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March 18, 2025

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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 (D) also allocated $50 million to the sixth year of the state’s Charge Up New Jersey program, funding it at the same level as in 2024. 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 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. 

Stakeholders close to the EV sector are skeptical 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 already are 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 historically has 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 also faces 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 already has 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 due largely 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 also is 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 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.”

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Ford Suspends Ontario Electricity Tariff as Trump Wavers

Ontario Premier Doug Ford on March 11 said he would suspend the 25% tariff on electricity exports to the U.S., issued the day before, after speaking with Commerce Secretary Howard Lutnick and receiving threats of additional tariffs by President Donald Trump. (See Ontario Premier Ford Slaps 25% Tariffs on Power Exports to US.) 

In a post on X, Ford and Lutnick said they would meet in D.C. on March 13 “to discuss a renewed” United States-Mexico-Canada Agreement. The two said they “had a productive conversation about the economic relationship between the United States and Canada.” 

The statement came several hours after Trump posted a message on his own social media site, Truth Social, saying he had instructed Lutnick to impose an additional 25% tariff on steel and aluminum imports from Canada in retaliation to Ford’s action, on top of a blanket 25% tariff on all such imports set to go into effect at midnight March 12. 

Trump made a series of other threats, such as “declaring a National Emergency on electricity within the threatened area” and increasing a tariff on imported vehicles April 2. 

“The only thing that makes sense is for Canada to become our cherished 51st state,” the president wrote. “The artificial line of separation drawn many years ago will finally disappear, and we will have the safest and most beautiful nation anywhere in the world — and your brilliant anthem, ‘O Canada,’ will continue to play, but now representing a GREAT and POWERFUL STATE within the greatest nation that the world has ever seen!” 

Later, Trump posted another, shorter message, asking, “Why would our country allow another country to supply us with electricity, even for a small area? Who made these decisions, and why? And can you imagine Canada stooping so low as to use ELECTRICITY, that so affects the life of innocent people, as a bargaining chip and threat? They will pay a financial price for this so big that it will be read about in history books for many years to come!” 

Asked on MSNBC about his reaction to Trump’s threats, Ford said, “We will not back down; we will be relentless. I apologize to the American people that President Trump decided to have an unprovoked attack on our country … but we need the American people to speak up. We need those CEOs to get actually get a backbone and stand in front of him and tell him this is going to be a disaster. It’s mass chaos right now.” 

Later that day, Trump backed off his threat to up the steel and aluminum tariff for Canada, according to White House Deputy Press Secretary Kush Desai. “President Trump has once again used the leverage of the American economy, which is the best and biggest in the world, to deliver a win for the American people,” he said, adding that the blanket tariff was still scheduled to go into effect. 

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ACEEE Recommends Winter Discounts to Spur Heat Pump Adoption

Setting a lower price for power in the winter is key to ensuring that consumers’ overall energy bills do not go up when they switch to heat pumps, according to a report released March 11 by the American Council for an Energy-Efficient Economy.

“We know that heat pumps cut climate pollution and can reduce home energy costs, even in the coldest states,” ACEEE Buildings Program Director and co-author Matt Malinowski said in a statement. “Utilities, regulators and policymakers need to further reduce costs by encouraging heat pump-friendly electric rates and energy-efficiency upgrades, especially for low- and moderate-income households.”

The discounted winter rate is vital in states with high electric rates and in cold regions where the economics of heat pumps can be the most challenging. Generally, maintaining the grid is more costly in the summer than in the winter, so ACEEE said flat seasonal rates effectively overcharge in the cold months.

Other changes that can help boost heat pump adoption are efficiency upgrades like insulation, so homes need less heat, and adopting time-of-use rates, the study said.

The report modeled bills using actual utility rates under different home heating electrification scenarios, specifically picking from among the most expensive for electrification. The models in the report were based on single homes in Colorado, Connecticut, Maine and Minnesota.

