott. ��We always work to improve from every incident and have been applying lessons learned from that event to improve the operations of our plants during extreme conditions,�� Duke spokesman Jeff Brooks said.??

TVA said it has made more than 250 equipment upgrades to guard against a repeat failure. Kentucky regulators have raised the possibility of fining one utility related to its attempt to recoup from ratepayers the cost of emergency power purchased during Elliott, contending that it should have done better planning.

��Our standards and our mission and our charter is to avoid large scale cascading outages,�� Robb, the NERC CEO, said, adding that states could and should check into utility fuel contracts, substation security and whether they have enough power generation on hand, among other issues. ��States have the responsibility to ensure that their customers have power when they need it. �� States are always able to go beyond what we prescribe.��

For some, there��s also a broad need to promote more ��demand response,�� the ability to cut electric demand for some nonessential customers during severe weather. Hartman, from the R Street Institute, said that in Austin during the deadly Winter Storm Uri, ��we were keeping downtown vacant office buildings lit up while people in other parts of the city were without electricity.��

There are calls as well for better planning and ��accreditation�� of the different strengths and weaknesses of generating plants, so grid operators aren��t caught as much by surprise.

��If PJM is counting on gas plants to be available on short notice �� their vaunted flexibility �� then they should be. And they should be paying what they need to to be available if they��ve taken on the capacity commitment,�� said Casey Roberts, an attorney with the Sierra Club, at a FERC meeting on PJM��s capacity market last month. Power generators, in turn, say they need more money from power markets like PJM to ensure they can get gas and be ready when needed.

For some electric grid observers, there��s still a lot the federal government can do. For instance, FERC has been considering whether it should impose an interregional transfer requirement �� a certain amount of electricity that can move between regional systems �� to improve electric reliability. Proponents describe it as creating a grid bigger than the weather.

��It��s an insurance policy against all these events, being able to bring power from another region,�� Goggin said.

Growth in clean vehicle jobs made up approximately 45% of Kentucky��s overall clean energy job growth of 2,389 jobs added last year, the report says.?(Photo by Spencer Platt/Getty Images)

Though they only make up a fraction of cars and trucks on the road now, many projections �� from Wall Street firms, trade groups and automakers themselves �� predict an imminent surge in electric vehicles over the next decade.

S&P Global estimates that the nearly 2 million electric vehicles on U.S. roads today will grow to more than 28 million by 2030, when they��ll comprise 40% of all new cars and trucks sold.

The Edison Electric Institute, which represents investor-owned electric utilities, arrived at a similar forecast last year, even before the passage of the federal Inflation Reduction Act, which contained big incentives to spur electric vehicle adoption.

That means tens of thousands of additional public charging stations will be needed to be built across the country.

But there��s a big debate taking place at state capitols across the country about who should take the lead role in building them �� electric utilities or private businesses?

��That��s what retailers are there for��

The Charge Ahead Partnership, composed of big fuel retailers, grocery chains, convenience stores, gas stations and other businesses exploring installing vehicle chargers, argues that private businesses, particularly those that have been selling fuel to motorists for years and are already located in optimal spots to serve drivers, are best suited to making the switch to electric chargers. And they say they��ll have a tough time competing with monopoly electric utilities who can build charging infrastructure on the back of their ratepayers.

��The utilities are actively laying the groundwork to extend their monopoly into this new business field,�� said Ryan McKinnon, a spokesman for the partnership. ��If you��re going to be driving an EV you��re going to want a reliable network of charging stations. �� You really want entities to provide this that are good at selling things to people. That��s what retailers are there for.��

McKinnon pointed to recent legislation in Oklahoma, Georgia and Texas that imposes limits on utilities using ratepayer money for charging networks. In Georgia, for example, legislation passed this year restricts utility ownership of charging stations to a single program that allows the dominant electric utility in the state, Georgia Power, to provide chargers in remote and rural areas, with private retailers offered a right of first refusal.

��This will ensure ratepayer funds only subsidize EV charging operations in areas where private industry cannot operate,�� the Charge Ahead Partnership said in a news release last month.

But other states, like Minnesota and Colorado, have taken or are considering steps in the other direction. Proposed budget language that would allow utilities to bill ratepayers for electric vehicle charging infrastructure has also come under fire in Ohio.

And in Florida, the nation��s largest utility, Florida Power & Light, is building hundreds of chargers over the objection of critics like former Jacksonville Mayor John Peyton, president of GATE Petroleum, which owns gas stations and convenience stores in Florida, Georgia and the Carolinas. Peyton argued in a Florida Times-Union column that ��no private business would sink $100,000 or more to install EV chargers with the knowledge that some of the state��s most powerful monopolies can undercut them, using your ratepayer funds.��

An ��all-of-the-above approach��?

Some proponents argue, however, that there could be a place for utility-owned charging, since electric vehicles have long posed a chicken-and-egg problem. Mass adoption isn��t likely until drivers are comfortable they can always find a charger. And companies aren��t likely to build chargers until there��s a critical mass of electric vehicles to help them recoup their investment plus a profit.

Katherine Stainken, vice president of policy at the Electrification Coalition, a nonpartisan, nonprofit organization pushing for the widespread adoption of electric vehicles, said there��s too much variation across states and markets to foreclose options like utility ownership. She characterized the debate over who should own charging networks as the ��growing pains�� of a nascent industry.

��We support kind of an all-of-the-above approach,�� she said. ��There��s a lot of different factors here.��

Stainken added that for-profit companies might not be able to meet the needs of, for example, low-income apartment complexes, or instances in which no host comes forward to site a charging station through the National Electric Vehicle Infrastructure (NEVI) program, which is making billions of federal dollars available to states to boost charging infrastructure.

��If there are some areas where there is no site host coming forward, and the utility is the only one �� I don��t think we would want to say ��Forget it,���� she said.

The Edison Electric Institute likewise said the coming surge in electric vehicles requires an ��all-hands-on-deck approach.��

��No one is preventing private-sector stakeholders from investing in EV charging today, and the idea that some stakeholders are trying to prevent electric companies from building EV charging infrastructure is senseless,�� said Kellen Schefter, the institute��s senior director of electric transportation. ��Electric companies are well-positioned to make targeted and strategic investments in EV charging infrastructure that will benefit the broader community and accelerate EV adoption. America��s electric companies have proven expertise and decades of experience in deploying and maintaining electric infrastructure that is safe, affordable and reliable.��

Charging on demand?

Beyond who builds and owns the chargers, however, there are other thorny issues to untangle.

One of the most pressing, according to Angela Holland, president of the Georgia Association of Convenience Stores, which supported the new Georgia law limiting utility ownership of chargers, is how much private businesses who install chargers pay for electricity.

��One of the other things we��ve asked is for our utility friends to come up with an EV charging rate,�� Holland said. ��You can��t go to market with a product and not know whether or not you��re going to make money on it.��

In neighboring Alabama, Alabama Power, which, like Georgia Power, is part of Southern Company, offers a special rate for commercial and industrial customers for public electric vehicle charging stations. Electric usage for charging is metered separately from other uses at the location.

That��s crucial because in many utility billing frameworks, commercial and industrial customers often pay a demand charge based on the maximum amount of electricity they use at one time, usually measured as an interval of 15 or 30 minutes. The charge is meant to compensate an electric company for maintaining the generation and transmission capacity to meet that peak demand, even though it won��t be used all the time.

��Demand charges are intended to help (electric service providers) keep power systems appropriately sized, efficient and more affordable for all consumers,�� says a 2021 report spearheaded by the National Association of State Energy Officials that looked at demand charges and electric vehicle charging in Arizona, Colorado, Idaho, Montana, Nevada, New Mexico, Utah and Wyoming.

Electric vehicle charging infrastructure, though, ��has relatively unique power demands, with high power capacity required for fast charging, but relatively small amounts of energy consumed per charge,�� the report said, noting that demand charges ��are one element that may prevent (direct current fast-charging) station hosts from earning a profit from EV charging services.��

The town of Derry, New Hampshire, pulled the plug on its four free municipal parking lot electric charging stations in 2021 after its utility instituted demand charges and caused the price to spike, officials wrote to the state utilities commission.

McKinnon, the Charge Ahead Partnership spokesman, gave the example of a business that installs a 150 kilowatt charger with four ports, the minimum standard for the federal government��s NEVI program.

��You��re not going to have a ton of usage immediately. But as soon as one person uses it they are probably going to set the new peak usage for the month,�� he said. ��We��re not advocating for any specific rate. �� We��re just saying let��s pick a fair rate.�� Low usage and big demand charges, he added, ��kills the financial incentive�� for businesses to install chargers.

Two loons swim with their chick on Clear Lake in the Boundary Waters Canoe Area Wilderness in an area rich with copper and cobalt deposits. (Photo by Max Nesterak/Minnesota Reformer)

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 has in part led to some clean energy groups joining with traditional industry, fossil fuel interests and their allies in Congress in a push for permitting reform. In the wake of a controversial federal court decision involving an Arizona copper mine project, there��s also separate bipartisan legislation 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.

��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. (Read about University of Kentucky student Lucas Bertucci who has researched recycling batteries, solar panels and other electronic waste at the Center for Applied Energy Research.)

��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.��?

During extreme heat, stay out of the sun and in air conditioning when possible.?(Photo by Tim Boyle/Getty Images)

This story was updated with comments from MISO and SPP on May 19.

As much as two thirds of North America could face shortages of electricity this summer in the event of severe and protracted heat, according to the regulator in charge of setting and enforcing standards for the electric grid.?

��Increased, rapid deployment of wind, solar and batteries have made a positive impact,�� said Mark Olson, manager of reliability assessments for the North American Electric Reliability Corporation (NERC), in a news release. ��However, generator retirements continue to increase the risks associated with extreme summer temperatures, which factors into potential supply shortages in the western two-thirds of North America if summer temperatures spike.��?

NERC��s 2023 Summer Reliability Assessment says the amount of electric generation capacity across the country is adequate for normal summer weather, though spiking temperatures, coupled with potential high outage rates from fossil plants and low output from renewables, could force emergency actions like interrupting power service. NERC says the areas that face elevated risk are the U.S. West, the Midwestern states that are part of SPP and MISO �� a pair of regional transmission organizations that each coordinate the flow of electricity for a huge swathe of the central U.S. �� Texas, New England and parts of the upper South.?

��Weather officials are expecting above normal temperatures for much of the United States,�� the report says. ��In addition, drought conditions continue across much of the western half of North America, resulting in unique challenges to area electricity supplies and potential impacts on demand. �� Above average seasonal temperatures can contribute to high peak demand as well as an increase in forced outages for generation and some (bulk power system) equipment.��

Derek Wingfield, a spokesman for SPP, which coordinates electric flow for customers in 14 states, said the regional organization ��anticipates that we��ll have enough generating capacity to serve load across our region through the summer.�� Even if electric demand exceeds historical averages by as much as 5%, there��s still a high probability there will be enough power supply, Wingfield said.

��We hope people across our region will rest easy knowing that the summer season looks generally favorable in terms of electric reliability, but we encourage them to prepare for the unexpected and ensure they can receive notices from their local utilities in case of the threat of outages,�� he added.

In a news release on May 17, Clair Moeller, MISO��s president and chief operating officer, said managing the system, which covers all or part of 15 states over an area that runs from the Canadian border to the Gulf of Mexico, is getting tougher because of changes to the power generation fleet.

��Actions taken by market participants this year, such as delaying resource retirements and making additional, existing capacity available via imports may not be repeatable in the future, and this year we are still susceptible to supply shortages in extreme situations,�� Moeller said.

The NERC reportsays wind output in MISO and SPP will be a ��key factor�� in whether there will be enough electricity to maintain reliability. NERC also cites natural gas and coal supply risks and the EPA��s new ��Good Neighbor Plan�� rule, which is intended to cut smog-forming pollution from power plants and other industrial facilities in 23 states but will likely limit hours of operation for coal plants.?

The report says state regulators, grid operators and power plants will have to be ��vigilant for emissions rule constraints that affect generator dispatchability and the potential need for emission allowance trades or waivers to meet high demand or low resource conditions.��

Michael Goggin, a vice president at Grid Strategies, a consulting firm, said wind and solar have historically performed well during peak electric demand periods and generally meet or exceed the output grid operators expect them to deliver.

��The primary cause of reliability risks during both hot and cold extreme weather has been the underperformance of fossil, and particularly gas, generators,�� Goggin said, citing gas plants that failed to perform during heat waves in 2020 and 2022 in California and other parts of the west.?

Advanced Energy United, a trade group representing renewable energy businesses, said the report underscored the need to update the electric grid and increase the ability to move electricity around the country by building more transmission lines.

��With no end in sight to grueling summer heat waves induced by climate change, states that do nothing to shore up the energy grid will continue to risk blackouts and skyrocketing electricity costs,�� said Leah Rubin Shen, AEU��s managing director. ��Modernizing our 100-year-old electric grid with new transmission lines and new grid-improving technology will make it easier for all kinds of clean energy, like large-scale projects as well as household and neighborhood resources, to connect to the grid and make it more reliable and affordable.��

The group also called for a full-fledged regional transmission organization for the West, which currently has a power trading mechanism called the Energy Imbalance Market but has seen some states exploring efforts to better connect the region. Both Colorado and Nevada, for example, have passed legislation requiring their states to join regional transmission organizations and California is exploring further regionalization.?

��Right now, there are 38 entities managing 38 separate energy territories in the West,�� said Mona Tierney-Lloyd, Head of State Public Policy for Enel North America, an energy service company and renewable power developer. ��Coordinating across all of them can be very challenging when supplies are tight and demand is soaring �� and that’s what contributes to power outages. A regional transmission organization would make it much easier to coordinate and keep the lights on everywhere in the West. It is a much more efficient and reliable way of sharing scarce resources.��

��I hope we get through the summer��

At the Federal Energy Regulatory Commission meeting Thursday, commissioners got a presentation from their own staff as well as NERC on the reliability outlook for summer.

Two commissioners, Chairman Willie Phillips and Commissioner Allison Clements, saw positive trends compared to last year, including easing drought conditions that should improve hydropower in the West. Clements noted that the California Independent System Operator, which runs the electric grid for most of California, released its own outlook for summer that showed improvement in availability of electric generation and an additional 4,000 megawatts of storage capacity coming online. California��s grid was pushed to the brink by a late summer heat wave last year, but the addition of battery storage, regional cooperation, efforts to cut demand and direct appeals to consumers, among other measures, staved off disaster.?

��We have the tools in the toolbox to get at these problems,�� Clements said, citing improving the interconnection process for new generation resources, transmission planning upgrades, grid technologies and programs to reduce electric demand.

However, Commissioner Mark Christie wasn��t as sanguine.?

��We��re losing dispatchable generation at a pace that��s unsustainable. And it��s going to have negative consequences in the future,�� Christie said.??

��The long term trends are still threatening. That��s what I took from the NERC report. ��? I hope it is good news, I hope we get through the summer. But I think in the long term we��ve got some major, major threats facing reliability of the grid.��

Cutline: A coal-fired power plant in Romeoville, Illinois. The Environmental Protection Agency is proposing a new rule to regulate fossil fuel power plant carbon dioxide. (Photo by Scott Olson/Getty Images)

The Obama administration��s 2015 Clean Power Plan �� intended to cut carbon emissions from power plants �� was struck down by the U.S. Supreme Court.

The Trump administration��s much-criticized replacement, the Affordable Clean Energy rule, derided as a ��tortured series of misreadings�� of the U.S. Clean Air Act, was also tossed by a federal court.

But the Biden administration��s Environmental Protection Agency is back at bat with a new proposed rule to regulate fossil fuel power plant carbon dioxide, which is responsible for about a quarter of U.S. greenhouse gas emissions.

EPA says its new rule, released Thursday, is based on ��cost-effective and available control technologies,�� and will avoid as much as 617 million metric tons of CO2 emissions through 2042, the equivalent of reducing the annual emissions of 137 million passenger vehicles. The agency claims it will also prevent hundreds of premature deaths and hospital visits, thousands of asthma attacks and relieve the burden of environmental justice communities disproportionately afflicted by power plant pollution. In 2022 alone, the electric power sector accounted for about 1.5 billion metric tons of CO2 emissions.

The rule strengthens standards for new fossil-fuel plants, (mostly natural gas) and establishes emissions guidelines for states to follow in limiting carbon pollution from existing fossil fuel plants, which can be coal, gas or oil-fired.

