Bipartisan leaders of the Senate Environment and Public Works Committee want to pass energy infrastructure permitting legislation, but a Jan. 28 hearing on the subject showed how that might not happen during this Congress.
Senators, including EPW Ranking Member Sheldon Whitehouse (D-R.I.) and leaders from the Energy and Natural Resources Committee, have been working on potential legislation for the past year, but are trailing House colleagues who passed a bill late in 2025 that would alter the National Environmental Policy Act to speed up permitting. (See House Passes SPEED Act to Quicken Infrastructure Permitting.)
“I’d like to begin by thanking my colleagues who are here with me, and in particular, Ranking Member Whitehouse, for their drive to elevate problems in our current permitting regime and to work constructively together,” EPW Chair Shelley Moore Capito (R-W.Va.) said at the start of the hearing. “That’s what we need to do.”
“It’s the never-ending story on permitting, but we’re going to get into that story — I hope,” Moore Capito said.
Any bill needs to be bipartisan to be durable, she said before Whitehouse made his opening remarks, saying he shared that goal but thinks there is a “trust problem” with the Trump administration. He cited the president’s executive orders that temporarily stopped the Empire offshore wind project.
“This all stank, but I remained willing to work on a permitting bill,” Whitehouse said. “In August, stop-work Trump struck again against Revolution Wind off Rhode Island, a project over 80% complete with $4 billion invested, based on supposed national security concerns. That order was instantly thrown out in court as arbitrary and capricious, in part because the Trump administration had been making the opposite arguments about that same project in the same courthouse just weeks earlier.”
Other actions against clean energy continued through 2025.
“So, Sen. Heinrich [D-N.M.] and I have paused permitting reform negotiations,” Whitehouse said. “Let me be clear: We find no fault with Senate Republicans.”
The conflict is entirely between the legislative and executive branches of the government, according to Whitehouse, who said the Trump administration’s “lawless” attacks on clean energy loom over every other industry. The executive can resuscitate the bill’s prospects if it shows it will stop putting up roadblocks to clean energy, Whitehouse said.
The Solar Energy Industries Association is not focused on reforming NEPA, which the SPEED Act and any Senate proposal from EPW would do, because the law is rarely used in litigation against solar projects, said SEIA CEO Abigail Ross Hopper, who said “permitting is essential.”
“SEIA strongly supports these bipartisan efforts to improve the process for energy and transmission projects,” she said. “Permitting reform must begin with this basic principle: Projects that enter the federal permitting process must be allowed to move through that process in good faith and without unfair treatment based on energy source. And once a project receives a permit, that permit should be honored.”
The solar and battery developers that SEIA represents have run into issues with the Trump administration since a July 2025 Department of the Interior memo created “68 new layers of red tape” for their projects, she added. By requiring secretarial approvals on many easy decisions, it effectively amounts to a moratorium on solar.
The bureaucratic roadblocks are endangering 70 GW of solar and 42 GW of battery storage on both federal and private land,” Ross Hopper said. Together they represent 43% of all planned new capacity in the U.S.
“We all know electricity demand is rising rapidly, and without this power and the grid infrastructure to deliver it, electricity prices will continue to rise,” she said.
Sen. Ed Markey (D-Mass.) noted that the tactics being used against solar now could be wielded against the oil and gas industry in the future by a Democratic president. He entered a memo into the record from Evergreen Action laying out how to get that done.
“This administration must be forced to end its punitive treatment through clear legislative text and vocal Republican opposition to any efforts to violate the law,” Markey said.
After Markey’s turn on the mic, Sen. Cynthia Lummis (R-Wyo.) responded that previous administrations from his party had done the same kind of thing against infrastructure they disliked.
“Mr. Markey, we feel your pain. We could take your statement and where you said left — we could put right,” Lummis said. “Where you said right, we could put left. Where you said Trump, we could put Biden.”
One of the first things former President Joe Biden did when taking office in 2021 was to stop construction on the Keystone XL pipeline, she added. Markey countered that Trump has taken more such actions before Chair Moore Capito reminded him it was Lummis’ time to speak.
