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 51 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.
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.
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.
Prysmian canceled its plans to build an offshore wind cable factory in Massachusetts.
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.
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.
The Government Accountability Office said the Biden administration’s approval of California’s plan to end the sale of gasoline-only vehicles by 2035 is not subject to review and potential repeal by Congress.
In February, the EPA sent the approval to Congress saying it was considered a rule under the Congressional Review Act. The GAO said the decision should be considered an order and is not reviewable.
California’s rules require 35% of vehicles in the 2026 model year to be a zero-emission model before rising to 68% by 2030.
The United States is withdrawing from the Just Energy Transition Partnership, a collaboration between richer nations to help developing countries transition from coal to cleaner energy, sources in participating countries said.
The coalition, which consists of 10 donor nations, was first unveiled at the U.N. climate talks in Glasgow, Scotland in 2021.The U.S. State Department did not respond to a request for comment.
BLM Approves Newcastle Geothermal Development Project
The Bureau of Land Management has approved the Newcastle Geothermal Development project in Utah.The plant is expected to generate up to 20 MW near Newcastle in Iron County.
Sunnova Energy International says former COO Paul Mathews has been appointed president and CEO, effective immediately.Mathews joined Sunnova in January 2023. Prior to that, he spent nearly two decades serving in a variety of leadership roles at UPS.Mathews succeeds William Berger, who is stepping down as chairman, president and CEO.
Alliant Energy announced the appointment of Patrick Allen as the new independent board chair, effective following the company’s Annual Meeting of Shareowners in May.Allen has been a member of Alliant’s board since 2011.He will succeed John Larsen, who will retire.
German energy company RWE Offshore Wind Services plans to lay off 73 employees from its Boston-based U.S. offshore wind arm, according to state filings.Company spokesperson Ryan Ferguson said the layoffs, which will come by May 6, will affect workers supporting the long-term development of offshore wind projects across the country.
Alabama Power has announced plans to develop the first utility-scale battery energy storage system (BESS) project in the state.The 150-MW Gorgas BESS will be installed at the site of the retired Plant Gorgas power station in Walker County and will cover seven acres.Construction is set to begin this year, with commercial operations planned by 2027.
Los Angeles County said it will sue Southern California Edison, alleging the utility’s equipment sparked the Eaton Fire.The lawsuit seeks to recover costs and damages sustained from the fire. Costs and damage estimates were expected to total hundreds of millions of dollars, the county said, adding that assessments were ongoing. The blaze destroyed more than 9,400 structures and killed 17 people in the Altadena area.
House Committee Advances Bill to Block CO2 Pipelines from Eminent Domain
The House Judiciary Committee advanced bills to block liquid pipelines carrying carbon dioxide from the use of eminent domain.
One bill specifies that the “construction of hazardous liquid pipelines for the transportation or transmission of liquefied carbon dioxide” does not constitute a public use for the purpose of condemning agricultural land. The bill would apply to any condemnation proceedings made on or after its enactment. Another bill would restrict liquid pipelines from the right of eminent domain.
A companion bill in the Senate has not had any scheduled hearings and will likely be dead.
Louisville Gas & Electric and Kentucky Utilities requested approval for a Certificate of Convenience and Necessity from the Public Service Commission for two natural gas plants and a battery energy storage system (BESS).
The two 645-MW natural gas plants would supply additional generation at the E.W. Brown Generating Station. The companies expect to have the units available in 2030 and 2031.
The companies also plan to install 400 MW of BESS at the Cane Run Generating Station and a selective catalytic reduction facility to reduce nitrogen oxide emissions for Ghent Unit 2. These are expected to be operational in 2028.
Xcel Energy Proposes $318M in Refunds to Customers
Xcel Energy officials propose returning $318 million to customers.According to a news release, more than half of the refund ($176 million) comes from federal tax credits for nuclear energy generation, with the remainder would come from lower fuel costs and a 2011 outage at the Sherco coal plant.The refunds, which would total $81 for the average residential customer, must be approved by the Public Utilities Commission.
Bill to Allow Community Solar Projects Clears Senate
The Senate has passed a proposal to establish a legal framework for community solar power projects.If the proposal passes the Legislature, it will allow a solar developer to build a solar array between 50 kW and 5 MW and sell shares of the generation to subscribers. It also would require the Public Service Commission to come up with a framework for pricing the electricity generated.
Canada-based crypto mining company Bitfarms said it’s acquiring two coal-fired power plants to power its bitcoin mining operations.
Bitfarms is set to buy Stronghold Digital Mining in a deal expected to close this month. Stronghold owns the 85-MW Scrubgrass waste plant in Venango County and the 80-MW Panther Creek waste facility in Carbon County.
Bitfarms already has a presence in the state, having purchased a data center in Mercer County last year.