��EPA��s proposal relies on proven, readily available technologies to limit carbon pollution and seizes the momentum already underway in the power sector to move toward a cleaner future,�� EPA Administrator Michael Regan said in a statement. ��Alongside historic investment taking place across America in clean energy manufacturing and deployment, these proposals will help deliver tremendous benefits to the American people �� cutting climate pollution and other harmful pollutants, protecting people��s health and driving American innovation.��

However, some power plant operators warn it could imperil electric reliability by accelerating power plant closures before enough cleaner resources are ready. And some environmentalists say technologies the rule cites �� carbon capture and storage and co-firing natural gas plants with clean burning hydrogen �� are far from proven at the scale that will be required.

Others say the rule could be improved by setting lower thresholds for applicability (as proposed it only applies to the largest and most frequently used gas plants.

Reliability and sustainability

The Electric Power Supply Association, a trade group that represents competitive power generators, warned that the rule could intensify potential future electric reliability challenges. Indeed, some regulators fear that the increasing pace of power plant retirements, combined with increasing electrification in transportation and other sectors and the difficulty of getting new, primarily renewable resources sited and connected to the grid, could create shortfalls in electric supply in the near future.

��Once again, aspirational policy is getting ahead of operational reality,�� EPSA President and CEO Todd Snitchler said in a statement. ��If finalized, these aggressive rules will undoubtedly drive up energy costs and lead to a substantial number of power plant retirements when experts have warned that we are already facing a reliability crisis due to accelerated retirements of dispatchable resources.��

The Edison Electric Institute, which represents investor-owned electric utilities that provide electric service to more than 235 million people in all 50 states, was more measured.

��Just as we do with any rulemaking, we will assess EPA��s proposed new regulations through the lens of whether they align with our priorities and support our ability to provide customers with the reliable clean energy they need at an affordable cost,�� Edison CEO Tom Kuhn said. Kuhn said carbon emissions from the power sector are as low as they were in 1984 despite electric use climbing 73% over the past four decades.

Priorities for electric companies in the final rule, expected to go into effect sometime next year, are for compliance deadlines to align with ��existing transition plans�� and ��recognition of the critical role existing and new natural gas generation plays,�� Kuhn said. The utility industry also wants ��a range of compliance flexibilities�� that include hydrogen and carbon capture and storage ��when they are commercially available at scale and cost.��

Several environmental and renewable energy industry groups celebrated the proposed rule.

��Power plants have been allowed to pump deadly carbon dioxide pollution into the air we breathe, threatening our communities and our future, with nearly no federal limits �C until now. Today��s proposal marks a significant step forward, and we��re pleased to see the Biden administration continue to address climate pollution in a serious way,�� said Ben Jealous, executive director of the Sierra Club.

The American Council on Renewable Energy called it ��an important step forward�� that comes as the threat posed by climate change becomes increasingly severe.

��It is clear that we need a regulatory framework for reducing carbon emissions to complement the helpful incentives in the Inflation Reduction Act if we are to achieve our climate targets,�� ACORE said.

��Putting forward their very best foot��

But can the rule survive another expected legal challenge?

Patrick Morrisey, the Republican attorney general of West Virginia who sued the EPA over the Obama-era Clean Power Plan, was quick to challenge the legitimacy of the new proposed rule.

��Based upon what we currently know about this proposal, it is not going to be upheld, and it just seems designed to scare more coal-fired power plants into retirement �� the goal of the Biden administration,�� Morrisey said in a statement Thursday. ��That tactic is unacceptable, and this rule appears to utterly fly in the face of the rule of law. The U.S. Supreme Court has placed significant limits on what the EPA can do �� we plan on ensuring that those limits are upheld, and we expect that we would once again prevail in court against this out-of-control agency.��

Julie McNamara, a deputy policy director at the Union of Concerned Scientists, said the legal issue has never been whether EPA has the authority to regulate carbon emissions but rather how that power is exercised. With the Clean Power Plan, the Supreme Court ruled the agency overreached, finding that it could not direct power plants to shift from fossil fuels to cleaner sources like wind and solar. Rather, it held the EPA could set emissions limits by determining the ��best system of emission reduction�� for existing sources at that facility, not force a change in generation source.

The new rule, she said, is more narrowly focused and tailored to the confines of the Supreme Court ruling.

��EPA has been incredibly thoughtful about this and are putting forward their very best foot to try to have a defensible rule,�� McNamara said. ��It��s a certainty these will go to the courts but it’s not a certainty that the courts will take it up.��

McNamara said that when the rule becomes finalized next year, it will be up to states to submit plans for compliance.

��It��s up to the states to say what is the most cost effective and forward looking approach to achieving these emissions reductions,�� she said.

Brian Murray, director of Duke University��s Nicholas Institute for Energy, Environment and Sustainability, said the rule builds on the array of clean energy incentives in last year��s Inflation Reduction Act.

��Putting a regulation on top of that means that the regulation itself is more economically achievable because of the subsidies,�� he said. ��The IRA is doing a lot of the heavy lifting for the reductions that are being sought by the administration.��

Joining with many states��, utilities�� and corporations�� own decarbonization goals, the rule adds a lot of momentum that might be tough to derail.

��You take all these together and everything is walking in the same direction,�� Murray said.

Carbon capture questions

Wenonah Hauter, executive director of Food & Water Watch, a nonprofit focused on environmental activism, called carbon capture ��a fossil fuel industry propaganda scheme�� that��s wasted billions of dollars and produced ��a series of spectacular failures.��

An October report from the Congressional Research Service said the U.S. Department of Energy has funded carbon capture research and development since ��at least 1997�� and that Congress has provided $9.2 billion since 2010 in annual appropriations for the DOEs�� Fossil Energy and Carbon Management Research, Development, Demonstration, and Deployment program.

The 2021 bipartisan infrastructure law included billions more for carbon capture facilities. Most existing carbon capture projects use the CO2 to enhance oil production in aging oil wells. The first and only U.S. power plant capturing carbon in large quantities was the Petra Nova project in Texas, though carbon capture was suspended in 2020, the report says.

��There is broad agreement that costs for constructing and operating (carbon capture and storage) would need to decrease before the technologies could be widely deployed. In the view of many proponents, greater CCS deployment is fundamental to reduce CO2 emissions,�� the report says. ��In contrast, some stakeholders do not support CCS as a mitigation option, citing concerns with continued fossil fuel combustion and the uncertainties of long-term underground CO2 storage.��

Andres Restrepo, a senior attorney with the Sierra Club, said the expansion of fossil fuel plants is ��incompatible with a livable future�� but noted that because of the Supreme Court��s ruling in the West Virginia v. EPA case, blending natural gas with hydrogen for power production and carbon capture ��form the basis for the strongest possible standards that the EPA can legally propose.��

The EPA��s own projections show that many more power plants are likely to retire rather than install carbon capture, he added.

��We also believe the standards are likely to help deter some of the expected build-out of new gas plants in the first place,�� Restrepo said. ��Therefore, these standards are much more likely to reduce climate emissions and improve public health than simply maintaining the status quo.”

One analysis of Southern Company, which owns the dominant utilities in Alabama and Georgia, found that it could have saved its customers $1.5 billion between 2015 and 2020 if it was in a wholesale market that required it to operate its coal plants from lowest cost to highest and imported cheaper electricity from elsewhere. Georgia Power is aiming to shut down its coal-fired power plants by 2028, except for Plant Bowen, which won��t close until 2035. (Photo by Ross Williams/Georgia Recorder)

A recent report prepared for the South Carolina state legislature determined that a range of electric market and transmission reforms �� including creating a new independent organization to run the electric grid or joining an existing one �� would bring? ��substantial benefits�� for customers, potentially as much as $362 million a year.?

The report by the Brattle Group, a Boston consulting firm, stems from the V.C. Summer nuclear plant fiasco that saddled the state��s ratepayers with billions in cost overruns for reactors that were never built.

And it��s the latest chapter in a long-running saga over a southern-fried electric grid anomaly.

The majority of U.S. electric customers live in areas managed by regional transmission organizations, which coordinate the flow of electricity, ensure reliability, plan transmission projects and run electric markets. In large parts of the West, consumers benefit from a separate market that helps move low cost electricity around and manages congestion on transmission lines. But most of the Southeast remains dominated by a handful of large utility companies that have successfully thrown back attempts to bring them under any kind of similar arrangement.?

��Basically, utilities have a lot of political power in the Southeast,�� said Rob Gramlich, president of Grid Strategies, a consulting firm focused on integrating clean power into the grid. ��It��s not like utilities didn’t have power in the Northeast or Midwest or California, but there was a strong movement 20 years ago to get to a more efficient type of market and utilities in the Southeast resisted any such efforts in their region.��

��Unfettered control��?

The South Carolina report, which got a lukewarm reception from lawmakers there, per the Charlotte Business Journal, comes as big employers like Google looking to meet corporate sustainability goals express frustration with the lack of market options in the Southeast and environmental groups, eager to speed up the renewable transition, push for a true wholesale market in the region.?

��Utilities in the Southeast have pretty much unfettered control over which generation they use and they��re not subject to any meaningful competition,�� said Nick Guidi, an attorney with the Southern Environmental Law Center. Guidi and other market proponents say bringing the Southeast into a regional transmission organization or other type of competitive market construct would bring down wholesale electric costs for consumers, improve reliability in the face of increasing severe weather and help get more cheap renewable power onto the grid.?

However, utility companies and other opponents argue that regional transmission organizations and regional power markets add undue layers of complexity, reduce state oversight and take away control over utilities�� own operations. They also say state energy policy goals would take a backseat.

��We do not believe changing our integrated utility model is best for our customers and communities in North Carolina and South Carolina,�� said Jeff Brooks, a spokesman for Duke Energy, which is headquartered in North Carolina and operates in both RTO and non-RTO areas.?

��The report overstates savings and doesn��t account for administrative and joining costs. Participation in an RTO would keep our coal plants running much longer than currently planned and would transfer critical aspects of our operations into the hands of a federally-run body which is not accountable to the citizens, regulators and elected officials of the states we serve.��

Southern Company, which operates the dominant utilities in Georgia and Alabama as well as the smaller Mississippi Power, did not respond to a list of questions about a potential Southeastern wholesale electric market or regional transmission organization. But CEO Thomas Fanning told The New York Times last year that ��we absolutely are superior in every regard to those markets over time.��

The South Carolina report estimates that the biggest benefits for the state��s electric customers would come from integrating with PJM, though that would also require its neighbor North Carolina to do so. A bill filed in the North Carolina General Assembly would put $500,000 forward for a study similar to the one South Carolina just performed, citing the rolling blackouts from Elliott as a reason. A 2019 North Carolina white paper, also by Brattle, commissioned by consumer advocacy and clean energy business groups, has estimated that an RTO-operated market could yield hundreds of millions of dollars a year in benefits for electric customers there.?

��Still better for consumers��

Generally, in a wholesale electric market, power plants compete to provide electricity to the grid. The cheapest generators run more, replacing output from more expensive plants and creating savings for consumers. That also allows utilities to buy power from the market when it��s less expensive than producing it themselves. Regional transmission organizations plan electric transmission projects on a regional basis, which can avoid redundant projects by neighboring utilities, as the Brattle group noted in the 2019 paper.?

Gramlich said regional transmission organizations and the power markets they run also enable large, seamless transfers of power to improve efficiency during regular operations and keep the lights on when the grid is under stress, such as during Winter Storm Elliott, when Duke Energy was forced to implement rolling blackouts in the Carolinas. The Tennessee Valley Authority, which also operates outside of an RTO, did the same during the storm.?

Though PJM, which runs the electric grid for neighboring Virginia, along with a small portion of North Carolina, and parts or all of 11 other states and the District of Columbia, also saw power plants hamstrung by the frigid weather, it avoided blackouts.?

��It��s not in the utilities�� nature to give up control of some of the operations and planning,�� Gramlich said. ��Even with some of the warts on RTOs, it’s still better for consumers than just having a vertically integrated franchise monopoly that does everything.��

There are indeed tradeoffs involved in being part of a regional electric grid, said Kent Chandler, chairman of the Public Service Commission in Kentucky, which is part of two different RTOs �� PJM and the Midcontinent Independent System Operator (MISO) �� and also includes territory that isn��t in one.?

��Outside of Texas we��re really the most unique state in terms of markets,�� he said.??

Being part of an RTO, he added, does mean giving up a ��certain amount of control,�� though he noted that varies considerably depending on how the organizations are set up.?

��States are really on the outside looking in in PJM,�� Chandler said, though he added that in other RTOs, notably MISO and Southwest Power Pool, ��that is not the case.��?

And while he��s not advocating for or against a new market or RTO in the Southeast, he thinks the pros outweigh the cons for Kentucky.?

��Whatever shortcomings MISO or PJM have in terms of governance or transmission planning or whatever they are �� they��re still better than not having the RTO,�� he said. ��I think the increase in reliability and the reduction in cost for market membership is better than not having them.��

Nevertheless, RTOs and power markets also add what can be immense levels of complexity and other headaches, like the long interconnection queues �� essentially wait lists to connect to the grid that are holding up mostly new wind and solar projects �� that have bedeviled MISO and PJM.

��RTOs are a 1990s idea that has yet to adapt to the clean energy era. The Brattle Study ignored the problems RTOs have encountered since being first rolled out by FERC 25 years ago,�� the South Carolina AARP wrote in comments on the Brattle report. ��RTOs are cumbersome, complicated, and expensive entities to deal with.��

Why it matters

The electric grid, utility regulation and electric markets are complicated. But everyone pays an electric bill, and the regimes that govern the power system all make a difference in the cost and the source of the electricity that gets delivered to homes and businesses.?

The Western Energy Imbalance Market says it��s delivered $3.4 billion in ��gross benefits�� (defined as cost savings, integration of renewables and ��improved operational efficiencies�� such as the reduction in the need for reserve power ) since 2014. Southwest Power Pool says its markets provide more than $744 million a year in net savings for participants. Entergy, a company that operates utilities in Arkansas, Louisiana, Mississippi and Texas and joined MISO amid prodding from the U.S. Department of Justice��s Antitrust Division, said Louisiana customers saved $120 million in the first year of membership. PJM, the nation��s largest RTO serving some 65 million people, says its regional grid and market operations create anywhere from $3.2 billion to $4 billion in savings a year.

That��s big money, proponents of markets and RTOs say, and it could deliver real value for electric customers in the Southeast, who have some of the highest energy burdens (the proportion of household income required to pay energy bills) and bills in the nation.?

One analysis by RMI, a nonprofit focused on decarbonization, posited that Southern Company, which has been under fire for climbing bills in Alabama and Georgia, says the utility giant could have saved its customers $1.5 billion between 2015 and 2020 if it was in a wholesale market that required ��economic dispatch�� of its coal plants, meaning operating them in order from lowest cost to highest and importing cheaper electricity from elsewhere.?

��Millions of Southerners struggle to pay their monthly electric and gas bills. More customers are cost-burdened in the South than in any other part of the country, and more than a third of the region��s population has trouble paying their energy bills,�� the Southeast Energy Efficiency Alliance, an Atlanta nonprofit, wrote in a report released last month. ��Low-income households and people of color pay a higher financial and health price to power their homes than everyone else.��

Eric Gimon, a senior fellow at Energy Innovation, a nonpartisan energy and climate policy think tank, worked on a 2020 report that found a ��fully competitive�� Southeast wholesale electric market would generate $384 billion in regional savings, create 285,000 clean energy jobs and cut carbon emissions from the electric sector by 37 percent by 2040.?

He said their study found that the biggest savings came when power plants were put under competitive pressure, adding that electric utilities or their parent companies often have an equity stake in the gas pipelines that feed their power plants and aren��t incentivized to change the generation mix for lower cost options like solar and battery storage.?

��People in the Southeast are paying a lot more for energy than they need to in order to keep the status quo that profits the shareholders and investors in these large utilities,�� Gimon said.?

Remaining to be SEEM

Last year, a new market of sorts did launch for the Southeast. Called the Southeast Energy Exchange Market and founded by a group of regional utilities, the platform is intended to facilitate voluntary power trades between utilities.

��The SEEM platform will help save customers money and better integrate renewable resources, while ensuring all customers across the region realize the promise of renewables,�� said Noel Black, Southern Company’s senior vice president of governmental affairs, when the market launched.?

But critics, including Guidi and Gramlich, say as currently constructed the Southeast Energy Exchange Market is woefully inadequate. Several environmental groups and other organizations are suing the Federal Energy Regulatory Commission over the market, arguing it flies in the face of allowing open access to transmission.?

Guidi said the market ��completely failed�� during Winter Storm Elliott, when power exchanges were most needed, and has seen its trade volume decrease since it launched in November.?

��It��s only been around for four months but you would hope to see some upward trend in trade volume,�� Guidi said.?

The market also lacks crucial aspects: independent governance, transparency and competition, among other shortcomings, they said. A Google attorney called the market a ��nothing burger�� at an energy conference in Atlanta last year.

