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March 13, 2025

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Nev. Regulators Give Nod to NV Energy Clean Transition Tariff

Nevada regulators have approved NV Energy’s clean transition tariff (CTT), a framework developed in partnership with Google that will allow the utility’s existing large-load customers to receive power from new clean energy resources.

The Public Utilities Commission of Nevada (PUCN) approved the tariff March 11 after parties to the proceeding reached an agreement resolving their issues.

Under the agreement, one element of the tariff was left out of the commission’s approval: the base CTT rate model. That will be submitted for approval in a future integrated resource plan, or an IRP amendment, filed by NV Energy.

The commission said in its order that it won’t accept applications to take service under the new tariff until the base CTT model is filed.

Data Center Power

Google started working with NV Energy on the clean transition tariff as it looked for ways to power its northern Nevada data center with clean energy. Google has set a goal of running all its data centers and office campuses on 100% carbon-free energy by 2030.

Companies including Google that are seeking clean power have been buying electricity directly from energy developers. But those purchases are often “isolated from broader grid planning,” Google said in a blog post announcing the clean transition tariff.

“The CTT provides a novel and important opportunity for NV Energy and its customers to bring corporate investment capital into alignment with the utility planning process,” energy economist Carolyn Berry said in testimony filed with the PUCN on behalf of Google.

To power its northern Nevada data center, Google set its sights on an enhanced geothermal energy project from Fervo Energy. Without Google’s involvement, NV Energy wouldn’t have included the project in its IRP due to its cost, according to regulatory filings.

But through the CTT, Google plans to cover any premium costs of energy from the Fervo project to prevent cost-shifting to other customers.

During the long-term energy supply period, Google will pay a fixed price for energy from the 115-MW Fervo project. The entire output of the Fervo resource will go to Google. The data center is expected to need even more energy, which NV Energy will provide at a variable rate.

Existing Customer Benefit

The clean transition tariff is modeled on NV Energy’s Large Customer Market Price Energy tariff. The LCMPE tariff is only available to new customers; the CTT is a way to offer a similar arrangement to the utility’s existing customers.

The CTT is available to customers with an average annual hourly load of 5 MW or more, based on a 12-month rolling average. It applies to a clean energy resource that hasn’t previously been approved.

To use the CTT, NV Energy must file an energy supply agreement (ESA) as part of an IRP or an IRP amendment, or around the same time as those filings. The ESA must then be approved by the PUCN.

The ESA term must be as long as the life of the new resource.

NV Energy filed an ESA for Google to receive electricity from the Fervo project in June 2024, around the same time the utility filed its most recent IRP.

Two other ESAs linked to the CTT were also filed in June.

Under one agreement, Coeur Rochester would receive electricity from solar and battery storage projects for its mining, crushing and processing operations in Pershing County.

The other agreement involves solar and battery storage resources used to power the Las Vegas Convention and Visitors Authority’s offices and the Las Vegas Convention Center.

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EPA to Reconsider Endangerment Finding, GHG Rules

In a rapid series of announcements March 12, EPA Administrator Lee Zeldin unleashed a full-scale offensive on the agency’s regulatory authority, as it seeks to roll back as many as 31 regulations. 

Zeldin’s top targets include Biden administration rules on cutting emissions from vehicle tailpipes and coal-fired power plants and the 2009 endangerment finding, which established EPA’s authority to regulate GHGs under the Clean Air Act. 

The finding and other EPA rules threaten U.S. security and prosperity, Zeldin said in an agency press release, one of more than a dozen rolled out in a two-hour period. 

“The Trump administration will not sacrifice national prosperity, energy security and the freedom of our people for an agenda that throttles our industries, our mobility and our consumer choice while benefiting adversaries overseas,” Zeldin said. “We will follow the science, the law and common sense wherever it leads, and we will do so while advancing our commitment towards helping to deliver cleaner, healthier and safer air, land and water.” 

President Donald Trump first called for a reconsideration of the endangerment finding in his Jan. 20 executive order, “Unleashing American Energy.” Zeldin’s announcement begins a reconsideration process that could take months or years to complete and certainly will face legal challenges. 

According to EPA, multiple federal agencies and offices will be involved, including the Department of Energy, the White House Office of Management and Budget, and the National Oceanic and Atmospheric Administration. 

“It is in the best interest of the American people for EPA to ensure that any finding and regulations are based on the strongest scientific and legal foundation,” the agency said. “The reconsideration of the endangerment finding and EPA’s regulations that have relied on it furthers this interest. The agency cannot prejudge the outcome of this reconsideration or of any future rulemaking.” 

Zeldin did not comment on how major staff layoffs and anticipated budget cuts at DOE and NOAA might affect the reconsideration process.  

EPA’s ability to regulate GHGs, based on their threat to public health, was established in the Supreme Court’s 2007 decision in Massachusetts v. EPA. 

Jarryd Page, staff attorney at the Environmental Law Institute, said the court ruled that “greenhouse gases probably fall within the very expansive definition of pollutant under the Clean Air Act, and so, EPA, you need to make a finding one way or the other, on whether or not these greenhouse gas emissions endanger public health or welfare, or whether they’re reasonably anticipated to endanger public health or welfare.” 

After two years of study, the agency stating that GHGs are pollutants that do endanger public health, with a second finding issued at the same time saying they also “cause and contribute” to climate change. 