Carrier to Credit Ratepayers in Fraud Case Settlement
The Public Utilities Commission approved a settlement that will have Rhode Island Energy credit ratepayers $7.9 million for an alleged fraud scheme by its predecessor, National Grid.
In December 2021, the PUC discovered that National Grid knowingly misfiled invoices for its energy efficiency program over an eight-year period to make more money, overcharging customers as much as $2.2 million. National Grid acknowledged in a 2023 report that company employees “acted inappropriately” by deliberately delaying invoices.
Under the settlement, Rhode Island Energy will credit customers using its storm contingency fund, reducing future storm-related costs.
Gov. Rhoden Signs Eminent Domain Ban for Carbon Pipelines
Gov. Larry Rhoden signed a bill banning the use of eminent domain for carbon dioxide pipelines.
The issue has been at the center of a contentious debate over Summit Carbon Solutions’ proposed $9 billion carbon capture pipeline. The project would transport carbon dioxide from ethanol plants in five states, including South Dakota, to an underground storage site in North Dakota.
In a letter explaining his decision, Rhoden emphasized his commitment to property rights and framed the bill as a way to restore trust between landowners and developers.
Dominion Seeks SCC Approval for Chesterfield Gas-fired Units
Dominion Energy said it is seeking State Corporation Commission approval of its $1.47 billion project to install four natural gas-fired generating units at its Chesterfield Power Station.
The four units would generate 944 MW and would run at times of peak demand.The project would add an average of $1.36 to the residential monthly bill and would vary year-to-year.
FirstEnergy Planning to Replace Coal Plants with Natural Gas
FirstEnergy announced during its fourth quarter earnings call there are plans to shut down two Mon Power coal plants in favor of natural gas.The Harrison plant in Harrison County and the Fort Martin plant in Monongalia County are scheduled to shut down within the next 15 years, while the replacement natural gas facilities are expected to begin construction within the next five years.
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.
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.
DENVER — The Trump administration, pending ERCOT market changes, the future of wind power generation and uses for artificial intelligence were recurrent themes at Yes Energy’s annual summit, EMPOWER 25, held March 5-7. Here’s some of what we heard.
Trump Administration Shakes Things up
Former FERC Chair Pat Wood III, CEO of Hunt Energy Network, was among the speakers expressing concern over President Donald Trump’s first few weeks in office.
“There’s a lot of things I like about the last six weeks, but some that I don’t, like taking treasured institutions and kind of hitting a wrecking ball to them. FERC is one of those,” he said. “I think FERC will be fine. I’ve seen the statements of the new chairman there being pretty supportive of being able to work all this out, and yet I know some quality people are leaving the organization, and I do worry about the loss of that institutional knowledge that has really made markets work seamlessly and work more effortlessly than they probably should have, because you had the right people there.”
Sonya Gustafson, general manager of data services for Equilibrium Energy, which uses AI to optimize energy portfolios, said she is concerned over the potential loss of data compiled by EPA, the Energy Information Administration and other federal agencies.
“One of my biggest challenges is access to as much information as possible; that allows us to create accurate renewable energy forecasts,” she said. “The threat of that going away does create a little bit of nervousness. We’re fortunate in that for weather, we can go potentially to European models, but at the same time, it does create a shift in our businesses. So that’s been top of mind recently: making sure I’m archiving as much as possible and finding secondary and third sources for a lot of the information we need to fully optimize.”
“The uncertainty is really high right now,” said Emma Konet, CTO of Tierra Climate, a marketplace for grid-scale batteries to sell carbon offsets to corporate buyers. “I think developers with projects in various stages of the interconnection queue are now a little bit uncertain about what the [investment tax credit] is going to look like — and maybe it’s going away.”
She said although falling battery costs have driven a lot of battery deployment in California and ERCOT, the ITC will be needed for widespread deployment in MISO and SPP. “So I definitely think that’s a risk.”
Cliff Rose, senior product manager for Yes Energy (left), moderated an EMPOWER 25 panel on power market dynamics impacting asset development with Ryan Hakim, Cordelio Power. | Yes Energy
Leah Kaffine, senior director of integrated energy systems planning for Pattern Energy Group, which operates wind, solar, transmission and energy storage projects, expressed concern over the fate of the Inflation Reduction Act and the Department of Energy. “Pattern Energy, as a developer of transmission … we hope that maybe that will be spared,” she said.
Independent consultant Evan Bixby, former vice president of strategy and analytics for Pine Gate Renewables, said he is concerned over tariffs and supply chain risks. “Just the overall attitude of the federal government towards renewables is a little bit threatening,” he said. “I’m very confident in the renewable energy industry. It’s weathered storms before, and it’s a very creative, very passionate, very driven industry. So, [I’m] confident that we will be able to figure it out. But that doesn’t mean that there won’t be headwinds.”
Anticipating ERCOT Market Changes
ERCOT’s real-time co-optimization and battery project (RTC+B), set to go live in December, was mentioned at the conference frequently.