��SEEM could be built into something real,�� Gramlich said. ��As it stands it��s just kind of nickels and dimes. It��s not really of any significance.��

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. (Robert Zullo/ States Newsroom)

IDAHO FALLS, Idaho �� 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 �� including the Kentucky Office of Energy Policy �� have joined a new collaborative organized by the National Association of Regulatory Utility Officials 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.?

Kentucky launching nuclear energy working group

Legislation signed by Gov. Andy Beshear last month creates a 23-member Nuclear Energy Development Working Group to identify barriers to deploying nuclear power generation in Kentucky and to recommend how a permanent nuclear energy commission could overcome those barriers.

Sponsored by Sen. Danny Carroll, R-Benton, the resolution creating the nuclear working group says new nuclear technologies, including small modular reactors, make nuclear generation less expensive and more reliable and that nuclear power “could be a part of the Commonwealth’s all-of-the-above energy approach.”

Kentucky has no nuclear power generation. In 2017 the state lifted a moratorium on construction of new nuclear facilities. The legislature’s resolution says Kentucky “has fallen behind neighboring states, including Illinois, Tennessee, and Virginia, in the development and deployment of nuclear power generation resources.”

The working group is to submit a report by Dec. 1.

��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, 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.

But there��s also some doubt about whether an industry that��s struggled so much can rise to the challenge of meeting intense design, licensing and cost challenges.??

��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.

Despite a rash of shooting attacks against electric substations last year, regulators are not recommending new physical security requirements. (Photo by Justin Sullivan/Getty Images)

The organization in charge of setting and enforcing reliability standards for the U.S. electric grid isn��t recommending new physical security requirements for thousands of electric substations following a rash of shooting attacks that have knocked out power in parts of several states.

Jim Robb, CEO of the North American Electric Reliability Corporation, told the Federal Energy Regulatory Commission Thursday that cost was a major concern.

��We��re not recommending a common minimum level of physical security protections at this time,�� Robb said, adding that NERC was aware of the vulnerability of substations and other electric transmission infrastructure, particularly in remote areas. ��Physical security hardening of substations can be extraordinarily expensive. For example, something as simple as a camera installation could easily run into hundreds of thousands of dollars per substation.��

He added that ��it��s important that the risk abated is commensurate with the capital required.��

Following gunfire attacks on substations last year in Moore County, N.C., Ohio, the Pacific Northwest and elsewhere, the commission tasked NERC with reviewing existing rules, which only currently apply to electric infrastructure, that, if knocked out, would pose a hazard to the broader bulk power system.?

The current regulation, known as the CIP-014 Reliability Standard, which came into being in 2014 after a sniper attack on a California substation, ��was conceived to identify those critical assets that if rendered inoperable could result in what we call the ��evil three,�� �� Robb said. Those are instability, uncontrolled separation and cascading outages, the successive loss of elements on the electric system that results in widespread service interruption.??

Many substations, like the ones targeted in Moore County, North Carolina, don��t meet that threshold, but damaging them can still result in a loss of power for thousands.??

��These recent high-profile events are deeply concerning for their sophistication and effectiveness even while noting that the customer impacts were localized,�� Robb said, referencing the planned neo-Nazi attack the FBI says it foiled in Maryland earlier this year. ��These are sobering times indeed for the electric grid.��

However, NERC also didn��t recommend extending the applicability criteria under the existing regulations to other, less crucial substations, finding that the rule ��appropriately focuses limited industry resources on risks to the reliable operation of the (bulk power system) associated with physical security incidents at the most critical facilities.��?

The organization said it would hold a technical conference with FERC to determine whether any additional substations should be included in the criteria.

��NERC recommends 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,�� the group��s report says. The review did find that the language in the requirements should be ��refined�� so that owners of substations that do meet the threshold for the security standards conduct effective risk assessments.

��In certain instances, registered entities failed to provide sufficient technical studies or justification for study decisions resulting in noncompliance. NERC finds that the inconsistent approach to performing the risk assessment is largely due to a lack of specificity in the requirement language,�� the report says.?

FERC Chairman Willie Phillips called the report ��a good start�� and said the commission staff would work on putting together the technical conference.?

��There is no greater priority for me and for this commission than making sure that we protect the security of our electric grid,�� Phillips said.

A NERC spokeswoman said that while the commission cannot create a security standard or tell NERC how to write one, ��they do have the authority to order us to establish a new standard or modify an existing one.��??

Robb added that NERC sets baseline standards and that utilities, working with their regulators, can ��invest in additional protections.��?

A gas flare from a petroleum refinery in Norco, Louisiana. (Photo by Drew Angerer/Getty Images)

More than a dozen environmental groups are suing the federal Environmental Protection Agency over its failure to set water pollution limits for some industrial contaminants as well as its reluctance to update decades-old standards for others, arguing that the agency��s inaction amounts to a ��free pass to pollute�� for hundreds of chemical and fertilizer plants, oil refineries, plastics manufacturers and other industrial facilities.?

��It��s completely unacceptable that EPA has, for decades, ignored the law and failed to require modern wastewater pollution controls for oil refineries and petrochemical and plastics plants,�� said Jen Duggan, deputy director of the Environmental Integrity Project, a nonprofit focused on environmental law enforcement that coordinated the lawsuit by 13 environmental groups.? ��We expect EPA to do its job and protect America��s waterways and public health as required by the Clean Water Act.��

The EPA did not immediately comment on the lawsuit.?

The lawsuit, filed Tuesday, centers on the Clean Water Act, the landmark Nixon-era legislation that regulated the discharge of pollutants into waters of the United States. In a letter to the agency advising that the lawsuit was being filed, the Environmental Integrity Project noted that the act requires EPA to establish pollution limits based on the best available treatment methods and then review the limits yearly and every five years ��to keep pace with advances in technologies to reduce �� and ultimately eliminate �� water pollution from industrial sources.��

However, for 40 of the 59 industries subject to the pollution limits, the standards were ��last updated 30 or more years ago, and 17 of those date back to the 1970s,�� the EIP says.

��These point-source categories are large sources of water pollution, dumping billions of gallons of wastewater into our rivers, streams and lakes each year,�� the group said, noting that EPA standards in many cases ��do not limit discharges of nutrient pollution or toxics like benzene, mercury, polycyclic aromatic hydrocarbons (PAHs), selenium, per- and polyfluoroalkyl substances (PFAS), and heavy metals.�� The suit alleges that the EPA��s decision not to update the regulations is ��arbitrary, capricious, an abuse of discretion or otherwise not in accordance with law�� under the federal Administrative Procedure Act.

About half of all the river and stream miles and lake acreage in the U.S. fail to meet water quality standards because of pollution, ��which means half the country��s assessed waterways do not support intended uses like aquatic life and drinking water, the EIP says.?

Duggan said if the EPA required, for example, the modern treatment controls that are standard for municipal sewage plants that discharge into the Chesapeake Bay �� like denitrification, which removes nitrates and nitrite compounds that can lead to large algal blooms �� water pollution could be cut significantly.

Eighty-one oil refineries across the U.S. discharged nearly 16 million pounds of nitrogen pollution into streams, rivers, lakes and bays in 2021, the group says. Carbon and mechanical filtration technologies could also be used to remove heavy metals like lead, arsenic, selenium and PFAs, the ��forever chemicals�� that have been linked to potential increased cancer risk and a host of other health problems.?

��EPA simply cannot fulfill its mandate of setting increasingly protective, technology-based pollution limits for these and other industrial categories if EPA does not regularly review whether existing limits reflect best available technology and other recent technology,�� the EIP wrote in its letter.?

Tightening restrictions would affect about 1,185 plants across seven industrial categories, the EIP said. Some of the biggest polluters are oil refineries and ammonia nitrogen fertilizer plants, many of them concentrated along the Gulf Coast.?

But during a news conference announcing the lawsuit, representatives from environmental groups said the problem stretches from the slew of chemical and refineries along the banks of the Mississippi River (dubbed ��Cancer Alley��) in southern Louisiana to Newark, N.J.��s ��chemical corridor,�� the shores of Lake Michigan and to the San Francisco Bay, with many others in between. They noted that pollution tends to fall heaviest on poor and minority communities.?

��For decades the EPA has let these dirty industries pollute our rivers and bays instead of making them keep pace with advances in technologies that tackle water pollution, as the Clean Water Act demands,�� said Hannah Connor, the environmental health deputy director at the Center for Biological Diversity, a nonprofit focused on protecting endangered species. ��Forcing people and wildlife like endangered Atlantic sturgeon to bear the weight of toxic water pollution while industries rake in record profits isn��t just morally wrong, it��s also legally indefensible. EPA needs to bring pollution standards into the 21st century.��

Service technicians work to install the foundation for a transmission tower at the CenterPoint Energy power plant on June 10, 2022 in Houston, Texas. (Photo by Brandon Bell/Getty Images)

The U.S. Department of Energy issued a draft report in February that found a ��pressing need�� for new electric transmission infrastructure across the country to improve reliability, connect a rapidly growing number of solar, wind and battery storage projects, supply increasing electric demand and alleviate scattered pockets of consistently high prices across the country.

To meet the future envisioned by the federal infrastructure act and the Inflation Reduction Act, which both contain major provisions to boost clean energy, the country needs to increase its current transmission system by an eye-popping 57% by 2035, the report says. Princeton University��s Net-Zero America study estimates expanding transmission capacity by 60% by 2030 will cost $330 billion and tripling it by 2050 will cost $2.2 trillion.

But in some states, bills that have been pushed by utilities to give them exclusive or preferential treatment for building regional transmission lines, called ��right-of-first-refusal�� laws, mean customers might pay more than they should for all those wires and towers, critics say.?

��What��s important to note is that the clean energy transition is going to require a significant amount of new transmission. Because of that, that��s why you have these protectionist battles going on across the country,�� said Sharon Senger, senior vice president of transmission policy at LS Power, a company that owns about 680 miles of transmission lines and has been awarded more than $4 billion worth of competitively bid transmission projects.?

��The incumbent utilities are trying to obtain a monopoly for the clean energy transition.��

The Edison Electric Institute, which represents investor-owned electric utilities and has pushed the Federal Energy Regulatory Commission to grant utilities rights of first refusal for regional transmission lines, did not respond to a request for comment on the rationale for right-of-first refusal laws. However, in statehouses across the country, proponents have argued that such laws actually benefit consumers because they remove the incentive to offer unrealistic lowball bids to win solicitations, avoid delays dealing with procurement, preserve state regulatory oversight and result in streamlined, more efficient projects because local utilities know their communities better.?

But they also represent a potential windfall for utilities.

��The more capital they spend, the more profit they make under government-guaranteed rates of return,�� said Josiah Neeley, a senior fellow at the R Street Institute, a right-leaning free market think tank, in testimony on a failed right-of-first refusal bill in Wisconsin last year. ��Historically, the absence of transmission competition has resulted in a severe lack of economic discipline �� leading to cost overruns, with captive consumers footing the bill.��

��Crony capitalism��

Last month, after a lawsuit by LS Power and another company, the Iowa Supreme Court halted legislation from 2020 that gave a right of first refusal for transmission projects to utilities operating in Iowa. The court, which ruled based on the manner in which the bill was passed, not its substance, nevertheless called it ��quintessentially crony capitalism�� and ��rent-seeking, protectionist legislation�� that will ��impose higher costs on Iowans.��?

That ruling comes as the U.S. Supreme Court weighs whether to take up a case involving Texas�� even more extreme 2019 law, which says the ability to build, own and operate new transmission lines that connect directly to an existing utility facility ��may be granted only to the owner of that existing facility.�� The U.S. Court of Appeals for the 5th Circuit held in August that the Texas law may violate the Commerce Clause of the U.S. Constitution, reversing a lower court ruling that upheld the law. The 5th Circuit, calling the law a ��ban on new entrants in a market�� remanded the case to the district court to consider whether Texas regulators can show they have ��no other means to advance a legitimate local purpose.����?

Writing for the conservative Cato Institute, Vanderbilt University law professor Jim Rossi called right-of-first-refusal laws (ROFR) ��constitutionally suspect�� and noted that of more than $10 billion in transmission projects recently approved by the Midcontinent Independent System Operator, which operates the electric grid in all or part of 15 states, more than 90% will be built by incumbent utilities rather than competitively bid.?

��State transmission ROFR laws reflect bad policy choices that thwart reliability in competitive regional power supply markets and, at bottom, are harmful to customers,�� Rossi wrote. ��Transmission ROFRs pose a barrier to a coordinated approach to grid expansion, making it more difficult to promote reliability and new technological approaches that enable the lowest�\?cost power supply options for customers.��

According to the National Conference of State Legislatures, Indiana, Michigan, Minnesota, Montana, North Dakota, Oklahoma and South Dakota have laws on the books that grant utilities right-of-first-refusal privileges to build local or regional transmission lines. Mississippi passed similar legislation this year. Bills to add new ROFR rights or expand existing ones have been introduced in Missouri, Montana, Wisconsin, Oklahoma, Kansas and Indiana.?

��If you want to see more clean energy we need more transmission and you want to keep all the options on the table for who��s going to develop those projects,�� said Ari Peskoe, director of the Electricity Law Initiative at the Harvard Law School.?

Current right-of-first-refusal laws at the state level have their origins in reaction to a FERC order in 2011 that sought to promote more competition in regional electric transmission projects in part by removing federal rights of first refusal for certain transmission projects.?

��The agency reasoned that federal rights of first refusal might ��be leading to rates . . . that are unjust and unreasonable,�� in large part because ��it is not in the economic self-interest of incumbent[s] to permit new entrants to develop transmission facilities,�� even if those facilities ��would result in a more efficient or cost-effective solution,���� the 5th Circuit judges wrote in their opinion.?

Utilities, Peskoe said, ��saw it coming and went to their legislatures and said ��please protect us from this competition.����?

Just 3% of today��s projects are competitively bid, according to the Electricity Transmission Competition Coalition, which includes 70 companies and organizations from 48 states, including manufacturers, consumer advocates, transmission developers, retail electric customers and public power representatives.?

Transmission tension?

The legal battles over right-of-first refusal laws come as the Federal Energy Regulatory Commission grapples with a suite of issues surrounding transmission planning and construction, including whether to reinstate a federal right of first refusal for utilities, a move that is opposed by the U.S. Department of Justice and the Federal Trade Commission.?

��American consumers and businesses should not be denied the benefits of competition when paying for this significant transmission investment,�� the agencies said.?

FERC, which regulates interstate electric transmission, is also exploring the concept of an independent transmission monitor. That��s because some state regulators and consumer advocates say that as transmission spending by utilities is becoming an increasing portion of electric customers�� bills, projects are escaping rigorous oversight because of varying regulatory regimes, a lack of expertise at the state level and too little transparency. FERC also has a draft rule out that would alter how regional transmission projects are planned and costs allocated.

And what��s more, some critics argue, many utilities aren��t incentivized to build the types of interregional transmission projects that the Department of Energy reported have the best benefits for customers.?

The Texas case, they contend, is a textbook example of what��s wrong with the status quo.

Building power plants, Peskoe said, has always been the major source of profit for utilities. New transmission lines that might bring in cheaper power from elsewhere reduce the need for those pricey new facilities.

��You��re sort of cutting yourself off at the knees because you’re reducing the opportunity to build power plants in the future,�� he said. ��Bringing in energy from elsewhere may be good for the consumers but maybe bad for utility shareholders.��

��They ran to their state legislature��?

The Texas right-of-first-refusal law is being challenged by NextEra Energy Transmission, a subsidiary of utility giant NextEra Energy, which owns Florida Power & Light, the nation��s largest utility.?

NextEra had won a competitive bidding process in 2018 held by MISO to build, own and operate a 500-kilovolt line to be sited in a portion of east Texas covered by MISO but in Entergy Texas�� service area. The estimated cost at the time was $115 million. The next year, the Texas legislature passed the right of first refusal law, effectively allowing Entergy, which has three million electric customers in Arkansas, Louisiana, Mississippi and Texas, to take over construction of the line.?

��The Texas utilities lost a legitimate competitive bidding process so they ran to their state legislature and passed a right of first refusal,�� said Senger, the LS Power executive.?

Then, in 2020, Entergy issued a request for proposals for a 1,200-megawatt combined cycle gas power plant in the same ��load pocket�� (a term for a part of the electric grid where the transmission system doesn��t have enough capacity to meet demand and requires local power generation) that would have been served by the transmission line. Entergy later decided it would ��self build�� the project, which is expected to cost about $1.2 billion.