“In any cold-climate U.S. state, the ongoing bills are lowest with cold-climate heat pumps when heat pump adoption is accompanied by energy efficiency home envelope improvements and a favorable electricity rate plan,” the report said. “Heat pump-specific rate plans are best for incentivizing heat pump adoption, with winter discounts being a potentially important facet of those plans. These rates are generally based on the cost of service for heat pump customers, without subsidizing other customer classes.”

In Maine, all of the options studied led to no increases in bills when the modeling added a heat pump because the increased efficiency was enough to offset higher electric rates. Electrification increases costs in some months of the year but leads to lower overall bills.

Minnesota has an even bigger gap between electricity and gas costs, but one utility offers a 35% discount winter rate for customers using electricity for heat so adopting heat pumps leads to lower costs year-round for its customers.

The Colorado utility the study looked into offers a 10% winter heating discount — not enough to make heat pumps cheaper on their own, though time-of-use rates that the utility offers also would help cut costs.

In Connecticut, the study found that fuel oil and propane customers (representing 45% of residential customers in the simulation set) can save money through electrification, but the price ratio between gas and electricity was so high that even a discount like Minnesota’s and efficiency upgrades still would not fully make up the difference in costs.

“Here, as in other states where electricity is much more expensive than gas, the state should consider deep public investment (not ratepayer-funded) in making electric power more affordable to its residents,” the paper said. “This could include taking on some costs of grid maintenance and upgrades, putting a price on carbon or implementing clean heat standards that place performance requirements on all heating market actors. Fortunately, this type of electricity-gas price ratio is rare, and gas prices are expected to naturally increase in the coming years relative to electricity.”

Rates are not the only thing presenting roadblocks to heat pump adoption, with the report saying the biggest barrier is lack of awareness, which means that ongoing marketing/educational campaigns are needed.

Another challenge is that some HVAC contractors have misperceptions about the technology’s efficiency and costs. The report recommends better training around heat pumps in the HVAC industry, providing incentives to contractors and encouraging them to focus on maximizing homeowner satisfaction over getting jobs done quickly.

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OSW Critics Petition US Supreme Court for Vineyard Wind 1 Review

Commercial fishing advocates who have been fighting Vineyard Wind 1 for years are asking the nation’s highest court to do what lower courts have not: Rule that federal regulators improperly authorized construction of the 800-MW wind farm off the Massachusetts coast. 

The Responsible Offshore Development Alliance’s petition was docketed by the U.S. Supreme Court on March 10. Statistically, it is a long shot — the justices hear fewer than 100 of the thousands of appeals submitted each year. 

But if the petition is successful, defense of the regulatory decisions (which were made under President Biden, a strong offshore wind supporter) would fall to the Trump administration, which has taken firm steps to limit or block offshore wind development. 

The Texas Public Policy Foundation filed a similar petition to the Supreme Court on March 11 in a similar case that had been consolidated in U.S. District Court with RODA’s challenge. 

The shift from strong support to strong opposition between the two administrations has created a new element of risk and uncertainty for an industry that already was struggling to maintain momentum in the United States.  

Interior Secretary Doug Burgum offered some clarity March 6, when he told Bloomberg that while all offshore wind projects would be reviewed, in accordance with the executive order, advanced projects would be reviewed differently than early stage projects. 

Burgum also echoed Trump’s criticisms that offshore wind is too expensive and cannot serve as a baseload. 

In the challenge it began in January 2022, RODA asserts that the U.S. Interior Department under Biden reinterpreted Section 1337 of the Outer Continental Shelf Lands Act to “consider” the impacts of offshore wind projects rather than “ensure” they do not interfere with reasonable uses such as use of the sea or seabed for a fishery. 

Vineyard Wind 1 in 2021 became the first offshore wind proposal green-lighted in federal waters, and RODA said it set the precedent for the 10 other records of decision that followed, all of which were favorable. 

A district court rejected that line of attack (1:22-cv-11172). In December 2024, the U.S. Court of Appeals for the First Circuit denied RODA’s request to appeal the District Court’s ruling. 