The way Maryland Del. Lorig Charkoudian (D) sees it, working with other Mid-Atlantic states to study the costs and benefits of withdrawing from PJM is, at this point, the only responsible thing to do.
“PJM is frustratingly slow in changing, if changing at all [and] continues ─ even in a reliability crisis of their own making ─ to double down on their love affair with fossil fuels … at a really significant cost to our ratepayers. And so, you reach a point where it’s almost irresponsible not to say, ‘What are the other options?’”
Charkoudian was speaking during a recent legislative update call hosted by the Maryland Clean Energy Center (MCEC), where she previewed a package of bills she is sponsoring during the current legislative session, including H.B. 143, calling for the state to work with neighboring PJM states to study possible alternatives.
For example, the states ─ Maryland, Delaware, New Jersey, Pennsylvania and maybe Virginia ─ could start their own RTO or use PJM’s fixed resource requirement (FRR) “to pull ourselves out of the capacity auction,” she said.
Going the FRR route would require utilities in the states to procure their own capacity, rather than relying on PJM’s increasingly expensive capacity auctions, and H.B. 143 also would require Maryland utilities to study the costs and benefits of ensuring they could provide at least 80% of their capacity.
“The idea is to explore doing more capacity procurement through bilateral contracts and then use the PJM auction” as backup, Charkoudian said in an email to Livewire.
The Maryland General Assembly kicked off its 2026 session Jan. 14, and as far as energy policy is concerned, Charkoudian predicts “an adventurous year … [with] a lot of moving parts.”
Like Gov. Wes Moore’s Lower Cost and Local Power Act ─ announced Jan. 27 ─ which could actually tie the state more firmly to PJM by requiring all utilities to join the RTO. The bill has yet to be formally introduced, but a one-page summary argues that having all the state’s utilities in PJM ─ including small municipal utilities that generally have lower rates than investor-owned utilities ─ would lower electric bills.
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The state’s largest utilities ─ Baltimore Gas and Electric, Pepco Maryland and Delmarva Power, all IOUs owned by Exelon ─ already are members, as is the Southern Maryland Electric Cooperative. (See below for more details about the governor’s bill.)
So, the 90-day legislative session ahead is shaping up as a case study in how states facing explosive demand growth will attempt to build more clean energy, cut electric bills and reduce greenhouse gas emissions as PJM and the Trump administration resist any change that puts more solar, wind and storage online.
Maryland aims for 100% carbon-free power by 2035 but imports 40% of its electricity from the regional grid, making it particularly dependent on PJM’s mostly fossil-fueled power and vulnerable to any swings in the RTO’s market prices. The state’s consumers already are absorbing rate increases due to PJM’s price-spiking capacity auctions, and more pain is ahead with the December auction, for 2027/28, hitting yet another record high, $333.44/MW-day, up from $28.92/MW-day in 2023.
“It’s very easy to get caught up in all the drama around energy right now,” Charkoudian said during the MCEC call. “[But} we have, for the most part, all of the tools that we need, and we need to put them together in the right policy.”
Charkoudian vs. Moore
The politics of the upcoming midterm elections also are a key factor ─ Moore and all state lawmakers are running for re-election in November ─ affecting what new energy policies can be shepherded through the legislature and reach Moore’s desk.
Both the governor and Charkoudian want to get more clean energy online in Maryland, to help wean the state off its dependence on PJM and provide support for local installers, developers and consumers in the absence of federal incentives cut off by the Republicans’ One Big Beautiful Bill Act.
The 30% federal tax credit for residential solar was terminated Dec. 31, 2025. Commercial projects still can qualify for the credit if they start construction by July 4, 2026, and are online by the end of 2027.
The one-page summary of Moore’s bill says it will “create a process for clean energy projects to apply for financing for shovel-ready projects,” which, on the face of it, could primarily benefit utility-scale projects. (Residential and smaller commercial projects are rarely described as “shovel-ready.”)