��If you don’t build transmission, you end up with load pockets. Entergy’s now using those load pockets to justify *billions* in gas unit installations instead of spending *millions* on transmission,�� tweeted Simon Mahan, executive director of the Southern Renewable Energy Association, a nonprofit trade association that unsuccessfully urged FERC to deny MISO��s request to terminate the transmission line project.?

SREA sees a disturbing trend, noting that a similar transmission project in Entergy��s Louisiana service territory, the Waterford-Churchill line, was also canceled after its cost-benefit analysis was ��eradicated by local bottom-up transmission projects as well as the $870 million Entergy-built St. Charles (gas power plant).��

SREA said Entergy ��appears to be using an anti-competitive strategy of capturing, delaying, and/or canceling transmission projects with local generation assets at significant cost to local ratepayers, while at the same time, not resolving underlying load pocket problems.��

Entergy rejects that argument.?

The Orange County, Texas, plant ��was needed to address a large and growing shortfall of generation for Entergy Texas,�� said company spokeswoman Kendra James, adding that growing electric demand and the retirement of older power plants from the 1970s were also factors.?

��The OCAPS plant will address issues that the Hartburg-Sabine Junction Project could not, even under the most favorable assumptions for that transmission line,��? James said. ��There is no reasonable argument that Hartburg-Sabine was a substitute for OCAPS.��?

Entergy, James added, has more than doubled its capital investment in transmission since 2014 to improve reliability, connect new customers and reduce congestion on its system.?

��To provide reliable and affordable electric service, public utilities such as Entergy must invest in electric generation, transmission, distribution, and other aspects of the utility��s business,�� she said. ��Every investment decision we make is based on what we think is in our customers�� best interests.��

Correction: This article has been updated to correct the cost of the St. Charles gas power plant.

The nation��s largest grid operator is warning that it might not have enough electric generation in the future to guarantee reliability.?

And it comes as the Federal Energy Regulatory Commission convenes a forum on the multibillion-dollar capacity market PJM operates to ensure there��s enough power to meet demand even during grid emergencies, such as during Winter Storm Elliott last year. PJM coordinates the flow of electricity from gas, coal, nuclear, wind, solar and other types of generation through power lines in all or part of 13 states and the District of Columbia, an area that includes 65 million people.?

��We believe the healthy reserve margins we enjoy now cannot be taken for granted into the future,�� PJM��s Board of Managers wrote in a letter in February. ��Energy policies and market forces have, and could further expedite, the retirement of existing generation resources faster than the new resources are able to come online.��?

A changing electric generation mix, growing demand, severe weather, significant numbers of fossil fuel plant retirements and an interconnection backlog that has snagged thousands of megawatts of mostly renewable power projects, as well as complaints about how the capacity market is administered, are all putting pressure on PJM. The capacity market in particular has long been a punching bag for ratepayer watch dogs, renewable power developers, traditional power generators and other market actors since the current version came into existence in 2007.

��I think FERC is to some degree questioning ��Do we need step back and take a broader look at how we do resource adequacy?���� said Tom Rutigliano, a senior advocate at the Natural Resources Defense Council��s Sustainable FERC Project who advocates fair treatment for renewable resources by grid operators and at FERC. Resource adequacy is simply being able to meet customers�� demand for energy at all hours.?

��The capacity market just seems to be always breaking,�� Rutigliano said.

FERC itself said in a statement that the ��continuing disputes and frequent complaints about how PJM operates its capacity markets from an array of stakeholders throughout the region merit a general review outside the constraints of a particular proceeding.��

Most recently, FERC approved PJM��s request for capacity market rules changes that, if left to stand, would have seen bills for some customers on the Delmarva Peninsula (an area that includes parts of Delaware, Maryland and Virginia) spike by $24 a month for an average customer.?

PJM called it a ��unique set of circumstances�� triggered by a large number of planned power plants not participating in the auction for the 2024/2025 year, ��resulting in a supply and demand condition that did not reflect underlying fundamentals�� and driving up the capacity cost for customers. Power suppliers howled at the changes, vowing to challenge the ruling. One commissioner, James Danly, disagreed with approving PJM��s request, saying it would undermine confidence in FERC-regulated markets and calling it a ��misguided attempt to protect consumers.��

But Commissioner Mark Christie, a former Virginia utility regulator who supported PJM��s requested changes, said ��the auction results are so blatantly unjust and unreasonable that voting to allow those results to stand is unacceptable to me.�� And he said FERC needs to take more action.??

��The elephant in the room must be addressed: whether PJM��s capacity market construct can still ensure sufficient power supplies to deliver reliability at just and reasonable rates,�� Christie wrote.

��What we��re paying for is not what we��re getting��

PJM��s capacity market, called the ��Reliability Pricing Model,�� is the largest of its kind in the United States, said Steve Lieberman, vice president of transmission and regulatory affairs at American Municipal Power, a nonprofit formed to represent municipally-owned electric systems.?

It was set up to help generators ��solve for the missing money,�� Lieberman said, meaning there was concern that there were inadequate incentives for power generators to provide enough electricity to meet demand peaks, such as sweltering summers or frigid winters. In return for providing that money, PJM��s electric customers were supposedly buying certainty that there was adequate electric generation capacity to keep the lights on during emergencies, such as the 2015 polar vortex.?

But Lieberman and others say customers aren��t getting their money��s worth.

��I think they��re paying too much for capacity that isn��t available when we need it,�� he said. ��I believe in markets. But I think what we��re paying for is not what we��re getting.��

This year��s auction, intended to secure generating capacity for a period beginning June 1, 2024 through May 31, 2025, procured more than 140,000 megawatts, the rough output equivalent of 140 large (1,000 megawatt) power plants at a total cost of $2.2 billion, which will be paid by electric ratepayers in the states over which PJMhas jurisdiction. But though that gives PJM a comfortable 20.4% reserve margin, it was the third auction in a row where the total capacity offered declined, a trend that could be a ��potential concern for long-term resource adequacy,�� PJM said.

The market is a ��pay-for-performance�� model that requires power plants classified as capacity resources to deliver on demand during emergencies.

PJM likens it to a mall that builds enough parking to accommodate peak shopping times, such as Black Friday. ��The spaces are there when needed, but they may not be used all year round,�� PJM says on its website.

The concept is simple, but the rules are incredibly complex, so much so that in 2017, Stefanie Brand, the longtime director of the New Jersey Division of ratepayer counsel said in testimony to a Congressional subcommittee that ��the system is so opaque and confusing and constantly changing that the average consumer will never make sense of it.��

Even when the market does work as intended, she added, ��favoring lower priced generation sources and bringing overall prices down, the unsuccessful bidders and generators faced with lower prices then seek changes and subsidies to undo those market results.��

��Promising to perform and not deliver is very profitable��

Aside from the complexity and the wrangling by generators looking to get a better return, the resources procured to keep the lights on can sometimes fail spectacularly when they are needed most.?

During Elliott, which hit a huge swathe of the United States over the Christmas weekend, PJM lost about 46,000 megawatts of generation, mostly natural gas and coal power plants, due to an array of failures, including equipment and fuel problems, triggered by the plummeting temperatures. PJM had gone into the winter confident it had plenty of power on hand (indeed, it has long been criticized for saddling customers with too much capacity). But during Elliott, it implored customers to conserve electricity. There were no rolling blackouts like in other regions, but it illustrated that PJM needs to do a better job of accrediting the resources it accepts into the capacity market, said Rutigliano, the NRDC expert.

��PJM��s capacity market has been very rich and over supplied. That��s allowed us to get away with a lot of slop in the market,�� he said.

He noted that the penalties generators incur for failing to perform, weighed against the handsome capacity payments, aren��t enough to encourage them to perform the pricey weatherization that would enable them to keep operating during severe weather like Elliott.

��Promising to perform and not deliver is very profitable in PJM��s capacity market,�� he said. In January, Rutigliano noted that PJM plants that failed to perform in December face penalties of about $100,000 per megawatt of power they didn��t deliver. ��That sounds like a lot until you realize that many of them have earned $450,000 or more per MW in reliability payments since the last time they were called on,�� he wrote.?

Rutigliano was encouraged by the PJM board letter, which acknowledged the necessity of improving accreditation to ��ensure that the reliability contribution of each resource is accurately determined and aligned with compensation.��??

��From a market point of view, the most important thing is valuing things for what they are actually worth,�� Rutigliano added.

Lieberman said PJM��s efforts to ensure generators that get capacity payments can operate when called upon �� a system of penalties and bonuses called capacity performance �� have largely been a failure, noting that the rules implemented after the 2015 polar vortex didn��t prevent a large chunk of the generating fleet from failing to deliver during Elliott in December.

He was wary of language in the board letter that says the board ��believes that it is appropriate to evaluate whether changes are needed to the capacity performance construct and to ensure that market sellers are able to reflect the risk of taking on a capacity obligation in their capacity market offers.��

��If the argument PJM is going to make is ��We need to throw more money at the problem,�� that��s ignoring the problem. The problem is the money isn��t being spent correctly,�� he said, adding that either plants aren��t spending the money to adequately winterize or they��re too old to function reliably.?

��We indeed price signals to incent people to come online and we need price signals that incent people to retire,�� he said.?

Renewables and reliability

Why aren��t renewables �� with wind and solar now among the cheapest forms of electric generation and battery storage prices falling over the long term �� riding to the rescue? Like everything in the power generation universe, it��s complicated.?

For one, PJM��s massive backlog in approving projects that are seeking to connect to the grid, called the interconnection queue, has ensnared tens of thousands of megawatts of mostly renewable projects. Reforms approved by FERC are expected to smooth the process, but some undoubtedly withered on the vine waiting their turn, Rutigliano said.

��If you make everyone go through a five-year delay, that��s going to kill a lot of projects,�� he said. ��We��d be in a very different place if the queue was working better over the last five years.��

PJM, though, pushes back on that argument. In a media briefing last month on the capacity auction results, Stu Bresler, senior vice president of markets for the organization, said 40,000 megawatts of resources, many renewable, have made it through the queue and have interconnection agreements but have not come online.?

��We know there are many issues facing developers today,�� he said, citing supply chain problems, inflation and land acquisition challenges. Indeed, renewable development is increasingly being met with resistance across the country. ��Certainly I think it��s safe to say it��s not just the queue reform that is holding up new resources,�� Bresler said. ��There are a lot of resources that can get started.��

In a report released last month, PJM noted that electric demand is projected to continue growing as a result of increasing electrification (such as in transportation and heating) as well as data center proliferation. At the same time, economics, as well as government and private sector preferences for carbon free generation, are prodding coal and gas plants into retirement. Those retirements, PJM noted, are ��at risk of outpacing the construction of new resources, due to a combination of siting and supply chain.��?

The queue is composed ��primarily of intermittent and limited duration resources�� (like battery storage) necessitating ��multiple megawatts of these resources to replace 1 megawatt of thermal generation.��

To avoid that ��timing mismatch,�� PJM says a lot of new renewables will have to come online quickly.

Despite the fact that 290 gigawatts of renewables are currently in the interconnection queue, PJM says the historical rate of completion for those projects has been about 5%.?

Renewables, because of their intermittent nature, are also valued differently for capacity purposes. As Mark Specht, a senior analyst with the Union of Concerned Scientists, noted in a blog post, it��s not enough to just replace energy from gas and coal plants with renewable power.?

��You have to replace their reliability contributions as well,�� Specht wrote. ��Adding replacement renewable energy to the grid is easy, but it��s much more complicated to figure out the extent to which you can rely on renewable capacity to ensure grid reliability by preventing electricity shortfalls.��

However, because of their failures during severe weather, some pro-renewable groups argue that PJM is overvaluing gas and coal for capacity purposes and perhaps undervaluing renewables.

Advanced Energy United, a trade group, wrote in a report last year that traditional methods overstate the capacity value of coal and gas plants by 2.7% to 20% in winter and 4.6% to 10% in summer.?

Fixing the market

In a report released March 9, PJM��s independent market monitor, Monitoring Analytics, said the organization��s markets ��work, even if not perfectly,�� though Winter Storm Elliott exposed ��significant market design issues.��

��There is no reason that in a rational market design less than 24 hours of cold weather should result in a crisis and a level of administrative complexity that threatens to undermine the incentives to invest in existing and new supply resources at a time when those resources are needed,�� the monitor said.?

The report says renewables will not be able to replace the capacity output of retiring fossil fuel plants and that gas power plants are the main option to do so in the near term. That will require large amounts of gas pipeline capacity and to that end, PJM should ensure it has ��real time, detailed and complete information on the gas supply arrangements of all generators.�� Gas supply was ?a major issue during Elliott, and PJM should also consider rules requiring capacity resources to have firm fuel supplies and examine access to firm gas supplies for new generators, the report said.

The capacity market itself, according to the report, is plagued by longstanding issues ��that continue to be ignored�� and have resulted in customers being overcharged by a combined $1.45 billion for the 2021/2022 and 2022/2023 auctions. Those include the capacity performance design, which it also deemed a ��failed experiment�� that should be scrapped. There should also be ��comparable treatment�� of thermal and intermittent resources, the monitor said.

Among a range of fixes, the market monitor recommends that, rather than increase or decrease penalties, weaken performance requirements or provide more money to generators, PJM should ��return to the basic purpose of a capacity market, including ensuring that capacity resources are paid only when available to provide energy.��

PJM��s board has launched a fast-track process to gather input on a potential Oct 1 filing with FERC to approve capacity market changes.?

��The board welcomes the FERC forum and believes that, if anything, the commission��s interest in these larger issues provides further support for use of the [Critical Issue Fast Path] process so that potential solutions can begin to be vetted and then presented to the commission,�� the board said.

Winter storm Uri brought historic cold weather and power outages to Texas, including Fort Worth, shown here on Feb. 16. Storms swept across 26 states, bringing a mix of freezing temperatures and precipitation. (Photo by Ron Jenkins/Getty Images)

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, 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.��

A no trespassing sign is posted in front of a Pacific Gas & Electric (PG&E) electrical substation on Jan. 26, 2022 in Petaluma, California. (Photo by Justin Sullivan/Getty Images)

A federal task force wrestled with the costs and benefits of better shielding the nation��s tens of thousands of electric substations from a growing number of attacks, like a neo-Nazi plot the FBI says it foiled earlier this month in Maryland, another that knocked out power to thousands in North Carolina in December and more in the Pacific Northwest.

��These events correspond with an increase in extremism in our country,�� said Federal Energy Regulatory Commission Chairman Willie Phillips during a Wednesday meeting of a federal-state task force on electric transmission. Phillips cited a report released last year by the Program on Extremism at George Washington University that found that between 2016 and 2022, ��white supremacist plots targeting energy systems dramatically increased in frequency,�� with 13 people arrested and charged in federal court during that span, most of them in the past two years.

In December, FERC ordered a review of security standards at electric transmission facilities and control centers. That review, to be completed by the North American Electric Reliability Corporation, which sets and enforces reliability standards for the bulk power system in the U.S., Canada and part of Mexico, is due in April.

But at the task force meeting, NERC President and CEO James Robb said there are more than 50,0000 high voltage substations dispersed across the country and that regulators will have to make difficult decisions about which ones most need additional security.

��That��s a tremendous amount of infrastructure to protect,�� he told the task force, a mix of FERC commissioners and state utility regulators.��It��s not as simple as ��we should just protect everything.�� Your ratepayers that you��re responsible for probably wouldn��t like that answer.��?

Robb said the vast majority of ��physical security events,�� including vandalism, theft of copper wires and other components and shooting attacks, don��t result in any impact to the grid. Only about 5% do, though the bad news is the attacks are increasing, with extremist groups posting instructions for disabling critical infrastructure on the ��dark web,�� he said.

Puesh Kumar, director of the U.S. Department of Energy��s Office of Cybersecurity, Energy Security and Emergency Response, said that, in 2022, there were 163 events categorized as ��physical�� incidents involving electric infrastructure, including vandalism and sabotage, up from 92 in 2021.?

��The majority of incidents, there isn��t a lot of good information on what caused it,�� he told the task force. ��When these events do occur they tend to be pretty localized.��?

Existing regulations, which came about after a 2014 sniper attack on a California electric substation, only apply to facilities that, if they were knocked out or damaged, could create hazards for the larger grid, like cascading outages.

Many substations, like the ones targeted in Moore County, North Carolina, don��t meet that threshold, but damaging them can still result in a loss of power for thousands.??

��The consequence we��re protecting against is the cascading event that would (affect) millions of customers, not thousands,�� he said.?

As NERC works through its report, he suggested state regulators open dialogues with utilities about security costs.?

��You have to weigh the customer impact of this �� relative to your cost to defend against it,�� he said. ��A substation in a very rural part of the country will have different vulnerabilities than one in downtown Manhattan.��?