Page noted that Trump’s direct attack on the endangerment finding differs from the approach EPA took to GHG regulations during his first term, during which rules issued during the Obama administration were rescinded and replaced with less stringent regulations. “The endangerment finding was not challenged,” he said. 

A reversal of the finding would affect all sectors of the economy that emit GHG, Page said. “Removing the endangerment finding would mean EPA no longer has a requirement to regulate in any of these areas, and they could move forward with pulling back any and all of these Biden-era EPA regulations trying to reduce emissions.” 

But, Page noted, the Supreme Court has repeatedly declined to consider rolling back the endangerment finding, most recently in West Virginia v. EPA, which struck down the Obama-era Clean Power Plan. In general, reconsideration of EPA rules takes one to two years, he said. 

Avalanche of Announcements

Zeldin boasted in a video of “the greatest day of deregulation” in U.S. history before listing a handful of regulations EPA will reconsider. 

Among others announced later in the day was its mandatory GHG reporting program, under which businesses must calculate and report their emissions annually. 

Such reporting requirements are “another example of a bureaucratic government program that does not improve air quality,” Zeldin said in a press release. “Instead, it costs American businesses and manufacturing millions of dollars, hurting small businesses and the ability to achieve the American Dream.” 

Also up for reconsideration are the Biden administration rules on emissions from power plants and on tailpipe emissions from both light- and heavy-duty vehicles. 

Issued in April 2024, the 1,020-page rule on power plant emissions — referred to by opponents as “Clean Power Plan 2.0” — requires that coal-fired plants either ensure that 90% of their carbon emissions would be captured and stored by 2032 or close entirely by 2039. The rule sparked immediate legal challenges from Republican states and industry groups, but in an October ruling, the Supreme Court declined to put a hold on it. (See EPA Power Plant Rules Squeeze Coal Plants; Existing Gas Plants Exempt.) 

The costs that regulations impose on U.S. businesses and consumers were a consistent theme in Zeldin’s announcements, as was protecting consumer choice. 

Biden administration rules setting limits on tailpipe emissions from light-, medium- and heavy-duty vehicles resulted in $700 million in regulatory and compliance costs, EPA said in yet another press release. The rules were also characterized as the foundation for the nonexistent “electric vehicle mandate that takes away Americans’ ability to choose a safe and affordable car for their family and increases the cost of living on all products that trucks deliver.” 

Issued in March 2024, the emission rules for heavy-duty vehicles aimed to cut 1 billion tons of GHG emissions per year, while saving $3.5 billion for truckers. The rules also updated proposed standards issued in 2023 to provide a longer runway for manufacturers to meet emission-reduction targets. (See EPA Issues Final Standards on Heavy-duty Truck Emissions.) 

Other regulations and programs up for reconsideration include: 

    • limits on particulate matter, the microscopic pollution that can cause asthma and other respiratory illnesses; 
    • limits on hydrofluorocarbons used in aerosols, foam and refrigeration, which can be thousands of times more damaging to the climate than carbon dioxide; and 
    • standards on hazardous air pollutants — toxic chemicals that may cause cancer, birth defects or other serious diseases. EPA’s website notes that it has standards for 188 hazardous air pollutants. 

Rep. Julie Fedorchak (R-N.D.) called EPA’s reconsiderations “great news for North Dakota’s energy producers, farmers, businesses and families. This administration is taking decisive action to eliminate unnecessary, burdensome regulations that have made it harder for our energy producers to power the country and for our farmers to feed the world.” 

Rep. Frank Pallone (D-N.J.), ranking member of the House Energy and Commerce Committee, slammed the potential rollback of the endangerment finding as “a despicable betrayal of the American people. … Reversing the endangerment finding will have swift and catastrophic ramifications for the environment and health of all Americans.” 

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NERC Cold Weather Standard Commenters Say More Work Needed

In their last opportunity to provide feedback on NERC’s most recent proposed cold weather standard, several grid stakeholders continued to express doubt the standard will satisfy FERC’s directive to the ERO.

NERC’s Standards Committee approved EOP-012-3 (Extreme cold weather preparedness and operations) for a 45-day formal comment period at its meeting on Jan. 22. The actual comment period began Jan. 27 and ended March 12.

A formal ballot round would normally be conducted during the comment period, but will not take place in this case because the cold weather standard is the subject of a decision by NERC’s Board of Trustees to exercise its authority under Section 321 of the ERO’s Rules of Procedure. (See NERC Board Invokes Section 321 Authority for Cold Weather Standard.)

The board decided to take the Section 321 route after the standard failed its most recent formal ballot round that concluded Dec. 20 with only a 44.54% segment-weighted vote in favor, far short of the two-thirds majority required for passage. This represented an improvement of only about 2% from the previous ballot round, and the board worried that NERC might miss FERC’s deadline of March 27 to submit the new standard for commission approval.

After the comment period concludes, NERC will review all comments received, staff told the SC in January. (See Cold Weather Standard Set for Posting.) Trustees will then hold a special call ahead of FERC’s deadline to review the standard and any comments the committee considers relevant.

In its comment form, NERC asked stakeholders to respond to several questions based on elements of FERC’s order last year directing changes to EOP-012-2 (RD24-5). While most respondents said the new standard would satisfy the commission’s directive, the sentiment was far from unanimous.