“Petitioning the SCOTUS is the only option left to ensure American seafood harvesters, and the US wild-caught sustainable seafood industry, are not put out of business at the hands of those who want to turn our oceans into a massive web of industrial power plants,” RODA said March 10 in announcing its petition to the Supreme Court. 

The petition seems to acknowledge that the opportunity to block Vineyard Wind 1 has passed, as roughly three-quarters of its planned turbines are at least partly built. But it seeks to inform future projects: 

“Petitioner asks this court to grant review of this issue of vital importance to the fishing industry and to provide guidance to the secretary [of the Interior] regarding the correct statutory interpretation of ‘shall ensure’ in Section 1337(p)(4) so that future ocean energy projects are reviewed according to the criteria provided by Congress.” 

Texas Public Policy Foundation senior attorney Ted Hadzi-Antich said in a March 11 news release: “This is a stark example of federal administrative agencies shirking their responsibilities to follow the law. When that happens, we are here to hold their feet to the fire.” 

Even without a Supreme Court ruling, the U.S. offshore wind sector is struggling, both from the effects of Trump’s directives and from an array of financial and supply chain problems that set in long before the 2024 presidential election. 

Some recent examples: 

    • Major offshore wind developer RWE, which in November announced a two-year pause in its U.S. efforts, filed notice March 7 that it would lay off 73 employees in Massachusetts. 
    • RWE’s vice president of East Coast offshore development, Amanda Lefton, departed the company to become the acting commissioner of New York’s Department of Environmental Conservation. 
    • SouthCoast Wind’s developers are preparing for a potential delay of up to four years on the project off the Massachusetts coast. 
    • New Jersey canceled its next offshore wind solicitation in February after two bidders pulled out and a third lost one of its project partners. 
    • New Jersey stepped up its review of potential alternative uses for the wind port it has invested more than a half-billion dollars to build but has yet to use for offshore wind construction. 
    • Developers booked new impairments on projects planned along the East Coast. 

There are bright spots: 

    • New York state told NetZero Insider recently that work continues on its most recent offshore wind solicitation, which targeted the first quarter of 2025 for finalization of contracts. 
    • Massachusetts did not provide NetZero Insider with an update on its most recent solicitation, but power purchase agreements are due to be finalized by March 31.  
    • Coastal Virginia Offshore Wind is under construction, albeit at a higher cost. 
    • Revolution Wind is under construction off the Massachusetts coast, albeit at a higher cost and with a delayed commercial operation date. 
    • Onshore construction is underway for Empire Offshore Wind in New York, where developer Equinor is building an offshore wind port for over $850 million. On March 11, Empire submitted its request to the state Public Service Commission to proceed with the next phase of its onshore substation construction. 
    • And, of course, construction of Vineyard Wind 1 is far along, though well behind its original schedule after some problems with components. 
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CARB Work Seeks to Surmount Challenges to Calif. Hydrogen Goals

Consultants are evaluating four primary pathways for hydrogen production in California, and they say it’s too soon to eliminate any of them from a long-term strategy for the state’s green hydrogen industry. 

Energy and Environmental Economics (E3) is studying the hydrogen production pathways as part of a California Air Resources Board report. The consultants presented initial findings from their analysis during a Feb. 25 CARB workshop. 

E3’s analysis focuses on four hydrogen production methods: electrolysis of water using zero-carbon power, steam reformation of methane, methane pyrolysis and biomass gasification. The pathways were chosen based on their relatively high level of technology readiness, according to Vignesh Venugopal, senior managing consultant at E3. 

The steam reformation and pyrolysis pathways use methane as a feedstock: either fossil-gas methane or biomethane, which may come from landfill gas, dairy production, organic waste or wastewater treatment. Carbon capture and storage also is evaluated for methods that produce carbon emissions. 

E3 found that electrolysis using solar power theoretically could meet California’s 2045 hydrogen demand, which is estimated at 1.6 million metric tons (MT) in CARB’s 2022 climate change scoping plan. 