In contrast, Charkoudian’s Affordable Solar Act (H.B. 345) lays out a detailed plan for Maryland to adopt incentives similar to New Jersey’s, providing different levels of financial support for different kinds of solar ─ utility-scale, commercial, community solar and residential.
Incentives for utility-scale projects would be determined through a competitive auction, with the lowest-cost projects receiving incentives, while the state’s Public Service Commission would set the price for solar renewable energy certificates (SRECs) for residential, community solar and commercial projects under 5 MW.
The PSC would review and adjust the SREC price every three years, or more frequently if warranted by market conditions. Right now, the SREC price in New Jersey has been set at $85/MWh. Maryland SRECs are priced around $50, according to Flett Exchange, an online SREC trading platform.
New Jersey’s utility-scale auctions got off to a rocky start, with the state’s Board of Public Utilities rejecting all the bids in the first solicitation in 2023, saying they were too high. A second auction in 2024 awarded incentives to eight utility-scale projects totaling 310 MW.
Charkoudian described her proposed incentives as the “best bang for the buck from a ratepayer side, from a Maryland side. … We’re going to provide as much subsidy as is needed, but not a penny more, to each different sector of the industry.”
The bill also would make plug-in “balcony solar” legal in Maryland ─ a significant win for cutting home electric bills ─ and ensure that ratepayer dollars intended for the state’s clean energy fund cannot be used to fill holes in the state budget. Moore wants to take $292 million from the fund ─ the Strategic Energy Investment Fund (SEIF) ─ to backfill a 2027 deficit estimated at close to $1.5 billion.
ATTs and Grid Expansion
Both Moore and Charkoudian are bullish on advanced transmission technologies, which can optimize and expand capacity on existing power lines, as a cheaper, faster alternative to building new transmission.
Moore’s bill calls on utilities “to prioritize [ATTs] to expand existing grid capacity and authorize the use of state and interstate highway corridors to co-locate these projects.”
Again, Charkoudian provides a more detailed approach in H.B. 40. Utilities or other transmission owners within the state would be required to identify areas where grid congestion has occurred in the past three years, as well as where congestion may be likely to occur over the next five years, and then develop plans for using ATTs as part of any grid upgrades or expansion.
Developers seeking a certificate of public convenience and necessity for transmission projects also would have to show they’ve considered ATTs as an alternative to building a new line.
Charkoudian acknowledged that implementing the law could be tricky due to the fine line between state and federal regulation of new transmission. But she sees ATTs providing both grid efficiency and affordability.
An additional problem here is the slipperiness of legislative language. Any effort to get utilities to prioritize or consider new technologies tends to lead to highly technical arguments about why said technologies are not appropriate or feasible for any one project or situation. Compensation is another potential roadblock since upgrading wires with ATTs may be considered a maintenance cost that cannot be passed on to a utility’s customers ─ that is, in many places, ATTs cannot be rate-based.
Moore’s bill acknowledges that ATTs must be part of a bigger grid expansion strategy. The governor wants the Department of Transportation to use $10 million from the SEIF “to identify opportunities for high-voltage transmission lines and battery storage projects along state and interstate highways.”
The focus on existing rights-of-ways could be a potential vote winner for the governor in the face of the well-organized and vehement local opposition to the Maryland Piedmont Reliability Project ─ a 70-mile transmission line approved by PJM, which could run through agricultural land in the central part of the state. The fact that the project is being built by an out-of-state utility, Public Service Enterprise Group of New Jersey, has intensified community outrage.
High Bills and Data Centers
Differences between Moore and Charkoudian are more pronounced when we get to the nitty-gritty of high electric bills and data centers.
Besides taking $292 million from the SEIF to balance the budget, Moore also wants to use $100 million for direct bill rebates to “Maryland families burdened by high energy costs” ─ yet another major vote winner. Both those withdrawals will leave the fund with a balance of about $164 million, according to an analysis by Inside Climate News.
What the governor doesn’t mention is that in 2025, more than $94 million in SEIF dollars went to state programs providing bill assistance to more than 70,000 low-income families, according to the Maryland Energy Administration’s 2025 report on the fund. Projected spending for bill assistance programs in 2026 is $150 million. Whether Moore’s rebates would go to upper-income households that really do not need them is unclear.