Regarding the first question — which dealt with whether the standard’s generator cold weather constraint declaration criteria were “objective and sufficiently detailed” — Ruchi Shah, writing on behalf of AES U.S. Renewables, said he was “concerned the language used in several … criteria can be left to interpretation by the regional entities.”

Specifically, he said the phrase “comparable types in regions that experience similar winter climate conditions” lacked guidance as to how to interpret it.

Richard Vendetti of NextEra Energy similarly said while the newest revision added language regarding generator constraint criteria for wind turbines, there were “still many unknowns regarding specific criteria for solar generation.”  Without similar detail for solar generators, entities would not understand what is required of them, he said.

Vendetti said also that “NextEra would like to see industry visibility on the approval and denial of cold weather constraints,” and that transparency from the ERO on this subject would show industry what type of constraints are likely to be approved and help utilities save time and resources.

Another inquiry concerned NERC’s question about timelines for implementing corrective action plans (CAPs) after generator cold weather reliability events. Representatives from ACES Power said while the latest draft represents an improvement over previous efforts, the proposed standard is still “too ambiguous and may unduly discriminate against” generator owners arbitrarily.

ACES’ writers used the example of two entities that experience cold weather events on Oct. 22, 2025, and March 16, 2026. Under the proposed EOP-012-3, ACES said, both entities would have until Dec. 1, 2026, to implement a CAP, which in practice gives one entity much greater time for its fix. The commenters suggested modifying the standard to allow 12 calendar months for CAP implementation regardless of when the cold weather event occurs.

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Trump Cabinet Members Ding Climate Change at CERAWeek 2025

HOUSTON — Two members of President Donald Trump’s cabinet swept through CERAWeek by S&P Global to cheer on attendees with bombastic messages and their plans to take the U.S.’ energy industry in an entirely new direction. 

They spoke energetically and quickly, eschewing notes and frequently lauding the president. When their appearances were over, one frazzled attendee remarked, “Is it just me, or are they high on amphetamines?” 

Energy Secretary Chris Wright opened the conference March 10 by telling his audience that he wants to help reverse what he believes has been “a very poor direction in energy policy” with a “common-sense pivot in energy.” 

Energy Secretary Chris Wright | CERAWeek by S&P Global

“The previous administration’s policy was focused myopically on climate change, with people as simply collateral damage,” he said to enthusiastic applause. “The Trump administration will treat climate change for what it is: a global physical phenomenon that is a side effect of building the modern world.” 

“I’m going to share two words that I do not think you have heard from a federal official in the Biden administration during the last four years, and those two words are, ‘Thank you,’” Interior Secretary Doug Burgum said during a March 12 luncheon address. 

“You had the ideas; you went into areas where people said it’s impossible to develop these resources; and you did it,” he said, basking in the friendly reception. “You continue to do it in the favor of your own government that’s done everything they can to try to slow you down — whether it’s permitting, whether it’s being supportive of organizations that bring unnecessary and unrealistic lawsuits — all in the name of a climate ideology that, in the end of the day, actually leads to having more emissions in the world, not less.” 

Calling himself a “climate realist,” Wright said, “The last administration recklessly pursued policies that were certain to drive up electricity prices, knowing full well that millions of additional Americans would have to look in their kids’ eyes and tell them that their lights might be going out. 

“We are unabashedly pursuing a policy of more American energy production and infrastructure, not less. Our goal is to reindustrialize America, not deindustrialize America.” 

The Trump administration has made no secret of its plans to build more gas plants and pipelines and increasing natural gas production along the Gulf Coast. It has moved quickly in reversing former President Joe Biden’s pause on new terminals to export LNG, signing four export approvals since the inauguration. 

At the same time, government officials have been dismantling most federal policies aimed at slowing global warming. 

Wright, a fracking executive and strong proponent of liquid fuels, said, “‘Drill, baby, drill’ also requires ‘Build, baby, build.’ To produce more, you have to have the infrastructure to move it to market.” 

Burgum chose a different maxim. “Mine, baby, mine.” 

Not surprisingly, Burgum and Wright both took shots at the renewable industry. 

Discussing the need to take advantage of the country’s vast natural resources, Burgum referred to “intermittent, unreliable sources for electricity, a.k.a. wind and solar.” 

“Everywhere [that] wind and solar penetration have increased significantly, prices went up,” Wright said, claiming U.S. electricity prices have risen by more than 20%, with only about 2% demand growth. 

In a Jan. 27 report, the U.S. Energy Information Administration said that, accounting for inflation, residential prices have remained between 16 and 18 cents/kWh since 2010. It expects U.S. retail electricity prices to average 16.8 cents/kWh in 2025, 2% more than last year but relatively unchanged after again accounting for inflation. 

“Beyond the obvious scale and cost problems, there is simply no physical way that wind, solar and batteries could replace the myriad uses of natural gas,” Wright said. “The previous administration’s climate policies have been impoverishing to our citizens, economically destructive to our businesses and politically polarizing. 

“The cure was far more destructive than the disease.” 

During a later media session March 10, NextEra Energy CEO John Ketchum, who runs a clean energy behemoth with a subsidiary that produces more renewable energy than anyone else in the world, was asked whether he agreed with Wright’s comments that wind and solar will be unable to replace natural gas. 

NextEra CEO John Ketchum | © RTO Insider LLC 

“I disagree,” he said. “First of all, we believe in all forms of energy. Not only are we the leader in renewables, but nobody operates or has developed and built more gas-fired generation in the last 20 years than NextEra. 