Dan Scripps, a task force member and chair of the Michigan Public Service Commission, said he wasn��t ��entirely convinced�� that there shouldn��t be some baseline security requirements, such as fencing, regardless of where a facility is located.

He added that it��s difficult, ��from an optics and public responsiveness position�� to have to explain to utility customers that there are no minimum standards in place for many facilities.?

��There��s definitely work to be done,�� Robb said. ��There could be room here for a minimum threshold of protection.��

Robb added that states are free to impose their own security requirements.

��You can always go further,�� he said.?

FERC Commissioner Mark Christie, a former Virginia utility regulator, suggested states should work with utilities to develop a ��hierarchy�� of the most crucial facilities.

��You can��t harden every substation in the country,�� he said. ��The costs would be astronomical.��

Kumar noted that beefing up physical security is one approach to the problem, but so is making the power system more resilient by improving electric transmission, exploring more distributed generation and microgrids with battery storage that are less dependent on the larger power system.

��I think we have an opportunity but we need to be balanced,�� Phillips said, recalling a conversation with his personal trainer. ��You can pay me now or you can pay the doctor later.��

Wind turbines in Hardin County, Ohio, on Feb. 3, 2023. (Robert Zullo/ States Newsroom)

BUCYRUS, Ohio �� In four terms as a county elected official in northern Ohio, it was the most contentious issue Doug Weisenauer had ever seen.

The state legislature had newly empowered county governments to drastically restrict wind and solar power development, a process formerly overseen by the Ohio Power Siting Board, and the meetings of the three-member governing body for Crawford County (population 41,754) suddenly started becoming a lot more animated.?

��As soon as Senate Bill 52 passed, the anti-wind people, they started converging on our weekly commissioners�� meetings and demanding that we do something,�� said Weisenauer, a Republican, like the other two members of Crawford County Commission.?

Apex Clean Energy, a Virginia company, had been signing leases with locals for a proposed 300-megawatt wind farm, called Honey Creek, but Weisenauer was skeptical it would ever get built, saying in an interview he��d seen more than half a dozen would-be wind projects come and go.?

Ultimately, the commissioners voted 2-1 last year, with Weisenauer the lone no vote, for a 10-year ban on wind development. The commission��s decision was overwhelmingly upheld by county voters in a referendum last fall.?

��I said all along I am not telling people what they can and can��t do on their property,�� Weisenauer said. ��It got ugly. Our families have been split, friendships broken. It was bad for our community.��

Crawford County, of course, is far from an isolated case. Across the country �� from suburban Virginia, rural Michigan, southern Tennessee and the sugar cane fields of Louisiana to the coasts of Maine and New Jersey and the deserts of Nevada �� new renewable energy development has drawn heated opposition that has birthed, in many cases, bans, moratoriums and other restrictions.?

With states, corporations, utilities and the federal government setting aggressive renewable energy goals, as well as big tax incentives such as in last year��s Inflation Reduction Act, wind and solar developers have been pushing projects that are igniting fierce battles over property rights, loss of farmland, climate change, aesthetics, the merits of renewable power and a host of other concerns.?

And those debates are often happening in a miasma of misinformation and skewed by political polarization. However, some who have seen the backlash to renewable development up close and personal also say developers need to do a better job of being upfront with communities and convincing them of the benefits of their projects.

��I��ve seen it getting worse and worse over the past four years. There��s a huge level of distrust,�� said Tony Zartman, a former Paulding County, Ohio, elected official who now works for the Conservative Energy Network, which promotes market-based policies at all levels of government to promote a clean energy transition.?

��We��re seeing so much opposition��

In a report updated last year, the Sabin Center for Climate Change Law at Columbia Law School found that ��in nearly every state, local governments have enacted policies to block or restrict renewable energy facilities and local opposition has resulted in the delay or cancellation of particular projects.��

Not including what it called ��reasonable regulations,�� the 2022 edition of the report found 121 local policies (up 17.5% from 2021) that block or restrict renewable energy and 204 contested renewable energy facilities (up 23.6%).?

��This report demonstrates that ��not in my backyard�� and other objections to renewable energy occur throughout the country and can delay or impede project development,�� the report says.

In August, the National Renewable Energy Laboratory released a pair of data sets on local wind and solar energy zoning laws and ordinances. There were nearly 2,000 wind energy ordinances and almost 1,000 for solar energy.?

��The significant uncertainty created by difficulties in siting and permitting may make it more difficult for developers to sign contracts with buyers and/or obtain financing at a reasonable cost of capital,�� said Jos�� Zayas, executive director of policy and programs at the American Council on Renewable Energy, a nonprofit pushing to transition the economy to renewable power.??

J.R. Tolbert, vice president of strategy and partnerships at Advanced Energy United, a trade association representing wind and solar developers, as well as energy efficiency, battery storage companies and other businesses, said local opposition is becoming a major obstacle.

��The siting issue in and of itself is an issue that is really important for us to address,�� he said. ��If we��re unable to site projects, then we��re unable to interconnect projects and we��re unable to deliver that energy.��

Decarbonizing the U.S. electric grid, which accounted for about a quarter of U.S. carbon emissions in 2020, not to mention the rest of the U.S. economy, will require vast new solar, wind and other resources, many experts agree. Doing so by 2035, the Biden administration��s goal, will require ��rapid and sustained growth in installations of solar and wind generation capacity�� that amounts to ��more than four times the current annual deployment levels for each technology,�� per another report in August by the National Renewable Energy Laboratory.?

��My guess is that we��re going to need a lot of renewables built on public lands further west, just because we��re seeing so much opposition growing up, especially sort of the middle of the country that��s already very dense on wind,�� said Rich Powell, CEO of Clear Path, a nonprofit policy group working to curb carbon emissions, during a panel discussion on the state of the electric grid since the deadly 2021 winter storm Uri.

��Many more peoples�� backyards��

Indiana��s emblematic of some of those tensions. The state is simultaneously home to a solar project that��s one of the nation��s largest and lauded by Republican Gov. Eric Holcomb but also, increasingly, county regulations that restrict or outright prohibit wind and solar projects, per the Indianapolis Star.?

��We��ve got more than 120 renewable energy projects underway in Indiana,�� said Dave Arland, a spokesman for Hoosiers for Renewables. ��Some have faced opposition, and some have not. But obviously the trend �� from our standpoint �� is positive.��?

Part of the reason behind the growth in opposition is the nature of wind and solar power itself. Rather than a traditional coal, gas or nuclear power plant that might only be seen by a handful of neighbors, solar developments and wind turbines are more spread out and invite more NIMBY-style complaints.

��Plenty of people don��t have a strong opinion about wind and solar in the abstract,�� said Ben Inskeep, program director at the Citizens Action Coalition, an Indiana consumer and environmental advocacy group. ��It��s literally in many more peoples�� backyards.��

There��s also an ideological bent to some of the opposition, said Kerwin Olson, the coalition��s executive director who��s spent years working on energy policy in Indiana. ��The direction of discourse really pivoted when we elected President Obama,�� he said. ��You were a socialist if you supported wind and solar.��?

Though Zartman, the Republican former county commissioner from Ohio, acknowledged that some of the loudest pushback comes from conservatives, he said he sees a ��mix�� of motivation in opponents, including major resistance to changes to the skyline. (Some renewable projects even in famously liberal areas have sparked major opposition).?

��I haven��t seen anywhere on a deed that it tells you you have control over your horizon and your view,�� he said.?

��It does have downsides��

Bob Sostakowski, who��s lived in Crawford County, Ohio, for more than two decades and joined the local anti-wind effort after he became aware of proposed projects popping up in his and neighboring communities, said there��s more than aesthetics at stake.?

��I had no opinion one way or another on wind until this,�� Sostakowski, 48, said. ��There��s an obvious and very provable negative impact on property values and people’s standard of living.��

Both Sostakowski and Kimberly Groth, 42, who lives in neighboring Seneca County and was heavily involved in the effort to defeat wind projects there and in Crawford, said it��s not reasonable to expect people in agricultural areas to put up with commercial wind farms.

��People want quality of life and people move to rural areas because of the peacefulness of it. When you introduce industrial scale wind over tens of thousands of acres, you��re interrupting that quality of life,�� Groth said.

��I think we��ve heard for 20 to 30 years now about renewable energy and there��s just this assumption that it��s good and that it��s going to save us. So I think for me personally the more I looked into it, the more I realized it does have downsides. �� Every form of energy has these pros and cons.��?

Sostatkowski rejected the notion that farmers and landowners should have the right to lease their property to big wind developers whether or not their neighbors agree.

��There is a big distinction between commercial farming and agriculture and the heavy industrial production of electricity,�� he said. ��At no point in our history has it been OK for people to do whatever they want.��

Sostatkowski added that when he was a kid, a bald eagle sighting was so rare, his parents would pull the family car over to catch a glimpse of one.

Decades later, the fact that a wind project can get a ��take permit�� for eagles or other protected birds that run into the blades is ��unfathomable,�� he said, for an intermittent energy generation source that takes up lots of space.?

��What a horrendous and irresponsible waste of resources, our manpower, our tax dollars and our wildlife,�� he said.

��It��s no inconvenience��

Matthew Eisenson, a fellow at the Renewable Energy Legal Defense Initiative at Columbia��s Sabin Center for Climate Change Law, said many of the debates over local renewable energy siting take on similar contours.?

��In almost every one of these contested projects people talk about visual impacts,�� Eisenson said. ��Second most common is impact to property values. A lot of people cite impacts to health which are spurious.��

Autism. Livestock harm. Soil and water contamination. Sleep deprivation. Illness. Interference with emergency medical flights. Former President Donald Trump famously (and falsely) said wind turbines cause cancer.

Many of those dire consequences and more crop up in debates about wind and solar siting and populate the Facebook pages and websites that pop up to oppose renewable development.?

Whether ��Wind Farm Syndrome�� really exists or is a psychosomatic condition created by fear of turbines themselves has been debated for years. Numerous studies, including an inquiry funded by the Finnish government on inaudible ��infrasound,�� have found no evidence turbines cause any health effects.???

That��s not to say that there are no impacts from wind and solar. Utility scale solar takes up a lot of land, requiring anywhere from 5 to 10 acres per megawatt. And there can be big drainage and sediment pollution problems if developers are careless. Wind turbines are huge and visible for miles. They do kill thousands of birds and bats a year, though scientists are trying to make them less deadly. While it��s rare, they can catch fire or leak lubricating fluid. And like any piece of machinery, they can break.

Mike Brady, 69, a farmer from Paulding County, Ohio, has 11 turbines on his 3,000 acres, where he grows corn and soybeans. The first became operational 12 years ago.?

��A turbine takes up maybe ? of an acre,�� he said. ����You just farm right around them. It��s a little inconvenient but for the price you��re getting paid it��s no inconvenience.��?

He says there is occasional ��shadow flicker�� (the effect of the sun shining through the turning turbine blades) and some noise.

��There is flicker at my house. It��ll maybe last five minutes. It just depends on the wind and the angle of the sun. We pull our drapes,�� he said. ��You��ll hear a noise at like 4 a.m. if you go outside because there��s no other noise. �� You can hear a hum out of them. But it doesn��t keep you awake.��?

Once, a turbine blade broke, which made ��quite a noise,�� he said, and birds do get hit occasionally.

��They have done bird studies around a couple of my turbines,�� he said. ��They find one or two birds a year. Of course they assume that they hit the turbine.��

But both Brady and Zartman, the former Paulding County commissioner, said the turbines have been a windfall for rural Paulding��s local school and government coffers.

��As a county, we were virtually bankrupt,�� Zartman said. Paulding, entirely reliant on agriculture and which had a population of about 19,000 as of 2021, had been hit hard by the recession that began in 2007. There was some resistance to hosting turbines, which he described as coming from out of state, but it never got much traction, he said.

��The anti group was telling everybody that our large commercial dairy farms would quit producing milk because of the noise and the flicker effect from the turbines. They told us all of our children would be autistic,�� he said. ��They never really got a firm foothold in our community.?

By 2019, wind development, then at 188 turbines, was pumping about $2.5 million in payments in lieu of taxes into the county budget, a local news outlet reported.

��All the school districts struggled with money. Now they��re doing quite well,�� Brady said.?

��It��s our land��

When part of their 300 acres of farmland in rural Seneca County, Ohio, was leased for a potential wind project, Anne Fry, a retired local teacher, and her husband were looking forward to the additional financial security a lease payment would provide, but also the influx of cash the project was expected to bring in for the local school system.?

��At first we were excited,�� Fry said in an interview. ��I was naive about so many things.��

She got a rude awakening at an early meeting on the project.

��I thought, ��I can��t wait to see if there��s going to be a turbine on our land,�� she said. ��It was packed. I saw people, they were so angry they were shaking. They were furious. �� They said it was all done in the dark of night, it was secretive. … I didn��t think anybody cared.��

Ultimately, Seneca County Commissioners voted in November of 2021 to ban large wind and solar projects in all unincorporated areas of the county.?

��It��s our land. And if we want to grow corn, soybeans, or put green energy on our land, why is it someone else��s choice, who might live on a postage stamp size lot, to tell us what we can and cannot do with our land?�� Fry said.

Indeed, hosting renewable development has become an attractive option for struggling farmers.

Per the U.S. Department of Agriculture, the number of U.S farms has fallen from a peak of 6.8 million in 1935 to about 2 million in 2021, down from 2.2 million in 2007.?

Farmers have been under financial pressure from the pandemic, a trade war with China (the world��s largest agricultural importer), severe weather events, depressed prices and rising costs of production like fuel, fertilizer, equipment and other inputs, said Andrew Walmsley, senior director of government affairs for the American. Farm Bureau Federation, which has six million members nationwide.?

Against that backdrop, leasing acreage for wind and solar can be a lifeline to financial stability.??

��It��s a great predicament to be in if you want to diversify income,�� Walmsley said. ��It also creates challenges in a lot of rural communities.��?

Many farmers lease some or all of the land they farm, and others are looking to buy more ground to take advantage of economies of scale. Siting renewable energy on prime farmland increases the cost of doing that, Walmsley noted.

��When that acreage is lost, that drives up the cost across the community. That’s the biggest rub,�� he said.?

Dave Crum, 78, who lives in Crawford County and has a lease for what was going to be Apex��s Honey Creek project, said he was also surprised by the degree of resistance, including the landslide vote that upheld the commissioners�� wind ban.

��I can��t understand the difference between renting your land for crop land and renting your land for a wind turbine,�� he said. ��It��s baffling when you have things that you think will help the community and they don��t let it happen.��?

Sitting at his dining room table on a frigid February morning, he compared the resistance to stories his grandfather, a local elected official, told him about people who cut down utility poles during rural electrification.?

��I��m not sour grapes. They voted to do that. Make sure you understand what you did,��? he said. ��Crawford County��s a very conservative place. Sometimes it kicks them in the butt.��

Honey Creek, in addition to payments to hundreds of local landowners and neighbors, would have provided up to $2.7 million per year in new revenue for local schools, county services and township governments in Crawford, about $80 million over the life of the project, according to Apex Clean Energy.??

��We were very disappointed in the result of the vote, which embodies a dangerous and precedent-setting expansion of government authority over local property rights,�� said Brian O��Shea, a spokesman for the company. ��The result restricted and effectively seized the individual land rights of more than 500 Crawford County farmers and landowners, who lost the ability to decide what they wanted to do with their own property.��

In an email, Larry Schmidt, a Crawford commissioner who voted for the wind ban, said ��very little dialogue took place between the anti-wind groups and the developers, making it difficult to have a conversation with a differing viewpoint.��?

Schmidt said he supported the wind ban to give locals a vote on the project.

��I favored this option because the developer indicated that they would challenge our decision by ballot,�� Schmidt said, adding that he ��pondered and prayed over this a lot,�� before making up his mind.??

��I do feel we may be missing out on economic gains, however we are more densely populated and the voters have spoken and voted overwhelmingly against,�� he said. ��And we work for them.��

Selling communities on the merits

Tolbert, the vice president of strategy and partnerships at Advanced Energy United, the trade group, says renewable energy companies need to build a ��bigger tent�� to help sell communities on the merits of projects.?

��We need to make this as an industry about workforce development, putting people to work, delivering money that can come into your community to help pay for schools, fire and EMS and for all the programs communities need,�� he said.

Developers also want regulatory certainty, he said, calling for more states to follow Illinois�� lead in setting statewide standards for wind and solar siting, an end run around the type of local opposition that snarled projects even in deep blue states. It can be politically tough, however, to water down or strip away local land use control, as lawmakers in neighboring Indiana found out when similar legislation setting statewide standards for wind and solar siting failed in 2021. Voluntary standards passed last year. Zayas, with ACORE, pointed to New York, which created an Office of Renewable Energy Siting to consolidate environmental review and permitting of major facilities into a single process.