But the resources required for doing so could be a constraint, Venugopal said. About 812 square kilometers of land would be needed for alkaline electrolysis, mainly for solar installations, E3 estimated. That’s more than six times the land area of San Francisco County, which measures 120 square kilometers.  

About 72 billion liters of water would be required to meet the 2045 hydrogen demand with alkaline electrolysis, as well as 85 TWh of electricity, which is 28% of California’s current total electricity demand of about 300 TWh. 

The land use impacts of electrolysis along with other factors “warrant consideration of other pathways,” according to E3. 

“An optimal [hydrogen production] strategy may involve multiple pathways to mitigate impacts and bring benefits to the state,” Venugopal said. 

E3’s final analysis will include more details on resource requirements for other hydrogen production pathways.  

Meeting Climate Goals

CARB is developing the hydrogen report in response to Senate Bill 1075 of 2022, which states that the legislature’s intent is to develop “a leading green hydrogen industry in California” to realize energy benefits and help meet the state’s climate goals. California has set a goal of net-zero greenhouse gas emissions by 2045. 

SB 1075 notes that technological advances may be needed — in addition to scaling up production — to produce hydrogen from renewable feedstock for $1 per kilogram. That’s a target set by the U.S. Department of Energy in its Hydrogen Energy Earthshot, an initiative launched during the Biden administration. 

The E3 analysis looked at the cost of producing hydrogen using different pathways and making various assumptions. 

With electrolysis, the hydrogen production cost in 2045 could be as low as $1 per kilogram, according to E3. That assumes less expensive electrolyzers from China are paired with low-cost solar energy. 

The cost of electrolytic hydrogen rises to over $4 per kg with the use of more expensive, American-made electrolyzers powered by a new nuclear reactor. 

For hydrogen produced using steam methane reformation, projected 2045 costs range from $2 to $10 per kg based on the price of natural gas or renewable natural gas (RNG) used. RNG can be costly, depending on its source. Venugopal noted. The high end of the cost range also assumes carbon capture is part of the process. 

The cost of natural gas or RNG also is a key factor for hydrogen produced through pyrolysis, which has a cost range of $2 to $14 per kg. In pyrolysis, methane is heated in the absence of oxygen to produce hydrogen and solid carbon. The lower production cost figures in the E3 study assume the solid carbon byproduct can be sold. 

Gasification uses heat, steam and oxygen to convert biomass to hydrogen and other products without combustion. E3 estimated the cost to produce hydrogen by this method as ranging from $1.7 to $5 per kg, based on the cost of biomass used and whether carbon capture is deployed. Sources of biomass include forest residue, crop residue and urban wood waste. 

Venugopal noted that “a wide range of uncertainty exists” regarding the cost to produce hydrogen in the different pathways. 

“There is meaningful overlap between the cost from each pathway, which suggests it is too soon to pick one single pathway based on cost alone,” he said. 

Report Timeline

CARB is accepting comments on the hydrogen workshop through March 18. 

E3 will continue its analysis, addressing additional topics including the impacts on clean air objectives, barriers to hydrogen use and policy recommendations. The consultant expects to complete the analysis in the third quarter of 2025. 

CARB expects to release a draft version of its hydrogen report by the end of 2025, accept public comments and then issue a final report in early 2026. 

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PJM PC/TEAC Briefs: March 4, 2025

Planning Committee

PJM Presents Changes to DESTF Issue Charge

PJM’s Chen Lu on March 4 presented the Planning Committee with a draft amendment to the Deactivation Enhancement Senior Task Force’s (DESTF) issue charge to add a key work activity (KWA) focused on creating pro forma language for reliability-must-run agreements with generation owners seeking to deactivate a unit identified as being necessary for reliability.

The new language seeks a proposal that would be effective for the 2028/29 delivery year, which is the tail end for a temporary measure allowing some resources operating on RMR agreements to be counted as capacity if they meet certain requirements (ER25-682). Approved by FERC in February, the temporary change allows resources that PJM believes can act as capacity to be counted in the supply stack for the 2026/27 and subsequent Base Residual Auction. (See FERC OKs Changes to PJM Capacity Market to Cushion Consumer Impacts.)