“However, there’s a timing difference in terms of when those generation solutions can be brought to market, and there’s a cost difference,” Ketchum said, taking care to note that NextEra has installed 175 GW of renewables, 13 GW of gas and 3 GW of nuclear over the last five years. 

“We really kind of cover the complete waterfront when it comes to the energy industry,” he said. “Renewables are ready to go right now because they’ve been up and running. When you look at gas as a solution, to get your hands on a gas turbine and to actually get it built and brought to market, you’re really looking at 2030 or later.” 

While Ketchum said NextEra’s goal is to deliver the lowest-cost options for its customers (“We don’t care if we’re selling you wind turbines or gas turbines.”), he said the industry is facing “unprecedented times” with a six-fold increase in power demand over the next 20 years, as compared to the prior 20. 

“It’s here right now, and it has to be met by something,” Ketchum said. “The issue that we’re seeing on the gas power generation side … is you have to get a long life for a gas turbine, first of all, and that gas turbine is today three times more expensive than it was just 24 months ago. 

“You also have to find the labor required to build the combined cycle facility. That’s not as easy as it once was 24 months ago because we’re building LNG terminals; we’re building oil and gas refinery expansions; we’re building data centers; and we’re building industrial manufacturing to accommodate the electrification of our economy as we’re pushing an America First agenda. 

“We have to have the generation available to meet that demand at the lowest-cost solution. Otherwise, we’re going to have a huge power affordability crisis in this country with utility bills going through the roof.” 

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MISO to Seek 3-Year Order 881 Delay for Vendor Holdups

NEW ORLEANS — MISO announced March 12 that it will ask FERC for a postponement on rolling out ambient-adjusted line ratings until December 2028.

MISO leadership told the Advisory Committee, meeting as part of MISO Board Week, that RTOs are experiencing delays from vendors supplying the necessary software for the varied line ratings required under FERC Order 881.

Some stakeholders seemed taken aback by the announcement. Clean Grid Alliance’s Beth Soholt said it was disappointing that MISO was not prepared for Order 881 when it previously said adjusted line ratings would not be a particularly heavy lift.

“It’s a consistent theme that systems are not ready to go,” Soholt said of compliance with FERC rulemakings.

Order 881 is set to go into effect for MISO on July 12.

MISO Senior Vice President Todd Hillman said the RTO is not the only grid operator requesting extra time on compliance. He said that although it is unfortunate, it is simply a reality because the country’s RTOs are vying for deliveries from a few specialized vendors to track and implement AARs.

“We’re counting on MISO for the system of the future,” Soholt said, later adding, “excuses, excuses, excuses” in response to Hillman’s explanation. Hillman and Soholt continued in a tense exchange, in which he said he felt the news of the delay was akin to disappointing his mother, to which Soholt responded that she would play the role of dissatisfied parent.

“The vendor stuff is not immaterial. There are a small number of vendors working for all the RTOs,” Hillman said. It’s worth it for MISO and its “RTO brethren” to take the time to get implementation right, he argued.

MISO said over 2022 and 2023 that it had been able to receive and use variable line ratings for about a decade, albeit on a smaller scale. (See MISO, Members Debate Deploying AARs.) At the time, MISO staff said it was up to transmission owners to determine and submit their AARs while the RTO devised an interface to accept and share hourly line ratings.

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NWPCC Considers Trump, Data Centers in Regional Power Plan

The Northwest Power and Conservation Council (NWPCC) must ensure its models consider President Donald Trump’s shifting energy priorities to ensure the council’s upcoming 20-year regional power plan stays relevant, board members contended during a March 11 meeting. 

The council is required under the Northwest Power Act “to develop a plan to ensure an adequate, efficient, economical and reliable power supply for the region.” NWPCC publishes a plan every five years, according to the council’s website.  

The plan considers several factors, including federal policies that could impact resources. During the meeting on March 11, council members noted that Trump has rescinded certain clean energy initiatives imposed under former President Joe Biden. 

For example, NWPCC’s 2021 power plan included the social cost of carbon — a measure to estimate the economic impact of climate change — to inform resource decisions. Though states like Washington still require utilities to plan with the measure, other states stopped using it after Trump issued his executive order on Unleashing American Energy, which directed federal agencies to consider getting rid of the measure (See Federal Budgets, Procurements to Include Social Cost of GHGs and DOE Official to NASEO: ‘There is not an Energy Transition’.) 

Idaho-based utilities, for example, don’t use the measure anymore, according to board member Jeffery Allen. He contended the council’s regional power plan should not apply the social cost of carbon regionwide. 

“I want what we do to be relevant. I want the council to be relevant. I want the council to be interesting,” Allen said. “If we say we’re going to do social cost of carbon regionwide, and parts of it aren’t, it kind of dings our relevancy in certain portions of the region.” 

Jennifer Light, director of power planning at NWPCC, said, “We do have a methodology where we can apply to just a portion of the region where it’s required.” 

However, board member KC Golden, who represents Washington, said NWPCC risks its relevance if it fails to address “the objective reality of our physical circumstances on the planet … because it’s wrapped around the axle of political differences between the states.” 

“These costs are not hypothetical,” Golden added. “We’re seeing them in the rise in the [Columbia River Basin] Fish and Wildlife Program. We’re seeing them … with all the utilities who are going to their commissions … or their boards and trying to figure out how to recover these wildfire costs. People are bearing the costs.” 