��The reality is oftentimes what happens is a developer gets into the process, invests hundreds of thousands or millions in the process and a county can at the last moment change the rules on them,�� Tolbert said. ��That��s a process that isn��t fair.��

However, developers can also do more to build trust in communities. Zartman said.?

��They have a community in their target area for quite a while but then they start going out to try to get leases. They really don��t tell anyone openly that this is what they’re thinking until they��ve got quite a bit of the land leased,�� he said. ��By then they��ve invested oodles of money but they haven��t done anything to try to help public opinion.��

Both Sostakowski and Groth, the Ohio wind opponents, said a lack of advance notice from wind developers helped galvanize opposition.?

��By the time the community feeling on this becomes apparent the leases are already signed,�� Groth said.?

Zartman said renewable companies need to sell communities on the benefits of projects ��before you come in and try to steamroll your way�� to approval.

��How do you get community support if that��s how you start?�� he said. ��I understand what they��re thinking but as a former public official it��s a lot easier for me to be on board with a project if I��m part of the original planning process.��?

Wind turbines in Schlewswig, Iowa. MISO, which manages the flow of electricity in all or part of 15 U.S. states, was able to export power to its southern neighbors in part because its wind turbines produced enough energy during the storm. (Photo by Christopher A. Jones/Getty Images)

A day after Christmas, as parts of the country were still digging out from Winter Storm Elliott, the Wall Street Journal��s editorial page, undeterred by the absence of much concrete data, already knew where to cast the blame for rolling blackouts implemented in parts of the South to keep the grid from collapsing.?

��While there wasn��t a single cause for the power shortages, government policies to boost renewables snowballed and created problems that cascaded through the grid,�� the editorial board wrote.?

However, more than a month after the storm and the power cuts it triggered for customers of the Tennessee Valley Authority and Duke Energy in North Carolina, wind and solar energy �� which made up just 9.2% and 3%, respectively, of U.S. power generation in 2021 �� appear to have met, and, in some cases, exceeded, expectations, according to presentations by grid operators and utilities.??

A joint Federal Energy Regulatory Commission and North American Electric Reliability Corporation inquiry into the power system��s performance during the storm is ongoing.?

But the picture that��s emerged in the month since Elliott is one of inaccurate forecasting of how much electricity would be needed to weather the storm and large-scale fossil fuel plant failures and gas shortages that left grid operators scrambling to find enough power to meet demand.

��Almost no one got the load forecast right during Elliott, which was quite surprising,�� said Joshua Rhodes, a research scientist at the University of Texas at Austin who focuses on the bulk power system. He added that, generally speaking, grid managers rely chiefly on thermal resources (power plants that convert heat into electricity like nuclear, coal and natural gas plants) in their planning for severe winter weather because of the intermittent nature of solar and wind.

��If you’re going to call yourself reliable baseload, you better be able to turn on and produce electricity when you��re called on,�� he said.?

Duke Energy

In North Carolina, where about 500,000 Duke Energy customers for the first time ever had service cut to save the broader electric grid, company executives told the state��s public utility commission earlier this month that the company thought it had adequate reserve power to weather the storm.?

But as electric demand grew well beyond forecasts, natural gas and coal power plants began to experience freezing instruments and other problems (a total loss of about 1,300 megawatts of generation) and power purchases from out of state didn��t show up, the utility was forced to cut power to avoid causing a larger grid collapse.

��All of our neighbors were tight,�� Sam Holeman, a Duke executive, told the commission.??

The company��s modest solar generation, which performed ��as expected�� during the storm, wasn��t much of a factor because the electric shortfall happened overnight. As of 2021, wind, solar and hydroelectric power made up just 7% of Duke��s electrical generation.

��We own what happened. We have set out on a path to ensure that if we are faced with similar challenges, we will see a different outcome and provide a better customer experience,�� said Julie Janson, executive vice president and CEO of Duke Energy Carolinas, in a statement.?

TVA

In the Tennessee Valley Authority��s service area, which includes 10 million people in most of Tennessee and parts of Kentucky, Mississippi, Alabama, Georgia, Virginia and North Carolina, actual electric demand surged well past forecasts, with TVA breaking its all-time record for single-day electric demand. At the same time, TVA��s 2,500 megawatt Cumberland power coal plant went offline early on Dec. 23, the authority said, because of frozen instrumentation. Other gas plants went offline ��due to the cold,�� a spokesman said, though more details will be available after a full internal review is completed.?

Just 3% of TVA��s generation portfolio is wind and solar, but according to preliminary data from the federal Energy Information Administration, the relatively small amount of solar TVA has performed consistently during the storm.?

��Our crews worked 24/7 to successfully restore some of the impacted generating units to service during the event,�� spokesman Scott Fiedler wrote in an email. ��We also purchased and imported generation from neighboring markets as much as we could, however, these efforts were challenged as surrounding utilities and market operators were also experiencing high demand.��

TVA was able to pull power from the Midcontinent Independent System Operator, which manages the flow of electricity in all or part of 15 U.S. states (Arkansas, Illinois, Indiana, Iowa, Kentucky, Louisiana, Michigan, Minnesota, Mississippi, Missouri, Montana, North Dakota, South Dakota, Texas and Wisconsin). Despite its own unplanned generation outages, MISO was able to export power to its southern neighbors in part because its wind energy production remained high during the storm.?

��Wind saved the day,�� said Simon Mahan, executive director of the Southern Renewable Energy Association, a nonprofit trade organization. ��Had there not been nearly as much wind I think things might have been more severe.��

The situation forced TVA to cut power to thousands of customers, though an exact number hasn��t been released. Fiedler said TVA has also created a ��Blue Ribbon Panel�� that includes the former CEO of the Electric Power Research Institute, a former U.S. senator and the president of the American Public Power Association, to provide an independent perspective and insight on TVA��s internal review.

��This review will be transparent and will move with a sense of urgency as we identify gaps, lay out corrective action plans and make the necessary changes to allow us to better respond to such challenging events in the future,�� he said. ��We know there is work to do to fully restore confidence in TVA��s ability to reliably provide the energy 10 million people count on every day, and we are committed to meet that expectation for the future.��

PJM

When PJM, the nation��s largest grid operator responsible for coordinating the movement of electricity in all or parts of 13 states and Washington, D.C �� a territory that numbers 65 million people �� issued a call for customers to conserve power during Elliott, it set off alarm bells for people in the power industry.?

After all, PJM had been under fire from consumer advocates who argued it was saddling customers in its territory with too much electric generation capacity.?

Going into the storm, PJM had a forecast for electric demand of nearly 127,000 megawatts and called nearly 156,000 megawatts of capacity into action.?

��We believed we had almost 29 gigawatts of reserve capacity available to absorb load and generation contingencies and to support our neighboring systems,�� PJM staff wrote in a preliminary report earlier this month.

But as temperatures started to plummet, ��a significant portion�� of that generation fleet failed to perform, with as much as 46,000 megawatts of power offline by Christmas Eve as a result of fuel problems, equipment failures and other issues, PJM reported. That severely limited the ability of PJM to send electricity to its neighbors, like Duke and TVA. On Dec. 23, ��PJM began curtailing exports as our capacity position deteriorated due to the generation failures that we were having.��

Most of those failures were natural gas power plants, followed by coal power stations. About 6,000 megawatts that went offline was listed in the ��other�� category, which includes renewables and nuclear, but a PJM spokesman declined to provide a more detailed breakdown due to what he said were confidentiality restrictions. PJM says the power generators that failed to perform when called upon face between $1 and $2 billion in penalties.?

��I can tell you that wind and solar resources performed as the near-term forecasts projected based upon wind speed and solar irradiance,�� PJM spokesman Jeff Shields said. At the end of 2021, renewables made up about 6% of the total generation mix.

Utility crews work on downed power lines after Hurricane Laura passed through Charles, La., in 2020. With three hurricanes in 2020, Louisiana had the worst performance among states for getting the power back on after a major event, according to a new report that compared how utilities ranked in three areas: reliability, affordability and environmental responsibility. (Photo by Joe Raedle/Getty Images)

A nationwide comparison of electric utility performance by an Illinois consumer advocacy group found that customers in states that are heavily reliant on fuel oil and natural gas, as in the Northeast and South, tend to pay more than those with larger amounts of carbon-free generation, among other findings.?

Kentucky, largely reliant on coal for electricity, has relatively cheap but dirty power, ranking higher among states for overall affordability of electricity. The state received poor marks in the report for environmental considerations such as high carbon dioxide emissions.??

The report by the Illinois-based Citizens Utility Board ranked all 50 states and the District of Columbia for utility reliability, affordability and environmental responsibility using 2020 public data from the U.S. Energy Information Administration, the federal Environmental Protection Agency and the U.S. Census Bureau.?

For overall performance across those categories, the top 10 were, starting with the highest ranked, Washington, Nevada, the District of Columbia, South Dakota, Illinois, Colorado, Arizona, Minnesota, Oregon and Nebraska. The bottom 10, starting with the lowest ranked, were West Virginia, Alaska, Mississippi, Massachusetts, Louisiana, Michigan, Alabama, Georgia, Indiana and Connecticut.

Kentucky ranked 35th in the country for overall performance, receiving better marks for affordability and reliability but ranking near the bottom for environmental aspects including a lack of clean energy generation and higher greenhouse gas emissions from electric utilities.

?It��s the second year in a row the group has compiled the report, which started as a way to measure how Illinois compared to other states and morphed into a project it hopes will be useful for utility regulators, electric ratepayers and state policymakers across the country, said David Kolata, the board��s executive director.?

��What we��ve tried to do here is provide as full a picture as we possibly can,�� he said. ��We view this as a conversation starter not a conversation ender. We do think it provides a convenient and accessible way to get at this data. �� Our hope is every state will improve in these categories.��

Affordability

Given the wide state-by-state variance in regulatory regimes, the difference in rates between customer classes and how their bills are put together, it can be difficult to compare electric prices across state lines. Also, climate and heating and cooling differences can make apples-to-apples bill comparisons tough. Electric customers in the South, for example, tend to rely on electricity for heating in the winter and face hotter summers that require more air conditioning than in the North, where gas is more common for home heating.???

��Whereas households in warmer climates may consume more electricity on an annual basis to run air conditioning units than households in colder climates, those same households will not spend as much on natural gas, propane or other heating fuels during the winter,�� the report says. Other states, like Alaska and Hawaii, are expensive by virtue of their geographic isolation from the larger U.S. electric grid.

The top 10 for overall affordability �� as measured by average household energy expenditures, total household electric costs as a percentage of income, electric cost per kilowatt hour, total cost electricity expenditures and cost of energy efficiency savings �� were Utah, Washington, Idaho, the District of Columbia, Colorado, Wyoming, Montana, Oregon, Nebraska and Illinois. The bottom 10 states were Connecticut, Hawaii, Massachusetts, Alaska, Rhode Island, New Hampshire, Vermont, Alabama, Georgia and South Carolina.?

Kentucky was 16th in the country for overall affordability, though Kentuckians contributed more of their annual household income in 2020 to electricity than residents of most states, giving about 2.48% of annual income to pay electricity bills. The Kentucky Public Service Commission is currently looking into how utilities? pass on costs to customers for fuel purchases.

According to the report, the average annual electricity cost for Kentucky residential customers was $.115 cents per kilowatt, while the national average was $.137 cents per kilowatt.

Though the study used 2020 numbers, those affordability problems in states that rely on gas will likely have gotten worse, Kolata said, given the huge spike in gas prices triggered in part by Russia��s war in Ukraine.

In November, the National Energy Assistance Directors�� Association said more than 20 million American families (roughly 1 in 6) are behind on utility bills and in total owed more than $16 billion as of August, up from $8.1 billion at the end of 2019, a problem expected to exacerbated by natural gas prices hitting a 16-year high. Power plants that burn natural gas provide about 38% of U.S. electricity generation.?

��There��s every reason to believe that those states that are dependent on natural gas and fossil fuel are going to do even worse on affordability going forward,�� Kolata said. He noted that the study found that states with significant amounts of ��firm�� carbon free generation, such as Washington and Oregon��s huge hydroelectric resources, and Illinois, which has more nuclear reactors than any other state, generally fare well on affordability measures.

Reliability

Though outages caused by power plants tripping offline, as in Winter Storm Elliott, get a lot of headlines, only about 1% of outage minutes nationally are caused by generation or transmission problems. Much more common are outages that hit the delivery system, such as storms downing power lines, equipment failures and other problems, the report says.

Using three reliability performance indices created by the electric power industry, the report ranked states based on how well utilities performed during ��major events�� such as ice storms, hurricanes and wildfires, as well as under normal circumstances.?

The top 10 for reliability were Arizona, Nevada, the District of Columbia, South Dakota, Nebraska, North Dakota, Maryland, Kansas, Minnesota and Florida. The bottom 10 were Louisiana, West Virginia, Maine, Mississippi, Oklahoma, Arkansas, Alabama, Alaska, MIchigan and Tennessee.?

Kentucky ranked slightly better than most states for overall reliability measures at 22nd in the country, with the power customer in the Commonwealth seeing power outages on average of 282 minutes, nearing five hours, due to major events in 2020.?

For 2020, Hurricane-prone Louisiana had far and away the longest average duration of power outages due to major events, at 3,624 minutes per customer, while Arizona, the best state, only averaged 72 minutes. In the U.S., 2020 set a record for the number of named storms (11) that made landfall, per the Weather Channel. Three hurricanes hit Louisiana that year.?

Without major events, Nevada was the top state (behind only the District of Columbia) with an average outage duration of 55 minutes per customer. The worst was West Virginia at 468 minutes.

Environment

The report also ranked states by their sources of electricity and emissions data, giving consumers, policymakers and others a ��bird��s-eye view of each state��s renewable, clean energy and fossil fuel mix�� as well as data on how aggressively utilities are deploying energy efficiency programs.?

The overall environmental ranking includes a combination of carbon and other emissions, renewable electricity (including biomass) generation, clean energy (defined as all renewables, plus nuclear and excluding biomass) and residential energy efficiency program savings as a percentage of residential electric sales. The top 10 were Washington, South Dakota, Oregon, New York, Vermont, New Hampshire, California, Idaho, Maine and Oklahoma. The bottom 10 were West Virginia, Kentucky, Indiana, Louisiana, Ohio, Missouri, Mississippi, Wyoming, Utah and Alaska. There were some interesting contradictions.?

For example, Texas led in both clean electricity generation and CO2 emissions.?

��Texas is big everywhere,�� Kolata said, adding that he hopes the report will be a tool for politicians, utility regulators, customers and others to begin exploring the difference in performance between states.?

��You can��t improve what you can��t measure.��?

In the report, Kentucky��s second-worst environmental ranking was driven by having some of the highest carbon dioxide emissions per gigawatt of electricity generated in the state and a lack of energy efficiency savings for customers, among other factors.?

In 2020, according to the report, Kentucky produced almost 50 million metric tons of carbon dioxide emissions to generate electricity, with 779.44 metric tons of carbon dioxide emissions produced per gigawatt of electricity generated. Only West Virginia and Wyoming produce more carbon dioxide emissions per gigawatt generated.?

To find out how your state compares, click here.

Liam Niemeyer contributed to this story.

Detroit residents were among those who experienced frigid temperatures over the holidays. The winter storm dropped temperatures to single digits in much of the country and led to controlled power outages to prevent grid failure. (Photo by Matthew Hatcher/Getty Images)

The deadly winter storm, christened Elliott by the Weather Channel, that tore through much of the United States over the Christmas weekend placed a huge strain on the American electric grid, pushing it past the breaking point in some places.

Frigid temperatures, in some places setting records, drove a surge in electric demand while also causing big problems for gas, coal and other power plants that took electric generation offline just when it was needed most. That forced some southeastern utilities to cut power to thousands of people on a rotating basis, and led grid operators to urge customers to conserve power.?

?��Supply and demand for electricity have to exactly balance in real time,�� said Michael Goggin, a longtime electric industry analyst and vice president at Grid Strategies, a consulting firm focused on clean energy integration. ��If not, in a matter of seconds the grid can collapse.��

The Federal Energy Regulatory Commission and the North American Electric Reliability Corporation announced Wednesday that they will open a joint investigation into the power system��s performance.

��There will be multiple lessons learned from last week��s polar vortex that will inform future winter preparations,�� said Jim Robb, president and CEO of NERC, the nonprofit regulator that sets and enforces reliability standards for the bulk power system in the U.S.?