While PJM will ask the Markets and Reliability Committee to vote on the changes during its March 19 meeting, Lu brought the language to the PC, Market Implementation Committee and Operating Committee during their March meetings to provide stakeholders with advance notice.

Paul Sotkiewicz, president of E-Cubed Policy Associates, asked Lu why PJM had reversed its earlier position that RMR agreements should be out-of-scope for the DESTF. He stated that RMR agreements are different from other areas the task force has focused on because they are specific to transmission security, not market design.

Lu responded that there are relevant issues around RMR agreements, such as the operational parameters needed to maintain reliability and on the markets side what is needed to count those resources as capacity. PJM believed a senior task force was the best forum rather than a standing committee.

Speaking during the MIC meeting March 5, Philip Sussler, of the Maryland Office of People’s Counsel, and Clara Summers, of the Illinois Citizens Utility Board, questioned whether the added work item would impact the ability for the task force to proceed with KWAs exploring alternatives to RMRs, an addition to the issue charge the two consumer advocates sought to have included in 2024. (See “Stakeholders Approve Generation Deactivation Issue Charge,” PJM MRC/MC Briefs: Sept. 20, 2023.)

Other work areas include education on alternatives to rebuilding transmission assets when generation deactivations would trigger reliability violations, such as reconductoring or the deployment of grid-enhancing technologies; developing alternatives to RMR agreements; and accounting for any changes stakeholders and the RTO may make to its capacity interconnection rights transfer process.

Transmission Expansion Advisory Committee

Market Efficiency

PJM’s Nicolae Dumitriu presented the Transmission Expansion Advisory Committee with an update on the RTO’s 2024/25 long-term market efficiency window.

The congestion drivers behind the analysis were identified through base cases pairing the 2024 load forecast with the expected grid topology in 2029 and 2032. An additional sensitivity was included examining how increased load identified in the 2025 forecast could impact the 2029 case to allow PJM to right-size the solutions built on the two base cases.

The inclusion of the 2024 Regional Transmission Expansion Plan (RTEP) Window 1 slate of grid updates mitigated 13 constraint overloads that prevented the market efficiency analysis from being able to calculate interface limits, in addition to reducing congestion on several lines. The remaining congestion is largely located along the PJM/MISO border. PJM also included planned resources sorted into the fast-track study queue and those with suspended interconnection service agreements (ISAs) to the analysis to allow it to meet the expected 17.8% reserve requirement.

The preliminary congestion drivers identified include the 138-kV Museville-Smith Mountain line in the AEP zone, which has $39.7 million of congestion in the 2029 base case and $51.5 million in the 2032 case; the 115-kV West Point-Lanexa line in the Dominion zone, which has $1.2 million of congestion in 2029 and $1.3 million in 2032; and the 115-kV Garrett-Garrett Tap line in the APS zone, which has $1.8 million in 2029 and $2.4 million in 2032.

PJM’s Nicholas Rodak said the next step is finalizing additional sensitivities and the models for the 2025, 2029, 2032 and 2035 simulated years.

Tightening Supply and Demand Impacting RTEP Planning

PJM’s Wenzheng Qiu presented stakeholders with an update on the assumptions being developed for the 2025 RTEP analysis, which includes an expectation that existing generation and planned resources with signed ISAs will not be sufficient to meet loads in 2030.

Window 1 will include the 2025 load forecast, which includes 16 GW of growth in 2030 above the prior year’s forecast.

The five-year analysis of the balance between load and generation finds that peak loads could be met with the addition of projects with suspended ISAs, fast-lane queue projects, the Chesterfield Energy Reliability Center planned in Virginia and the Coastal Virginia Offshore Wind project, albeit with a loss-of-load expectation of 1.6 days per year. If the 2,308 MW of offshore wind planned in New Jersey and 255 MW in Delaware are not completed, the LOLE would increase to two days per year, 20 times higher than the one-in-10 benchmark.