The council also discussed how Trump could impact clean energy tax credits. Golden said other incentives, like production and investment tax credits, should be safe from rollbacks. 

“We are in uncharted water, so I’m not going to hazard a prediction, but I just will say that these two policies in particular had a long history of bipartisan support before this administration,” Golden said. “So, it strikes me as different from some of the other clean energy policy things that are clearly going to be rolled back.” 

Load Forecast

Council staff also gave a presentation on load forecast, noting that board members will hopefully see a final forecast “sometime in April.” 

Like other entities across the country, NWPCC is paying close attention to demand growth spurred by electric vehicles and data centers.  

Steve Simmons, senior energy forecasting analyst at the council, noted that fluctuations in markets can make forecasting difficult as industries grow and disappear. He pointed to the chip manufacturing industry in Oregon and Idaho, which has existed for a while and is currently going through a large growth spurt, saying that load is not always increasing. 

“These are big jumps that you may not be able to exactly predict based on some of the economic forecasts,” Simmons said. “Also, some industries may disappear again … or they may move to a different region, and that can actually decrement load.” 

Simmons also cautioned against over-forecasting, which is a risk as stakeholders want to ensure they meet the power demand posed by industries. He pointed to the tech bubble in the early 2000s. 

“Everyone was essentially over-forecasting because someone else had over-forecast,” he added. “You end up with a bubble and then supply completely overwhelmed demand, and again it deflated, which bubbles do, but it’s often a pretty painful process.” 

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Load Growth Drives Early MTEP 25 to $11B

NEW ORLEANS — MISO’s preliminary 2025 Transmission Expansion Plan (MTEP 25) is set to become another record-breaking collection, at 434 transmission projects at an estimated cost of $11 billion.

MISO said load growth is pushing investment again.

Introducing the early version of the plan to board members March 11, MISO’s Laura Rauch said for the third consecutive year, the RTO is managing record levels of MTEP investment.

The $11 billion MTEP 25 contains $754 million in generator interconnection projects, $2.07 billion in baseline reliability projects and a whopping $8.17 billion in projects termed as “other,” which include projects needed for load growth, projects needed to replace aging infrastructure and projects needed to meet transmission owners’ reliability criteria.

Rauch said load growth is the thrust behind 61% of other category projects this year. She also said load growth likewise is propelling expedited treatment of projects.

This MTEP cycle includes $4.2 billion in developers’ expedited projects, or those projects that are needed sooner than MISO’s routine MTEP approval in December. The expedited investment this year eclipses MTEP 24’s $896 million worth of expedited requests and MTEP 23’s $684 million.

“You can’t help but having an eye pop at the expedited projects this cycle,” MISO Director Barbara Krumsiek said.

MTEP

Early MTEP 25 investment breakdown | MISO

Rauch acknowledged it’s becoming more difficult to conduct expedited reviews “when you have data centers the size of Baton Rouge.” She assured board members that MISO’s expedited review process for transmission projects does not cut corners. MISO studies expedited projects outside of its usual MTEP reliability studies to make sure the projects won’t be detrimental to the grid.

If the full MTEP 25 moves ahead, Entergy Louisiana alone would account for $3.1 billion of MTEP 25 through 14 projects. Two 500-kV projects would cost more than $1 billion apiece.

MTEP 25 will take a more definitive shape over the fall. MISO will submit the portfolio for board approval Dec. 11.

Concerns over MISO South Planning

Virginia Paschal, representing the Arkansas Advanced Energy Association, asked MISO to take a “more proactive” approach on transmission planning in MISO South at the meeting.

Paschal said MISO South risks unnecessary energy curtailments in the future without cohesive, multi-value transmission planning. She said the South’s perceived penchant for new gas plants is overblown and many in the region want more than the “piecemeal” transmission planning occurring today.

“We need transmission that maximizes economic, reliability and consumer benefits,” Paschal said. She pointed out that MISO has focused exclusively on its Midwest region in its long-range transmission planning.

At a March 12 Advisory Committee meeting, the Alliance for Affordable Energy’s Yvonne Cappel-Vickery said the number of expedited projects requested from MISO South is alarming, particularly because the projects have limited oversight. She said her Louisiana-based nonprofit joined MISO hoping for more oversight of her investor-owned utility, in an apparent reference to Entergy.

Cappel-Vickery asked for MISO assurances that the expedited projects won’t replace comprehensive transmission planning in the South region.

Senior Vice President Todd Hillman said MTEP having such a large share of expedited projects is a new phenomenon. He also said MISO seeks to provide the lowest-cost “delivered” energy, not simply the lowest-cost energy, and that transmission planning in addition to resource planning achieves lower costs.

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MISO: Better Preparations Clinched Winter Storm Operations

NEW ORLEANS — MISO emerged from winter 2024/25 without turning to emergency procedures despite wide-ranging winter storms Jan. 6-9 and Jan. 20-22. 

During the March 11 meeting of the Markets Committee of the MISO Board of Directors, RTO leadership credited relatively smooth operations to more open communication with members, market improvements and better data and modeling of risks than in past deep freezes.  

“After a quiet December, weather-wise, we had a very busy January,” Vice President of Operations Renuka Chatterjee told board members. “We always talk about how more days are going to get interesting, and here we are.”  