��This storm underscores the increasing frequency of significant extreme weather events (the fifth major winter event in the last 11 years) and underscores the need for the electric sector to change its planning scenarios and preparations for extreme events.��

But for some experts, a major lesson from the storm is already plain, and it’s the same as learned in past severe winter weather: The U.S. grid needs to be better connected to enable power to be moved easily to where it��s needed in moments of crisis.

��Although this was a massive event that ultimately affected huge parts of the country, there were geographic elements to it,�� said Ari Peskoe, director of the Electricity Law Initiative at Harvard Law School. ��The attention belongs on the transmission system.��

The storm

John Moore, a meteorologist with the National Weather Service, said the storm was unusual in several aspects, including the rapid drop in temperatures triggered by a blast of arctic air pushing down from Canada far into the American South, the rapid strengthening called ��bombogenesis,�� and the heft of the pressure behind the system, which he said set a record in Edmonton, Canada.??

��It��s a very broad system and it��s a lot of impacts associated with it. �� The cold air with this one was a little bit stronger than we usually see this time of year,�� Moore said, noting that the storm caused temperatures to drop 37 degrees in one hour at Denver International Airport, for example, and set temperature records in Wyoming and Montana, according to preliminary data.??

As it moved east, it caused a deadly blizzard in the Buffalo area that claimed at least 40 lives and wreaked havoc on the electric grid.?

��There were likely other records set across the South and East Coast,�� Moore said.

Outages

Though hundreds of thousands of homes and businesses were left without power because of normal storm calamities such as downed power lines, many other customers in the Carolinas and the Tennessee Valley Authority service territory, which includes most of Tennessee and parts of Kentucky, Mississippi, Alabama, Georgia, Virginia and North Carolina, saw outages because of the strain struggling power plants and surging demand placed on the grid.

��What we saw was concerning,�� said Goggin, who was monitoring data from many of the major regional transmission organizations hit by the storm. ��You saw very high unplanned or forced outages of power plants of many types but primarily fossil.�� The extreme cold shut down many natural gas production wells, he said, which limited pipeline supplies that feed power plants.?

��We��ve seen a number of events like this where the extreme cold disrupts the gas system which then cascades to the power system,�� he said.?

TVA?

On Dec. 23, with demand climbing past 33,000 megawatts (its normal December demand is around 24,000) the TVA for the first time in its 90-year history instituted load shedding �� temporary, controlled outages �� and urged customers to conserve electricity. The service interruptions ended on Dec. 24, with the TVA saying it had supplied more power over the previous 24 hours than ever before to meet an all-time peak winter demand. POWER magazine also quoted a TVA spokesperson saying that a ��limited number�� of power plants in TVA��s territory ��did not operate as expected during this event resulting in a loss of generation.��

��We at TVA take full responsibility for the impact we had on our customers,�� the authority said in a Dec. 28 statement. ��We are conducting a thorough review of what occurred and why. We are committed to sharing these lessons learned and �� more importantly �� the corrective actions we take in the weeks ahead to ensure we are prepared to manage significant events in the future.��

In an email to States Newsroom Thursday, a TVA spokesperson could not say how many customers were affected nor provide any information on why power plants weren��t able to perform, citing the ongoing review. In the Memphis area, where Memphis Light, Gas and Water is the TVA��s largest customer, more than 30,000 customers were affected, WMC-TV, a local station, reported. The Chattanooga Free Press reported on Christmas Eve that the TVA had lost about 6,000 megawatts of generation the day before at coal and gas plants.

��Until the review is completed over the next few weeks, any discussion on individual plants would be inappropriate because it would just be speculation on our part,�� TVA spokesman Scott Fiedler told States Newsroom. ��As the wholesale power provider, we instruct our 153 local power companies to reduce load. They implement the process to limit the impact to their customers. We expect customers were affected by 15-30 minutes in a rolling fashion as LPCs implemented curtailments.��

Duke Energy

Duke Energy, one of the nation��s largest utility companies, was forced to cut power to about 500,000 of its customers in North Carolina and South Carolina on Dec. 24, with the last of them having power restored by about 6 p.m., spokesman Jeff Brooks said.?

��The combination of temperatures that were lower than forecast, customer usage that was higher than projected, some reduction in generating capacity on our system and limited options for additional capacity from outside of our service area due to extreme cold weather that impacted the eastern half of the United States created conditions that resulted in the need to conduct temporary outages,�� Brooks said.?

��We made this difficult decision to protect the electric grid and reliability on our system, and to avoid a potential longer or broader outage to customers.��

Another Duke Energy spokesman told States Newsroom in November, in response to a report by NERC that its service territory might be vulnerable to electric outages in the event of extreme winter weather, that the company was ��ready to meet the energy needs of our customers every day, regardless of weather.��?

Brooks said the company is still examining generation performance during the storm and assembling information for regulators and couldn��t provide more details on what type of power plants failed to perform.?

Duke Energy assures me NC is in the clear now. But I��m deeply concerned about people who lost power and who didn��t get notice about rotating outages. Grateful for those who conserved energy. I��ve asked Duke for a complete report on what went wrong and for changes to be made. – RC

— Governor Roy Cooper (@NC_Governor) December 26, 2022

Duke Energy officials are scheduled to brief the N.C. Utilities Commission staff on the outages on Tuesday.??

��It was a combination of generation on our system that was either reduced or unavailable that evening, coupled with the inability to import additional electricity from out of state (which is something we can typically do to add to our native generation) that resulted in the need to initiate temporary outages,�� Brooks said, noting that solar wasn��t a factor because it was dark when the outages were initiated. As of 2021, wind, solar and hydroelectric power made up just 7% of Duke��s company-owned output.

��We did believe that we had adequate generation going into Friday evening to meet the forecasted demand for electricity,�� Brooks said. ��That demand ultimately came in higher than we forecast.��

PJM?

Faced with plunging temperatures, surging power demand and some power plants struggling to perform, PJM, the nation��s largest grid operator, issued a call for customers to conserve energy a day before Christmas Eve. The call came as a surprise for electric industry experts.

In a winter reliability assessment, NERC said that PJM �� which coordinates the movement of electricity for 65 million people in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia �� ��expects no resource problems over the entire 2022-23 winter peak season because installed capacity is almost three times the reserve requirement.��

But a big portion of that excess electric generation capacity was struggling to produce power, said Michael Bryson, PJM��s senior vice president of system operations.

��We saw pretty significant generation outage data coming in, failing to start or tripping offline, far exceeding our ability to keep up,�� Bryson said. In its request to the Department of Energy for a temporary waiver of environmental rules for generation units, PJM said its peak load, or electric demand, exceeded 135,000 megawatts on Dec. 23 while about 45,000 megawatts of generation were out or underperforming. (PJM lists about 185,000 megawatts of total generation capacity)

Bryson said in an interview that the performance problems affected coal, gas and nuclear plants. Wind, which makes up the majority of renewable energy in PJM��s generation mix (though it is dwarfed by coal, gas and nuclear) performed well during the storm, Bryson said. He had not had the chance to review how solar energy fared during the event.?

��We��ll be working through those issues unit by unit over the next week,�� he said, adding that power plants that failed to meet their performance criteria risk financial penalties.?

In addition to participating in the NERC-FERC inquiry, ��we��re going to kick off a pretty comprehensive lessons-learned session ourselves,�� Bryson said, including examining the organization��s own extreme cold electric load forecasting. He said PJM��s forecast was low by about 7 to 10% on Dec. 23.

Creating a grid ��bigger than the weather��

Peskoe, the director of the electricity law initiative at Harvard, and Goggin, the energy consulting firm executive, both said too often in the aftermath of major storms that stress the power grid, one form of generation or another comes under fire.?

��Extreme weather like this does affect all generation sources,�� Goggin said, though he said it appeared that renewables, which don��t need coal piles that can freeze or pipelines that can be curtailed by cold, largely fared well during the storm.

But the real task for the people in charge of the nation��s electric grid, is to grow a transmission system that��s ��bigger than the weather,�� as Goggin put it.

��When you do that, it allows you to bring in power from areas that are less affected,�� he said. ��Having a large grid that allows you to move power around as events like this unfold provides a lot of value.��?

Goggin said he monitored data from the regional transmission organizations affected by the storm, including the Southwest Power Pool and MISO (Midcontinent Independent System Operator), neither of which had to resort to rolling outages, and noticed that wind electric prices in those markets plunged to very low or even negative levels. That means there wasn��t enough transmission capacity to get the large amount of electricity the turbines were producing to where it was needed.

��That power would have been extremely valuable in locations farther east but it couldn��t get out of the wind-producing areas,�� he said.?

Simon Mahan, executive director of the Southern Renewable Energy Association, a trade group for large renewable energy and energy storage companies, said the storm showed how critical interconnection between regions is for reliability and that other parts of the southern electric grid are vulnerable to severe winter weather like the catastrophic grid collapse Texas saw in 2021

��Being connected with our neighbors is exceptionally important,�� he said. ��If we weren��t connected with MISO and PJM, things would have been a disaster. �� Winter Storm Elliott is kind of that storm that showed that the rest of the Southeast is vulnerable like Texas was.��

Mahan noted that the storm raised transparency issues as well, with real-time data on generation and load coming in from areas controlled by regional transmission organizations like PJM and MISO but not so much from areas controlled by the TVA or monopoly utilities like those owned by Duke in the Carolinas and Southern Company in Alabama and Georgia.

��It��s very easy to see where there are problems. But in the Southeast, because there��s so little transparency, it��s hard to see,�� he said.?

The storm came as FERC is weighing a major proposed rule on streamlining regional electric transmission planning and cost allocation as well as taking into account broader benefits. And it comes less than a month after a FERC-led meeting on potentially requiring a minimum amount of interregional electric transfer capability �� electricity that can be moved between regional transmission systems ��? for public utility transmission providers. Supporters described it as an ��insurance policy�� in the event of grid crises like extreme weather.?

��One thing that I hope is explored as people try to dissect what happened is what would the value have been of interregional transfer capability during this event,�� Peskoe said.

FERC Commissioner Willie Phillips at the meeting said better transfer capability can improve reliability and resilience, lower costs for customers by allowing them to access cheaper electricity and accommodate more renewable power.?

��Given the likelihood of future extreme weather events and related generation shortfalls, many stakeholders have been asking us to do something,�� Philips said. ��Both Winter Storm Uri and the 2014 polar vortex, these events have shown that greater interregional transfer capability has a significant reliability benefit.��?

Not everyone was a fan of the idea though. Tricia Pridemore, chair of the Georgia Public Service Commission, which regulates utilities, said states like Georgia that are not part of regional transmission organizations, don��t need a new transfer requirement, citing the state��s utility planning process and cooperation with other southeastern utilities.?

��Our bottom-up approach maintains reliability and does not put upward pressure on rates by constructing unnecessary or duplicative transmission assets,�� she said. ��Georgia is better for maintaining a safe, reliable affordable system all while not being told to do so from a top-down governance structure.��?

According to the federal Energy Information Administration, Georgia is one of the more expensive states in the South in terms of average residential retail electric price and Pridemore��s commission just approved a big rate hike for the state��s dominant utility, Georgia Power.?

��The reality is during the storm and this past week after the storm, Southern Company and Georgia have really relied on imports from MISO and a significant amount of power from Canada that has been brought into MISO,�� Mahan said. ��It��s pretty incredible how Canada is helping keep the power on in places like Atlanta.��?

Executives at the Shell Chemical petroleum refinery in Norco, Louisiana, agreed to install $10 million in pollution monitoring and control equipment in 2018 to settle allegations it was violating the Clean Air Act. The Biden Administration was expected to increase EPA enforcement but that hasn��t happened says a national environmental group. (Photo by Drew Angerer/Getty Images)

Lawrence Livermore National Laboratories Director Dr. Kim Budil speaks during a news conference with fellow administrators and scientists at the Department of Energy headquarters to announce a breakthrough in fusion research on Dec.13, 2022 in Washington, D.C. The officials announced that experiments at the National Ignition Facility at the LLNL achieved ignition, where the fusion energy generated equals the laser energy that started the reaction for the first time ever, a major advancement that may produce bountiful clean energy in the future. (Photo by Chip Somodevilla/Getty Images)

Scientists at a U.S. national laboratory announced Tuesday that they achieved fusion ignition, a breakthrough decades in the making that could have major implications for clean energy.

Researchers at the Lawrence Livermore National Laboratory near San Francisco said that on Dec. 5, for the first time anywhere in the world, they managed to produce more energy from a nuclear fusion reaction than was needed to produce it.

��This is what it looks like for America to lead. And we��re just getting started,�� said U.S. Energy Secretary Jennifer Granholm.

However, at the announcement, officials said it would be years before a commercial application, such as a fusion power plant, might emerge.

��There are very significant hurdles, not just in the science but in technology,�� said Kim Budil, director of the Lawrence Livermore National Laboratory. ��Probably decades. Not six decades I don��t think. Not five decades, which is what we used to say. I think it��s moving into the foreground and probably with concerted effort and investment, a few decades of research on the underlying technologies could put us in a position to build a power plant.��

Granholm said the Biden administration has a goal of getting to a commercial fusion reactor in a decade.

��We��ve got to get to work and this shows that it can be done, which has been a question,�� she said, adding that now researchers can begin improving the technology necessary to bring a commercial project to fruition.

Fusion, the same scientific process by which the sun and other stars are powered, involves the merging of two light atomic nuclei to form a single, heavier nucleus, a reaction that releases ��massive amounts of energy,�� according to the International Atomic Energy Agency.

Scientists have been attempting to harness fusion power since the 1930s because of its potential to provide vast amounts of clean energy, since fusion produces little waste and poses none of the hazards of nuclear fission, which splits atoms to generate heat. The challenge, however, has been recreating the conditions that allow fusion to occur, including extreme pressures and temperatures exceeding 100 million degrees Celsius.

��In this experiment we used the world��s most energetic laser, the National Ignition Facility, to create X-rays that cause a tiny capsule to implode and create a very hot, very high pressure plasma,�� said Mark Herrmann, the lab��s program director for weapon physics and design.

��And that plasma wants to immediately lose its energy. It wants to blow apart, it wants to radiate. It��s looking for ways to cool down. But the fusion reactions are depositing heat in that plasma. �� So there��s a race between heating and cooling. And if the plasma gets a little bit hotter, the fusion reaction rate goes up, creating even more fusions �� which gets even more heating. And so the question is can we win the race? And for many many decades we lost the race. �� But last Monday that all changed.��

Herrmann and other officials said the fusion breakthrough will also help ensure the safety and effectiveness of the nation��s nuclear weapon stockpile, which is also part of Lawrence Livermore��s mission, without underground weapons testing, since fusion ignition is a component of thermonuclear weapons.

Arati Prabhakar, director of the White House��s Office of Science and Technology Policy, recalled the summer she spent at Livermore as a student in 1978 working on lasers related to fusion experiments.

��They never lost sight of this goal,�� she said. ��And last week lo and behold, indeed they shot a bunch of lasers at a pellet of fuel and more energy was released from that fusion ignition than the energy of the lasers going in. �� I just think this is such a tremendous example of what perseverance really can achieve.��

Andrew Holland, CEO of the Fusion Industry Association, a nonprofit working to commercialize fusion power that calls itself ��the unified voice of the fusion industry,�� said in a statement that the announcement is ��an important milestone�� and evidence that fusion ��is not science fiction.��

��This will give governments around the world further incentive to support the development of commercial fusion energy,�� Holland said. ��It also shows that now is the time to establish regulatory regimes which both protect the public and encourage innovation. The FIA and our member companies will continue to meet milestones and drive rapid increases in fusion investment, while supporting efforts to increase interest from governments around the world.��

About 35,000 customers experienced rolling blackouts last Dec. 23 when LG&E and KU had to reduce supply to avert wider power outages. (Photo by iStock/Getty Images Plus)

The nonprofit regulator charged with helping ensure the reliability of the North American electric grid is warning of potential electric supply shortfalls during severe weather this winter in several regions of the country.

Earlier this month, the North American Electric Reliability Corporation, which sets and enforces reliability standards for the bulk power system in the U.S., Canada and part of Mexico, said New England and parts of the South and Midwest, are ��at risk of having insufficient energy supplies during severe winter weather.��

The organization pointed to fuel supply problems, potential shipping disruptions, limited natural gas infrastructure, fossil and nuclear plant retirements and high potential peak electric demand as contributing risk factors during sustained cold weather.

��While the grid has a sufficient supply of capacity resources under normal winter conditions, we are concerned that some areas are highly vulnerable to extreme and prolonged cold,�� said John Moura, NERC��s director of reliability assessment and performance analysis, in a statement. ��As a result, load-shedding may be required to maintain reliability.��
(Load-shedding means intentionally interrupting the flow of electricity to customers to reduce the strain on the grid.)