“We’re in a little bit of purgatory right now,” said Drew Peine, vice president commercial for Hunt Energy Network, which is building energy storage in ERCOT.
“We’re going into this kind of unknown with RTC+B. You’ve got the day-ahead markets that are going to be financial, both energy and ancillary products, and then you’ve got that five-minute optimization on top of it. ERCOT is writing the rules as we speak. [It is] a little bit frustrating that we don’t have all the rules right now [that] we need to start, but we’re participating in that process with our regulatory team trying to understand what ASDC [ancillary service demand curve] is, first of all, and then what it means for our optimization. And … we need to be there on that Day 1.” (See ERCOT TAC Opens Discussion on Proposed RTC Changes.)
Gustafson predicted an “exciting” first couple months. “Whenever there’s new products launched, there’s more volatility. Later on, we may see slightly more depressed prices, but I’m excited for the first three or four months.”
Also on the power market dynamics panel were (left to right) Judd Rogers, Scout Clean Energy; Evan Bixby, Bixby Analytics; and Leah Kaffine, Pattern Energy Group. | Yes Energy
“A lot of people, I don’t think, fully appreciate how dynamic this market’s going to be, and they’re going to be kind of stuck in their old ways,” Peine added.
“What’s really interesting is, once we get to real-time optimization, they have nothing to train on. We have no real-time price data for ancillary services,” Konet said. “So, I think that’s going to be a really interesting dynamic.”
Uses of Artificial Intelligence
AI isn’t just driving data center growth, speakers said. It’s also taking an increasing role in the work lives of power professionals.
“I think I spend more time talking to ChatGPT than to any human in my life right now,” Gustafson said. “It’s an awesome platform to learn, and it’s something that I use every day when I’m developing code. It makes me faster.”
“Asset optimization has been around forever. But I think where AI and [machine learning] and these kind of neural net type models can really come in is in the inputs to those optimizations,” Konet said.
Peine said AI will become increasingly important. “The amount of data that we consume is phenomenal; I just cannot believe how much data we consume on a daily basis,” he said.
Jesse Carver, Yes Energy (left), moderated a panel on batteries in evolving markets with (from left): Emma Konet, Tierra Climate; Sonya Gustafson, Equilibrium Energy; and Drew Peine, Hunt Energy Network. | Yes Energy
Peter Kelly-Detwiler, co-founder of NorthBridge Energy Partners, said he uses Perplexity AI regularly — but still reads 44 newsletters, up from 42 with the recent addition of two on data centers.
“People have told me, ‘Why the heck do you read 42 newsletters — now 44 — and scan all that instead of teaching an AI tool to give you what you need?’ My answer is, I don’t trust yet that I’m going to ask it the right things to look for. And so much of my learning is still accidental.
“When I used to go into a library, the book that I was looking for was not the one that was usually the most valuable to me. It was next to it in the stack, in the adjacencies. And I still enjoy the accidental adjacency, because that’s when I find so many of the things I didn’t know were going to be valuable to me. And I’m afraid of taking my AI lens and making it so narrow that I build biases into it that exclude the broader world that I need to look at, especially for the data that’s going to come slamming into my head and destroy a paradigm that I thought I knew. I love when that happens.”
Future of Wind Generation
Wind development has fallen way behind solar in generation growth, but it will remain an important player, speakers said.
According to EIA, a record 30 GW of utility-scale solar was added to the U.S. grid in 2024, 61% of all capacity additions. Battery storage also hit a record last year, adding 10.3 GW. EIA predicts an additional 32.5 GW of utility-scale solar and 18.2 GW of utility-scale battery storage in 2025.
By contrast, wind added only 5.1 GW last year, the smallest amount since 2014, with slightly more (7.7 GW) expected in 2025.
“Wind is a lot harder to develop,” said Ryan Hakim, vice president of commercial and corporate strategy for independent power producer Cordelio Power. “You need a lot of acreage. … There’s a lot of things that can kind of go wrong. But if you are able to take a project to completion, there is quite a lot of demand for that product just because … it profiles generally the opposite of solar.”
“One of the reasons why we don’t see as much wind development is there’s a lot of sites that have been picked over,” he added. “But another thing to consider is, we’ve got more technology where you can build bigger turbines, higher towers; where you’re able to extract some of the wind in places where you previously hadn’t. And so I think there’s new regions that are also opening up.”
“Solar and batteries pretty quickly saturate themselves, whereas wind diversification as a species will always be highly valued,” agreed Kaffine. “And I think, yeah, people find it refreshing and different.”
“You can’t do it all with just one technology,” Bixby said. “You can’t do it all with solar and batteries. [You] probably could, but you need to overbuild by a lot. So you need wind in there. … You’ll need advanced geothermal. You’ll need new types of battery storage technology. You’ll need advanced controls to be able to manage all of it [and] new market mechanisms to pay for it.”
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