NEW ORLEANS — MISO confirmed it’s taking steps to get answers from FERC about the role the Independent Market Monitor should have — if any — in transmission planning.
During March Board Week, MISO Director Trip Doggett said the board was put in a tough position, with some members agreeing the IMM should monitor transmission expansion from an independent perspective and others vehemently opposed to the Monitor critiquing MISO’s planning in addition to market operations.
MISO board members on Feb. 14 ultimately passed a motion directing MISO to ask FERC whether it’s appropriate for the IMM to analyze the value of proposed transmission. In the meantime, MISO is to freeze any funding for independent scrutiny of transmission planning by the IMM until MISO gets clarity. (See Board Orders MISO to Get Answers on IMM’s Role in Tx Planning.)
The board drew up the motion following IMM David Patton’s vocal opposition to MISO’s nearly $22 billion long-range transmission portfolio over 2024.
“We felt like being responsible for the budget, we really couldn’t let the IMM continue until we have clarification,” Doggett explained at the March 11 Markets Committee of the MISO Board of Directors.
During a March 12 Advisory Committee meeting, MISO counsel Jacob Krause said MISO would pose the question to FERC sometime in the second quarter. MISO may file a petition for a declaratory order with FERC; the RTO has not confirmed that’s the route it will take.
Attorney Ken Stark, representing MISO’s end-use customers, said he found MISO’s intent to file problematic. Some state regulatory staff also have expressed concern over the appearance of MISO effectively shutting the IMM out of planning discussions for the time being.
During a March 13 MISO board meeting, Organization of MISO States President and Minnesota Public Utilities Commissioner Joseph Sullivan said a few regulators have strong opinions about MISO temporarily withholding funding. He said OMS is following developments closely.
“We have agreed to disagree on that topic,” MISO Board Chair Todd Raba said, though he added MISO was working with FERC and the IMM to draft a filing.
Patton did not comment on the future filing over the course of Board Week, though in the past he’s said repeatedly that markets and transmission planning cannot be viewed in isolation because of their interdependence.
At a Feb. 25 OMS board meeting, Wisconsin Public Service Commissioner Marcus Hawkins said it was “surprising how the process played out,” with MISO leading the charge to stop payments to the IMM on transmission planning assessments. He pointed out that states and MISO are free to disagree with the Monitor’s independent views.
“[It] seems ironic that the only time that MISO has ever brought this up is when the IMM disagrees with its transmission planning,” said Bill Booth, consultant to the Mississippi Public Service Commission. He questioned whether MISO was trying to “silence” its IMM.
NEW ORLEANS — FERC Commissioner Judy Chang delivered remarks on the importance of meeting ballooning load at MISO Board Week.
Chang, who made an unscheduled appearance March 13, said the pace and size of recent load growth could “threaten the reliability of our grid.”
“We have to meet this event. We have no choice,” she told MISO leadership and members.
Chang said she’s focused on solving load growth collaboratively, competitively and within the markets. She said she would “take very seriously the cost issue affecting ratepayers” while ensuring necessary infrastructure can be built.
Chang characterized ever-increasing load as an opportunity, while warning it might come with “a lot of headaches.”
She also called MISO’s regional transmission planning process “a model for the rest of the country” and a cornerstone to meeting the needs of the coming decade.
“Thank you for being a leader in this area,” she said.
“We’re seeing significant load growth in the South and up into the Midwest in our footprint,” MISO CEO John Bear said following Chang’s brief remarks.
Bear said MISO’s yearlong pause in long-range transmission planning to recalibrate its 20-year planning futures is necessary to contemplate the effect load growth will have on the footprint and how transmission needs might escalate. (See MISO Aims for 4 New Tx Planning Futures in 9 Months.)
During a March 12 strategy update, Senior Vice President Todd Hillman said MISO is concerned primarily with the pace of generation coming online and going offline in the footprint combined with the unprecedented load growth.
Hillman said MISO expects its solar fleet to double every year from now until 2028, when it predicts it will have 41.7 GW of panels. He noted that nameplate solar capacity already has doubled since the beginning of winter, when it was 6 GW.
Hillman said that dominant renewable energy mix could leave MISO with ramping needs as high as 100 GW on some days by 2044. Over that time frame, MISO could experience anywhere from 1.6 to 2.7% compound load growth annually.
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 often are “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 because of 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 available only 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 previously hasn’t 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 then must 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 also were 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.
In a series of announcements March 12, EPA Administrator Lee Zeldin began 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 stated 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 repeatedly has 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 also were 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.”
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 normally would 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 then will 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 still were “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 also said “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 still is “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.
HOUSTON — Two members of President Donald Trump’s cabinet swept through CERAWeek by S&P Global to cheer on attendees with provocative 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 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 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.
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.”
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.
“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, noting that the industry has installed 175 GW of renewables, 13 GW of gas and 3 GW of nuclear over the last five years. NextEra’s generation portfolio has 72 GW of renewables, gas and nuclear.
“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.”
NEW ORLEANS — MISO announced March 12 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 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 simply is 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.
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.
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 hopefully will 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 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.”
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.
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.
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.