If all those projects are included in the seven-year base case, Qiu said the 2032 LOLE would be 2.3 days per year. The seven-year case is being included in the analysis to identify projects that could be right sized for long-term needs.

PJM’s Sami Abdulsalam said resources with suspended ISAs and fast-lane projects are being included in the RTEP analysis to allow the amount of available generation to meet peak loads. The point of interconnection for those projects is being set at the nearest bus at 500-kV or higher to avoid impacts to lower-voltage facilities. The seven-year case also includes all projects being studied in Transition Cycle 1 and 2, which will also be modeled on the high-voltage backbone network.

Responding to stakeholder questions on how any network upgrades required for those generation projects will interact with the RTEP needs, Abdulsalam said the seven-year case will inform the solutions chosen to resolve the five-year needs. Not all network upgrades expected to be completed in the latter analysis will be included in the five-year case, so any such upgrades would be removed.

Supplemental Projects

FirstEnergy presented two projects in the ATSI zone to address transmission overloads and congestion identified in MISO’s Long-Range Transmission Planning process (LRTP) and support projects in the 2024 MISO Transmission Expansion Plan.

The first would construct a 20-mile optical fiber line between the Lemoyne and Toledo Edison substations and replace line relaying at Lemoyne at a $15.6 million cost. The second would install 7 miles of fiber from Toledo Edison to the Lallendorf substation, where line relaying would also be replaced, at a $5.9 million cost. The overall $40 million project is in the conceptual phase with a projected in-service date of June 1, 2032.

FirstEnergy also presented three projects to replace transformers in the JCPL zone for maintenance issues and the infrastructure approaching the end of its useful life. The 230/115-kV Whippany transformer No. 12 is about 66 years old and has had problems with leaking oil and nitrogen gas; the unit, associated relaying and substation conductor would be replaced at a $8.1 million cost, with an in-service date of March 7, 2030.

The 230/34.5-kV Chester transformer No. 4 is nearly 46 years old and has been reading elevated ethane gas in its oil. Replacing the transformer, a 230-kV circuit switcher, 34.5-kV breaker and limiting terminal components would cost $7.3 million with an in-service date of Dec. 31, 2029. The 230/34.5-kV Chester No. 1 would also be replaced, as it was installed about 60 years ago and there are signs of degrading insulation. Its replacement would cost $7.3 million, which includes a 34.5-kV breaker and limiting terminal components.

FirstEnergy presented a $12 million project to replace the control building at its Glade substation in the Penelec zone. The building is 56 years old and degrading, with rusting walls and broken windows. Several line ratings are also limited by terminal equipment. Several other components of the substation would also be replaced, including: four disconnect switches, two 230-kV breakers, and substation conductor and the line trap on the 230-kV Lewis Run-Warren line. Substation conductor and terminal equipment would also be replaced at the utility’s Warren and Lewis Run substations. The project is in the conceptual phase with a projected in-service date of Dec. 17, 2027.

American Electric Power presented a $173 million project in its zone to connect LRTP Tranche 2 projects to the PJM grid. While the full cost would be assigned to MISO customers, there could be impacts to the PJM grid, so AEP determined to submit them as supplemental projects to be studied for any transmission violations. No “large-scale issues” have been determined, AEP said.

The Sorenson substation would be reconfigured to terminal two new 765-kV lines to the Greentown and Lulu facilities, and four new 345-kV lines would be terminated at the Sullivan substation, with two running each to Fairbanks and Dresser.

Several lines would also be modified to cut into new substations:

    • the 765-kV Sullivan-Rockport line would cut into a new Pike County substation;
    • the 765-kV Jefferson-Greentown and 345-kV Tanners Creek-Hanna lines would both cut into the Gwynneville substation;
    • the planned 345-kV Gwynneville-Tanners Creek line would cut into the existing Batesville substation;
    • the 345-kV Fall Creek-Sunnyside line would cut into a new Madison County substation; and
    • the double-circuit, 345-kV Olive-University Park and Olive-Green Acres lines would cut into the 345-kV Babcock substation.