MISO: Extreme cold weather would bring challenges

For the part of the grid overseen by the Midcontinent Independent System Operator, an area that includes all or parts of 15 U.S. states (Arkansas, Illinois, Indiana, Iowa, Kentucky, Louisiana, Michigan, Minnesota, Mississippi, Missouri, Montana, North Dakota, South Dakota, Texas and Wisconsin), NERC worries that more than 4.2 gigawatts of nuclear and coal power plants have been retired. That��s the rough equivalent of four large (1,000 megawatt) power plants.

��An extreme cold-weather event that extends deep into MISO��s area could lead to high generator outages from inadequate weatherization in southern units and unavailability of fuel for natural-gas-fired generators,�� the report says.

MISO predicts its peak winter demand will be 102 gigawatts, with 113 gigawatts of electric generation available ��under normal grid conditions,�� Brandon Morris, a spokesman, said in an email. The organization��s all-time peak winter record for power demand was 109 gigawatts on Jan. 6, 2017.? However, Morris said staff members from the organization noted in a winter readiness workshop last month that extreme cold weather, intense winter storms and/or fuel supply issues could create challenges for MISO and local utilities.

Power generators in MISO, however, have shown improvement in preparing their plants for extreme weather, according to a winterization survey the organization conducted, Morris said.?

Warnings of potential outages in the South

NERC��s report says Texas, which largely operates its own electric grid, and much of Arkansas, Louisiana, Mississippi and the Carolinas, are all vulnerable to extreme cold because it could trigger power plant outages and big spikes in demand. In many parts of the South, electricity is the prime heating source and NERC says power generators and the fuel supply infrastructure that serves them ��remain vulnerable without weatherization upgrades,�� despite improvements since Winter Storm Uri in 2021, which caused an estimated 246 deaths in Texas after the grid collapsed.

��While the risk of energy emergencies in the three areas hardest hit during that event has not been eliminated, enhancements to equipment freeze protection and cold weather preparations for both the gas and electric industries is a positive step,�� said Mark Olson, NERC��s manager of reliability assessments.?

Duke Energy, which has about 4.5 million electric customers in the Carolinas, said it is prepared for extreme weather with well-stocked coal inventories that exceed pre-winter goals.?

��We are ready to meet the energy needs of our customers every day, regardless of the weather,�� said Bill Norton, a company spokesperson. ��As we do before each winter, we have prepared for the possibility of extreme cold across our electric system.��?

Norton also cited a power mix that includes renewables, nuclear, natural gas, coal and hydroelectric power, grid upgrades to serve a growing number of customers in North Carolina and plants that can run on more than one kind of fuel as key to guarding against outages caused by extreme weather.

In New England concerns about fuel delivery

New England relies on liquefied natural gas imports and oil-fired generators to meet peak demand days, NERC said, which means fuel delivery constraints and limited inventory of liquid fuels, worsened by the Russian invasion of Ukraine could increase the chance that power plants might lack the fuel they need to run, resulting in potential energy shortages in extreme weather.?

Concerns about winter power in New England aren��t new. In an August letter to U.S. Secretary of Energy Jennifer Granholm, Gordon van Welie, president and CEO of ISO New England, which is responsible for managing the flow of electricity for the six New England states, noted that concerns about energy challenges in the region go back a decade. He added that even as the states in the region push to decarbonize, it will rely on natural gas for the near future.

��During the coldest days of the year, New England does not have sufficient pipeline infrastructure to meet the region��s demand for natural gas for both home heating and power generation,�� van Welie wrote, adding that the organization has developed a tool to forecast potential energy shortfalls 21 days out and got federal approval to keep a natural gas fired plant running with access to liquefied natural gas imports.

��Based on these actions, and the results of our winter assessment to date, the ISO expects to be able to operate the system reliably in a mild to moderate winter (using established operational procedures to manage capacity deficiencies),�� he wrote. ��However, concerns remain should the region experience an extreme winter.��

The organization wants the federal government to heed requests made last summer by New England governors, including exploring suspension of the federal Jones Act, which prohibits foreign vessels from transporting goods (like liquified natural gas) between U.S. ports and developing a regional energy reserve for fuel oil in the area, among other asks.

NERC��s recommendations

NERC made a broad series of recommendations to mitigate risks to the power grid from extreme weather. First, it said power generators should be preparing for winter conditions and communicating with grid operators. They also should ensure they have adequate fuel on hand and the organizations that monitor them should keep tabs on fuel supplies as well. But NERC also urged state regulators and policymakers to ��preserve critical generation resources at risk of retirement prior to the winter season and support requests for environmental and transportation waivers.��

Holly Bender, the Sierra Club��s senior director of energy campaigns, called NERC��s suggestion to suspend environmental rules to keep fossil plants running ��the wrong strategy.�� Rather, Bender said the report makes the case that reliance on fossil fuels itself poses risks and she urged state regulators to instead push energy efficiency and weatherization programs that will cut power use. ��Whether it��s water shortages in the summer or frozen coal piles and short fuel supply in the winter, fossil fuels like coal and gas struggle through extreme weather,�� she said. ��In addition to the public health, environmental, and climate impacts, fossil fuels are increasingly unreliable, contributing to energy insecurity and unpredictable price spikes that impact the most vulnerable members of our communities the most.��

Utility companies are spending billions building out transmission and distribution lines around the country, leading some to call for an independent monitor to protect customers. (Photo by Robert Zullo)

An aging electric grid, fossil fuel power plant retirements and a massive renewable electricity buildout are all contributing to a boom in transmission and distribution wire projects by electric utilities across the country.

In 2020, investor-owned electric utilities spent $25 billion on transmission, up from $23.7 billion in 2019, figures that the Edison Electric Institute, which represents investor-owned electric companies, expected to only grow going forward.

Ohio-based American Electric Power, which is one of the nation��s largest electric companies and which operates the largest transmission system in the country (serving 5.5 million customers in 11 states) said last year that it plans to spend $23.3 billion between 2022 and 2026 on transmission and distribution.

But much of that spending is happening on local projects in states with widely differing regulatory regimes. And there��s been growing concern at the state and federal level that too much of it is occurring without enough transparency and oversight to ensure transmission owners are appropriately planning for new technology, considering more cost-effective regional approaches or alternate solutions and not ripping off their ratepayers.

��There��s going to be a significant amount of transmission built,�� Federal Energy Regulatory Commission Chairman Richard Glick said at a Nov. 15 meeting of a joint federal and state task force on electric transmission. ��We need to make sure consumers get the best bang for their buck.��

The meeting came more than a month after a FERC technical conference during which electric utility regulators and consumer counsel from a wide variety of states said, to varying degrees, that they often lacked the authority, information and expertise to properly vet and oversee the rising number of transmission projects happening in their states.

That��s led to growing support for the idea of an independent monitor to examine the need, costs and planning behind the wave of new projects to protect customers and ensure utilities �� for whom transmission spending and the return on equity it comes with is a major profit stream �� are looking beyond their own narrow financial interests.

��It is inexplicable, other than perhaps explained by utility influence, that massive expenditures for these utility local transmission projects are being charged to consumers without the government regulatory oversight that has been developed over a century for consumer protection,�� Mike Haugh, director of the analytical department at the Office of the Ohio Consumers�� Counsel, wrote in comments to FERC in support of independent transmission monitors.

��The ITM would allow for another level of protection for consumers that are paying for the transmission system.��

Not everyone, of course, is on board.

Electric companies and transmission owners see it as an unnecessary layer of bureaucracy, and even some utility regulators say it��s a job best left to states.

��Screams out for more oversight��

At the task force meeting Nov. 15, Andrew French, a commissioner at the Kansas Corporation Commission, which regulates electric utilities, said transmission costs in his state have gone from $4 a month on the average customer��s bill 10 or 15 years ago to $20 today.

��We are seeing a flood of capital investment in that area and that screams out for more oversight,�� he said.

Jennifer Easler, the Iowa state consumer advocate, which is responsible for reviewing and investigating regulated services provided by gas and electric utilities, said during the October conference that regulators need more information in advance to perform a holistic assessment of local transmission projects that aren��t being properly vetted at the federal or regional transmission operator level.

��By the time it arrives at the state regulator, when a utility wants to replace a new line because of age and condition, the regulator is hard pressed to say no to that,�� she said.

But some state regulators do have processes in place to properly vet transmission projects and utility building plans, which are called integrated resource plans.

��In Nevada we have one vertical (investor-owned utility) that’s regulated, and it handles just about all the transmission in the state, which means that any time new transmission is being proposed, in an interstate context at least, there’s a lot of robust and review and analysis of that transmission,�� said Cameron Dyer, assistant general counsel for the Public Utilities Commission of Nevada at the October FERC conference.

And not all utility regulators see the need for an independent monitor.

Tricia Pridemore, chairman of the Georgia Public Service Commission, touted Georgia��s pro-business rankings, economic development wins, below average electric rates, growth in solar energy, lack of outages or brown-outs and a collaborative process between regulators and utilities that ��has been perfected over decades�� at the Nov. 15 FERC task force meeting. (According to the federal Energy Information Administration however, Georgia is hardly an electric rate utopia, ranking 15th most expensive in average residential retail electric price.)

She admonished other state utility regulators to secure the budget and staffing to properly oversee projects rather than rely on a federally-imposed monitor.

��It lessens your authority to do the hard things that simply must be done,�� she said.

During the FERC proceedings, several large transmission owners have also dismissed the concept of an independent monitor as an unnecessary layer of bureaucracy that could gum up the works at a crucial juncture for the electric grid.

��We are currently living at a time when the need for transmission infrastructure investment has likely never been greater since the dawn of the industry. However, there remain a few who continue to throw sticks in the spokes with a desire to divert the focus from progress to regress,�� wrote Charles Marshall, vice president of transmission planning for ITC Holdings, which describes itself as the largest independent electricity transmission company in the United States. ITC owns and operates high voltage transmission in Michigan, Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma.

��This has led to a push for additional layers of bureaucracy that could introduce new uncertainty and jeopardize needed investments in reliability and resilience,�� Marshall wrote.

Jeff Burleson, a senior vice president of environmental and system planning at Atlanta-based Southern Company, which operates electric companies in Georgia, Alabama and Mississippi, said the company posts transmission plans twice a year on the Southeastern Regional Transmission Planning website and gets ��a significant amount of oversight at our state regulatory agencies.��

��I also don’t feel that there is value for us from thinking about some sort of independent monitor because we already have so much scrutiny that comes through all of our processes,�� he said.

But Easler, the Iowa consumer advocate, said in her comments filed with FERC that growing transmission costs are hitting many Iowa ratepayers hard and there��s often little state regulators can do.

��I would disagree with the notion that this is creating additional bureaucracy. It’s addressing a major oversight gap that exists,�� Easler said at the October conference.

The scope of the problem

The Federal Power Act, which dates to 1920, grants FERC oversight over electric transmission in interstate commerce and charges it with ensuring that costs billed to customers are ��just and reasonable.��

��Yet, over the past few decades, the commission has used its expansive ratemaking authority to institute several shortcuts that reduce its direct oversight,�� according to comments filed with FERC by Ari Peskoe, director of the Electricity Law Initiative at Harvard University Law School. ��The commission��s policies do not protect consumers.��

Peskoe singled out FERC ��formula rates,�� which, instead of relying on a contested rate case to establish the utility��s cost of service for transmission, allows the companies to file information with FERC in various categories �� including rate of return, operations and maintenance, depreciation, taxes and other factors �� that is used to calculate the formula rate they��re able to charge customers for local projects.

��Formula rates are a vehicle for avoiding burdens of proof and limiting protests. The commission��s default presumption that all transmission expenditures are prudent allows utility costs to flow through to consumers�� bills without scrutiny,�� Peskoe wrote, adding that FERC policies for transmission asset replacement and end-of-life projects amount to ��a blank check that may be worth hundreds of billions of dollars over the next few decades.��

While there��s some opportunity to challenge utilities�� formula rates, ��it��s not practical to do so on the piecemeal basis that these other projects are progressing,�� Easler said.

��The absence of customer-initiated challenges to local transmission upgrades in formula rate reviews is not an indication that all is well,�� she wrote in her comments to FERC. ��Rather, in the face of relentless transmission rate increase, it is an indication that this regulatory process is inadequate to protect customers from unjust and unreasonable charges resulting from inefficient siloed transmission planning processes.��

FERC Commissioner Mark Christie, a former member of the Virginia State Corporation Commission, has said the amount of transmission spending utilities are packing into their rate bases (the total value of a regulated utility��s assets and upon which its electric rates and profits are calculated) nearly tripled between 2012 and 2020.

��What goes into rate base goes into consumer bills,�� Christie said at the Nov. 15 task force meeting. ��This is a hugely important issue. This is a ton of money.�� Christie questioned task force members on whether FERC should deny formula rate treatment to utilities in states that can��t certify that they have a ��credible process�� for evaluating need and prudence of projects.

Transmission projects that span different utilities�� service territories in areas managed by regional transmission organizations go through a vetting process involving multiple parties, but utilities have almost total control over local projects, a major incentive to avoid regional projects in which they may have to share control and profits with another utility.

��They like the status quo, which is them building their own transmission wholly within their own territory and not having to share,�� said Nick Guidi, an attorney with the Southern Environmental Law Center who works on electric regulation issues at FERC and is pushing for market reform in the Southeast.

Guidi quibbled in particular with the characterization by Burleson, the Southern Company executive, that the company��s state regulators conduct a thorough review of transmission projects.

Even where certificate of public need procedures (a permit to build and operate a utility facility) exist in the Southeast, it��s generally only for new lines, not lines that are being rebuilt, upgraded or replaced.

��So we don’t always have this fulsome review of a comprehensive plan,�� he said. ��An (independent transmission monitor) would be a tremendous resource for states who don’t often have the resources to monitor the process.��

State provision limits oversight in Kentucky

Many states limit what their public utility commissions can approve based on size of transmission line, leading to utilities often picking solutions that fall under that threshold in order to avoid scrutiny.

That means that while the project might not be the most efficient or cost effective, it��s the easiest one for the utility to get built with the least amount of oversight.

For example, in Kentucky, utilities are required to seek a certificate of public convenience and necessity from the public service commission for any transmission line longer than a mile, said Kentucky Public Service Commission Chairman Kent Chandler.

But there are catches. A line being replaced in ��like kind�� in the same place does not require one, Chandler said.

��So there’s an opportunity for quite a bit of transmission for us not to know about it, for us not to see it until it shows up in a rate case,�� he said.

In Ohio, only lines above 100 kilovolts require a certificate of public need.

The role of a monitor

In October, Chandler said the monitor could serve a similar function to the independent market monitor in PJM, the nation��s largest regional transmission operator that coordinates the movement of wholesale electricity in all or parts of 13 states and the District of Columbia. The market monitor is tasked with helping maintain ��competitive and nondiscriminatory�� power markets.

��I can understand people saying that it might be an extra layer of bureaucracy, but for many of these projects it may be the only real set of eyes that’s looking at the need and the planning, and you can say it’s an extra layer, but it may be the only one really parsing through the numbers,�� Chandler said.

There seemed to be little appetite among consumer advocates or utility regulators for giving the monitor authority to issue orders rejecting or requiring any particular projects to be built.

��Certainly they’re not going to issue an order requiring something to be built, but they can provide information to the states to whatever agency has jurisdiction to consider a transmission expansion, whether it’s in their own state, or three or four states over,�� said Henry Tilghman, an energy lawyer representing the Northwest and Intermountain Power Producers Coalition, a regional organization for independent power producers and other companies. ��Just some good information that gives them confidence that they have the information they need to make an informed decision for their ratepayers.��

A final FERC decision on independent monitors, however, isn��t imminent. Though the current discussion on independent transmission monitoring is occurring as the commission is weighing a proposed rule aimed at encouraging more effective long-term regional transmission planning and changing how benefits and costs of new transmission are allocated, an order on independent monitoring would most likely come in a future rulemaking proceeding, experts said.

��It would require another NOPR (notice of proposed rulemaking),�� Guidi said.

Adrienne Mouton-Henderson, director of market and policy innovation at the Clean Energy Buyers Alliance, an association for commercial, industrial, nonprofit and other organizations looking to purchase clean energy, said the same objections to transition monitors were raised about electric market monitors.

��Everyone complained when it was first raised. �� It��s going to stop the system, we��re just going to be stalled out. And that��s simply not been the case,�� she said. ��Band-Aiding the system right now and putting the same assets in place is not helping us get renewables there, it��s not helping corporate sustainability goals, it��s not helping us get to clean energy. Transmission lines need to be rebuilt, they need to be upgraded regionally, and we need to make sure that we do it in a cost-effective manner for all ratepayers. �� and we simply aren��t doing it right now.��