Chatterjee said the snow that fell over Little Rock and New Orleans in early January was unusual for the footprint.  

But Chatterjee said MISO was able to predict risks appropriately during the first bout of icy weather. She also said collaboration with members and the RTO’s risk assessment and uncertainty model shone to predict the gigawatts of market products needed during late January’s footprint-wide freeze.  

The Jan. 20-22 storm was one for the books in MISO South; the region hit an all-time, 33-GW record for wintertime demand. (See MISO South Hit Record, 33-GW Winter Peak in Jan. Storm.) The larger footprint crested at a seasonal peak of 108 GW on Jan. 22 during an average 6.5 F temperature.  

Chatterjee took a moment to reflect on how far MISO has come since the winter storms of early 2021 and late 2022. She said from Jan. 20-22, 2025, MISO experienced just $1.5 million in uplift payments to resources. That’s compared to the $49 million in uplift payments incurred during a storm lasting Feb. 15-17, 2021, and a $22 million tally from another storm Dec. 23-25, 2022.  

Chatterjee said those results happened because MISO improved its operational awareness.  

“I generally don’t believe in luck. I believe in preparation,” she said.   

Chatterjee said she heard one operator in the control room during the storm remark that he moved from feeling “little confidence in the information and high stress” as he had in past years to being confident in MISO’s information and experiencing less stress during winter storms.  

“This is a huge improvement for MISO, and it speaks to how well their processes have evolved,” Independent Market Monitor Carrie Milton said of MISO’s reduction in uplift payments. She also said MISO achieved a “very impressive” decrease in out-of-market actions in the control room to manage congestion over the winter.  

However, Milton urged MISO to trust its look-ahead commitment software more. She said on Dec. 12, 2024, the look-ahead tool recommended calling up about 20 more units than MISO operators ultimately committed. Milton said if MISO had followed the extra commitment recommendations, it might have avoided having one transmission constraint in violation for more than nine hours, which racked up $36 million in congestion costs. 

Milton also said in one February instance, MISO experienced a 30-minute contingency reserve shortage where prices temporarily shot to $1,900/MWh. She again said MISO should direct operators to be more accepting of look-ahead recommendations.  

IMM David Patton said he understood why operators might not perceive the look-ahead tool as an authority. He said the tool historically has not been as accurate as it is now, and MISO operators have long been under pressure to reduce costs and not overcommit resources. Now the tool is more precise, he said.  

“So, it’s a bit of a change in logic and process,” Patton said, adding he was confident MISO would change course and accept the tool as the default more often.  

Otherwise, the IMM reported that winter’s real-time energy prices of $41.08/MWh were 31% higher than last winter on rising gas prices. Milton said the historically low gas prices of 2024 vanished on sustained cold weather across the country.  

MISO Priming for Steep Ramping Needs

Looking ahead, MISO predicts a 99-GW peak during the spring. Chatterjee said MISO will enter the season with twice as much solar as it had last year. MISO was peaking at about 11 GW of solar in February. She said MISO likely will manage an average 9 GW in ramping needs over March, with requirements set to intensify.  

“This is going to be new for us, so I expect some lessons learned,” Chatterjee added.  

Executive Director of Markets and Grid Research DL Oates said rising operating uncertainty is an inevitability for MISO. He said MISO navigated the winter with about 200 GW of resources, including 41% gas, 24% coal and 16% wind. However, by 2043, MISO anticipates overseeing a 515-GW fleet with 18% gas, 4% coal, 35% wind and 27% solar.  

Oates said while MISO experienced an approximate 11-GW deviation between its initial forecasted needs and what generation ultimately proved necessary during the late January storm, that unknown could widen to more than 40 GW within 20 years.  

Oates said by 2043, MISO could require a net load ramp of 100 GW on a sunny day. He said on those days, new energy storage assets would need to charge during the day to be ready to discharge as the sun goes down. He also said it must ensure that reserves are deliverable on its transmission system. 

Milton said MISO already needed more than 20 GW in ramp demand Jan. 19 as the sun set, which ultimately led to higher prices and PJM furnishing imports.  

“It’s important that MISO continue the good work that they’re doing, that DL talked about,” she said.  

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NJ Pushes Ahead with EVs as Washington Pulls Back

New Jersey is forging ahead with programs that promote electric vehicle adoption, announcing incentive opportunities totaling $185 million already this year, as officials await the impact of President Donald Trump’s frequently expressed opposition to EVs. 

The New Jersey Economic Development Authority on Feb. 24 approved a new phase of the New Jersey Zero Emission Incentive program (NJ ZIP), with $75 million available for incentive grants, and launched a new program, called New Jersey Zero Emission Vehicle Financing program (NJ ZEV), with $25 million allocated. The program will provide loans of $50,000 to $500,000 for commercial or industrial enterprises purchasing one or more EVs. 

Both are supported by funding from the Regional Greenhouse Gas Initiative, as is the allocation announced in January by the New Jersey Department of Environmental Protection of $35 million to fund local government projects that replace medium- and heavy-duty (MHD) diesel trucks with electric models. 

In his budget released Feb. 25, Gov. Phil Murphy also allocated $50 million to the sixth year of the state’s Charge Up New Jersey program, funding it at the same level as last year. The program awards incentives of up to $4,000 for the purchase of lower-priced EVs. 