Exelon presented a $874.2 million project to extend two 765-kV lines from ComEd’s Collins substation, which would also be expanded, to interconnect with projects in MISO’s Tranche 2.1 portfolio. All costs associated with the project would be allocated to MISO.

A new 765-kV Woodford County substation would be built in the MISO grid as part of the project, which would cut into ComEd’s 345-kV Powerton-Katydid and Powerton-Nevada lines. Two 300-MVAR line reactors would be installed at Collins, along with associated circuit breakers for each new line.

Exelon also presented a $40 million project in the ComEd zone to construct a new 345-kV substation, named Eldamain, to serve a new customer bringing 600 MW to the area of its Plano substation. The new facility would be cut into the 345-kV LaSalle-Plano line with 0.4 miles of new double-circuit line. The project is in the engineering phase with a projected in-service date of June 1, 2029.

Dominion Energy presented a $30.6 million project to rebuild 10.3 miles of its 230-kV Shawboro-Elizabeth City line as it approaches its end of life, having been built with wooden H-frames in 1975. The project is in the engineering phase with an estimated in-service date on Aug. 31, 2025.

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PJM MIC Briefs: March 5, 2025

Offer Capping Resources with Advance Commitments

VALLEY FORGE, Pa. — The PJM Market Implementation Committee endorsed by acclamation an RTO-sponsored issue charge to consider changes to how resources committed in advance of the day-ahead market are offer capped. 

Out-of-market commitments have taken on extra significance in recent months as PJM acted ahead of winter storms to schedule additional resources it believed would be necessary to maintain transmission security but had been identified as being at risk of not being able to perform on short notice. That often took the form of resources with limited ramping capability and gas generators that could have difficulty procuring fuel. (See PJM: ‘Conservative Operations’ Maintained Reliability During Jan. 2024 Storm.)  

The first phase of the issue charge envisions governing document revisions on the scheduling practices of resources committed before the day-ahead market is run and how they may be offer capped; market power mitigation for those resources also is included. The second phase focuses on adding language fuel expenses in the cost-based offers for units with advance commitments. 

The issue charge was revised during the meeting to consider how advanced commitments can impact uplift payments, spell out the timeline for the two phases and designate the Reserve Certainty Senior Task Force (RCSTF) as the forum to coordinate the discussions. 

Responding to stakeholder questions regarding whether the issue charge seeks to formalize a practice of making out-of-market commitments on holiday weekends, PJM’s Phil D’Antonio said staff plan to discuss the approach operators will take in greater depth at the RCSTF. The next task force meeting is March 12 and is set to include discussion of how winter storms impacted “operations and market outcomes.” 

Adrien Ford, director of wholesale market development for Constellation Energy, said the company would abstain from the vote because it does not support PJM taking out-of-market actions. Instead, she said stakeholders’ focus should be on getting the markets right so these actions don’t have to be taken. Constellation did not vote in opposition because she said it believes if PJM is going to continue the practice, there should be rules in place governing how operators act. 

Paul Sotkiewicz, president of E-Cubed Policy Associates, said PJM should hold a special session to discuss the intersection of all the issues related to how the gas and electric markets interact. Otherwise, he said, this proposal and the other disparate stakeholder efforts will not yield comprehensive results. “These are really crucial issues from an operational and markets standpoint.” 

PJM Director of Stakeholder Affairs Dave Anders said the RTO has a desire to move forward on phase 1 quickly and that he believes the issues Sotkiewicz raised pertain to phase 2. He suggested the RCSTF could provide a venue to discuss those issues. 

“I think that is directly in the wheelhouse of the RCSTF,” Anders said. “I get this idea of wanting a holistic review of everything in one spot and trying to figure out where that is in the manuals. A senior task force is the best place for that to happen.” 

Periodic Review of Manual 11 Deferred

Stakeholders delayed voting on revisions to Manual 11: Energy & Ancillary Services Market Operations following uncertainty around the implications of designating data centers as “plug load.” 