Even in a good environment, it is not clear whether the funding would be enough to ensure the uptake of EVs continues at pace in the state. And Trump’s frequent criticism of EVs on the campaign trail suggests that he could take significant measures to slow the adoption of EV purchases — most notably the elimination of the $7,500 tax credit for an EV purchase. 

Murphy cited the expenditure of $135 million on NJ ZIP, NJ ZEV and the MHD program in a speech announcing the budget Feb. 25, saying that “with each and every investment, like these, into New Jersey’s clean energy future, we are not only meeting our responsibility to combat climate change” but also creating jobs and boosting the economy. 

But stakeholders close to the EV sector are skeptical that the state’s efforts so far will be enough. 

Laura Perrotta, president of the New Jersey Coalition of Automotive Retailers (NJ CAR), said she believes the Murphy administration’s recent announcements are a “direct response to the uncertainty around EV policy on the federal level.” 

She noted that New Jersey EV sales are already affected by new laws and regulations enacted in 2024 that pushed up the cost of buying an EV. “Add in the uncertainty around the federal EV tax credit and tariffs on China, Canada and Mexico, which could add as much as $12,000 to an EV, and it seems both federal and state-level economic policies are making it harder for customers to purchase an EV,” she said. 

Added Purchase Expense

New Jersey’s commitment to EV adoption was highlighted March 10 by a NESCAUM announcement reporting that the state and nine others had fulfilled their 2018 pledge to put 3.3 million EVs on their roads by 2025. 

The report said that when the 10 governors made their commitment, there were only 16 EV models on the market, compared to 150 today. 

“State leadership in electric vehicles has produced incredible results in the past decade, exceeding many expectations,” Elaine O’Grady, clean transportation director for NESCAUM, said in a release. The far larger variety of EVs available is because of states’ commitment and “their market-enabling programs that helped to build the EV market that exists in the U.S. today.” 

With a goal of registering 330,000 EVs by 2025, New Jersey has more than 215,000 EVs on the road, according to recent state budget documents. The state gained momentum in 2023, adding about 62,500 vehicles for a 68% jump over the year before. 

Pam Frank, CEO of ChargEVC-NJ, which promotes the sustainable growth of the EV market, said figures released this month for 2024 are expected to show that the state added fewer EVs than in 2023. She expects the numbers to be impacted by three “unforced errors” the state imposed on the sector in 2024: the elimination of a rule that allowed EV buyers to avoid sales tax on the purchase; a four-year, $250/year fee to pay for road repairs and upgrades (a fundraising measure that for non-EVs is done by a gas tax); and the introduction in July of a new rule in the Charge Up program, which has historically been a key driver of EV adoption in the state. 

The program previously offered a maximum purchase incentive of $4,000, providing it was priced less than $45,000 — an effort to focus the incentive on lower-income buyers. In July, the state started offering the $4,000 incentive only to low- and –moderate-income buyers, and a $2,000 incentive to everyone else. (See NJ EV Incentives Target Low-income Buyers.)  

Frank said that although the recently announced dollar figures look large, most of the programs announced by New Jersey this year are a continuation of past programs, and they don’t make up for the obstacles enacted last year. 

“It’s sort of like, the left hand giveth and the right hand taketh away,” Frank said. That makes it especially hard for New Jersey’s EV sector to advance if Trump takes measures to remove federal incentives, she said.  

The state is at a delicate moment, an “inflection point,” with the era of “early adopters” coming to an end and the general market buyers getting more interested and poised to become the main purchase driving force, she said. And the state needs to give them all the encouragement it can, she said. 

Federal Support Uncertain

The state is also facing the potential loss of federal support for electric charger installations under the National Electric Vehicle Infrastructure (NEVI) program, which was enacted in November 2021, Frank said. 

The U.S. Department of Transportation on Feb. 6 sent a memo to state DOTs saying it was reviewing the program and “suspending the approval” of all planned charger installations.  

The state applied for funds late, Franks said. It was awarded $104 million to identify alternative fuel corridors, the major state and interstate highways where EV charging stations would be located every 50 miles. However, none of the charging installations have been built, she said. And the state did not move on the project’s main contract until December, when it awarded $20.96 million to Joseph M. Sanzari Inc. to build charging stations at 19 locations along state highways. 

Steve Schapiro, a spokesperson for the New Jersey Department of Transportation, said it is “reviewing whether there is any impact to the funding to” the department. 

At the DEP, spokesperson Larry Hajna said there is no impact from the memo on another project to install chargers on New Jersey highways and those of three other states, because it is not funded under the NEVI program. That project, the Clean Corridor Coalition, involves installing 450 charging ports at 24 sites along the I-95 corridor in New Jersey, Connecticut, Delaware and Maryland. (See NJ to Install 167 Heavy Truck Chargers with $250M Federal Grant.) 

Echoing Frank’s concern about changes to state incentive programs, NJ CAR’s Perrotta said Gov. Murphy should abandon the Advanced Clean Cars II rules, which require an increasing number of new car purchases to be EVs and all new light-duty vehicles sold in the state to be zero emission by 2035. (See New Jersey to Adopt Advanced Clean Cars II Rule.) 

She said the state would struggle to meet its requirements, such as one that 43% of new cars be EVs in 2026, given that only 11 to 12% of sales were EVs in 2024. 

Spurring EV Purchases

State officials believe incentive programs can help get there. The Charge Up program had by the end of January approved 49,700 incentives in New Jersey — supporting slightly less than one in four EVs registered in the state — at a total cost of $147.8 million. The program awarded 11,300 incentives in 2024, according to the Board of Public Utilities. 