The language was drafted through the periodic review of the manual, which resulted in changes that PJM’s Joseph Tutino said were mainly typographical. 

Independent Market Monitor Joe Bowring questioned why data centers should be sorted alongside household appliances like washing machines. 

“Data centers are obviously a key issue, and considering them as a regular plug-in load doesn’t seem like the answer,” he said. 

PJM’s Maria Belenky said data centers are considered plug load for the purpose of curtailment service providers (CSPs) reporting load enrolled in demand response. The manual does not contain specific guidance for how that load should be categorized, and while it may not be the perfect approach, she said it reflects ongoing practice. 

“It is something that is currently done, and it’s to provide appropriate guidance for CSPs,” she said. 

First Read on Proposal to Overhaul Uplift

PJM and the Monitor presented a joint proposal to rework how the RTO determines when a unit is following dispatch and the process for assigning corresponding uplift payments or deviation charges. (See PJM Stakeholders Mixed on Uplift Proposal.) 

PJM’s Lisa Morelli said the changes seek to resolve an issue where resources instructed to ramp down instead could keep their output flat and nonetheless receive uplift payments. That is because the dispatch signals are ramp-limited and the balancing operating reserve (BOR) credit structure considers only whether a market seller followed dispatch for individual five-minute intervals. She gave an example of a unit operating at 100 MW being dispatched down to 95 MW in accordance with its ramp rate. If that unit ignored the signal and stayed at 100 MW, it would not exceed the 10% margin that defines when a unit is deviating from dispatch. Additionally, because dispatch is limited by ramp rates in the next interval, PJM could bring it down only to 95 MW again.   

The proposal would establish a Tracking Ramp Limited Desired MW (TRLD) metric that follows what a unit’s output would have been if it had followed dispatch over time. In Morelli’s example, the TRLD would continue to fall by an additional 5 MW for every interval that dispatchers sought less energy from the resource. 

The TRLD would replace the ramp-limited desired, dispatch and LMP-desired metrics currently used in the BOR credit and deviation formulas, which would seek to make resources whole to the costs they incurred with uplift limited by the output they were instructed to produce based on the TRLD metric. 

Morelli said the status quo formula is overly complex and would be simplified by calculating the BOR credits a resource would receive under the lesser of the TRLD and its actual real-time output. This also would remove punitive impacts that market sellers could experience when asymmetric inputs are used in the current formula. 

The proposal also would revise the start and end points for uplift eligibility to correspond with when a resource’s commitment began and the end of its commitment or minimum run time. 

Joel Romero Luna, a market analyst with the Monitor, said eligibility for BOR credits is defined according to the subjective phrase “operating as requested by PJM,” which has been interpreted differently by the Monitor and RTO. The Monitor’s position is that one is either eligible to receive uplift when it follows dispatch or not eligible if it does not follow instructions. 

Tom Hyzinski, of GT Power Group, questioned whether a market seller that changes its parameters to reflect changes in a resource’s flexibility would be held to the original or updated values. 

Romero Luna said the proposal changes how a resource that changes the flexibility of its parameters by more than 5% is treated to be dispatched according to its ramp-limited signal, instead of the LMP-desired signal that is not ramp limited. The economic minimum and maximum parameters would remain based on the original parameters at the time of commitment, while the ramp rate and offer parameters would be based on any updates the market seller makes. If a unit submits flexible parameters, but becomes inflexible and does not update, it would be penalized for not following dispatch. 

Implementation of the proposal would be phased to start with simulated settlement results being provided to market participants in late 2025 so they can become familiar with how the changes function, with rollout affected actual settlements around a year later. 

The MIC is scheduled to vote on the changes April 2, followed by the Markets and Reliability Committee on June 18 and the Members Committee on July 23. Morelli said the proposal would require tariff revisions, which might take long enough to draft to not be finalized by the time the MRC is asked to endorse the package. In that case, a special meeting for a page turn or a second vote may be sought.