NJ ZIP, which was launched in 2021, provides vouchers to support the purchase of trucks, starting at $15,000 for Class 2b vehicles and rising to $175,000 for Class 8 vehicles. It offers bonuses for low- and moderate-income buyers, applicants scrapping old diesel vehicles and school districts purchasing zero-emission buses. 

The program has committed $54.4 million in awards to 155 applications and has already supported the purchase of 134 vehicles in the state, and an additional 288 vehicle purchases are in process, according to the Economic Development Authority (EDA). 

The new NJ ZEV program is designed to complement NJ ZIP and other state incentive programs by “offering financing for vehicle costs that may not be met by NJ ZIP vouchers or other grant funding available via other sources,” EDA CEO Tim Sullivan told the agency’s board in a Feb. 24 memo. 

The program will make loans of between $50,000 and $500,000 toward the purchase of a medium- and heavy-duty vehicle that help cover the funding gap for an EV. The funds can be spent on the purchase — but not on taxes, registration fees, operating expenses and charging or fueling equipment — for EVs or hydrogen fuel cell EVs. 

Announcing the new funding for the two programs, Murphy said they would “drive us forward in our mission of decarbonizing transportation, reducing consumer costs and responding to market preferences.” 

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SERC Projects Shrinking Margins in Next Decade

Soaring electricity demand across the SERC Reliability footprint is squeezing the region’s reserve margins, with more than half of SERC’s subregions expected to fall below NERC’s 15% reference margin in the coming decade, the regional entity said in its Long-Term Reliability Assessment released March 11.

SERC publishes its LTRA each year as a companion to NERC’s LTRA — which is published the preceding December —  and as a tool for industry, regulators and policymakers “to support the decision-making necessary to ensure the reliability of the [grid] during the planning horizon.”

The RE gathered, independently validated and verified data from all SERC entities to develop the report, while also conducting a stakeholder review process in collaboration with industry experts.

This year’s report covers the years 2024-2034, based on data on generation and transmission resources, planned outages and demand projections on an hourly basis. SERC staff considered historical weather events, system outages, load levels in peak and off-peak scenarios, and generating resource levels.

Current peak demand in the region is 260 GW in summer and 251 GW in winter, according to the assessment. These figures are projected to grow by 48 GW and 41 GW over the next 10 years, respectively, representing an overall compound annual growth rate of 1.7% in the summer months and 1.5% in the winter months. This calculation is based on a 50/50 projection, meaning that there is a 50% chance the actual load will be lower or higher than the forecast.

The subregion with the highest predicted CAGR is SERC-PJM, with 5.19% and 4.63%. The subregion contains parts of Virginia, North Carolina and Kentucky.

SERC-MISO Central, which includes all or parts of Illinois, Iowa, Kentucky and Missouri, has the lowest predicted CAGR with 0.20% and 0.13%.

To meet this demand, total generating capacity for the summer months is expected to grow from 315.3 GW in 2024 to 332.1 GW in 2034. However, winter generating capacity is projected to fall over the same period from 318 GW to 312.9 GW.

The decline in winter capacity is largely due to the expected retirement of nearly 18 GW of coal generation, causing coal to fall from 20% of on-peak winter capacity to 14%. Most other generation types are projected to shrink slightly or grow; natural gas should grow from 157.3 GW in 2024 to 165.4 GW summer capacity in 2034, and solar generation is expected to nearly double, from 22.8 GW to 41.7 GW in summer across the SERC footprint.

However, SERC noted that the expansion of solar does not provide equal benefits from season to season. While solar as a share of summer generation is expected to rise from 7% to 13%, its share of winter capacity is projected to grow from 3% to just 5%. The report acknowledged that solar’s variability and “lack of essential reliability services makes it less than a one-for-one replacement for the retiring coal capacity.”

Sounding the Alarm

With demand rising faster than generating capacity, many of SERC’s subregions are expected to fall below NERC’s reference margin in the coming decade, the RE said. This represents a significant shift from last year’s LTRA, when only SERC MISO-Central was expected to show such a decline. (See SERC Highlights DERs, Extreme Weather Challenges in LTRA.)

In this year’s report, SERC MISO-South, SERC-PJM and SERC-East all show sub-15% anticipated reference margins in either summer or winter, or both, for at least part of the decade. SERC-PJM has the highest projected deficiency at -22% for winter and -12% for summer.

MISO-South is also expected to hit negative margins in both summer and winter in 2033 and 2034, while MISO-Central will have negative summer margins in 2024 and 2025 before rising above 0% in 2026. SERC noted that the MISO and PJM subregions can both draw on resources from the greater MISO and PJM footprints.

The RE called the falling margins a “marked deterioration and a trend that bears watching,” and urged grid planners to carefully coordinate the retirement of existing resources with the introduction of new ones. SERC also said regulators and policymakers “should pay close attention to whether proposed retirements shown in integrated resource plans will be replaced in time to meet projected load without falling below reference margins.”

“A key purpose of forward-looking reports like this is to sound the alarm early enough so that something can be done while there is still time to take meaningful action,” SERC said. “SERC looks forward to working with federal and state policy makers and regulators, SERC registered entities and … technical committees and working groups to continue to identify, understand and address reliability and security concerns across the SERC region.”