While Moore’s bill is mum on data centers, the governor signed onto President Donald Trump’s recent proposal that PJM hold a one-time emergency auction to deliver more long-term “baseload” power for data centers across its service territory ─ wording that assumes a traditional reliance on fossil fuels and nuclear.
Charkoudian tackles the data center dilemma in in her fourth bill, which proposes multiple strategies ─ and a preference for clean energy ─ to protect consumers from paying for any new generation or power lines needed to connect these megawatt-guzzling facilities to the grid.
The bill is being finalized, but according to a fact sheet from Charkoudian’s office, the core provisions include:
Accelerated permitting and interconnection for new data centers or other large loads that supply 100% of their power.
A voluntary demand response program for large load customers ─ defined as any facility with a demand of 25 MW or more.
An inventory of surplus interconnection capacity in the state, conducted by the Maryland Energy Administration. The information gathered by MEA “will be shared with large load customers who can then use this surplus interconnection to build new battery storage or other zero-emission resources to avoid having to go through the PJM queue,” according to a fact sheet on the bill.
A requirement for all new large load customers seeking interconnection in Maryland to cover the capacity for at least 25% of their power demand with either behind-the-meter resources, storage or carbon-free power.
A community benefit fee of $1,000/MW to be paid by any large load project applying for interconnection in Maryland. The fee would cover the cost of interconnection studies and be used to provide consumers with assistance for high utility bills and energy-efficient home upgrades.
Both Moore and Charkoudian appear to be moving in the same direction, tackling critical challenges for the state ─ in this case, how to develop a reliable, affordable electric power system with growing amounts of clean energy, an optimized, flexible grid and various pathways for data centers and other large loads to get the power they need.
Charkoudian tends to go big, ambitious and strategic on the bills she introduces, while Moore is smart, but perhaps a bit more cautious, with an eye on the election and Maryland’s mix of liberal and more conservative voters. Pressure from the White House, PJM, utilities and hyperscalers will be intense.
The challenge ahead for both will be getting their bills through a legislature that, even with a large Democratic majority, leans toward consensus, watering down more liberal bills with cuts, rewrites and amendments ─ or letting them die in committee.
In other words, the fate of clean energy, data centers and utility bills in Maryland and other PJM states will depend on the difficult, frustrating but absolutely vital process of making laws in a democratic society, with a free, independent press looking on. Thank goodness, in Maryland, we still have both.
Cybersecurity firm Dragos has blamed Electrum, a threat group linked to Russia’s intelligence service, for a Dec. 29 cyberattack against Poland’s power grid that it said could be a preview of future attempts to compromise critical infrastructure.
The attack occurred Dec. 29 and 30, according to a government statement published Jan. 15, and targeted a system for managing renewable energy sources as well as two combined heat and power plants. Polish Prime Minister Donald Tusk said that “at no point was critical infrastructure threatened,” and no outages occurred as a result of the attack. However, he said, the incident showed Poland’s energy system “requires further strengthening.”
In a report published Jan. 27, Dragos said it was called in by CERT Polska, Poland’s cyber incident response team, to analyze “one of the numerous incidents across the Polish system that are part of this attack.” The firm called the event “the first major coordinated attack targeting distributed energy resources at scale” and said it can “assess with moderate confidence that … Electrum is responsible.”
Electrum is associated with Unit 74455 of Russia’s Main Directorate of the General Staff of the Armed Forces (also known as GRU). Analysts have also dubbed the unit Sandworm and Voodoo Bear, though these may be separate groups within the unit. Unit 74455 is believed to have carried out attacks around the world, including against the Ukrainian grid in 2015 and 2017. (See Six Russians Charged for Ukraine Cyberattacks.)
In its 2024 Year in Review report, Dragos called Electrum one of three active threat groups capable of reaching Stage 2 of SANS Institute’s ICS Kill Chain, meaning “a capability that can meaningfully attack” a target’s industrial control systems. (See Dragos: Attacks on ICS Increased in 2024.)
The December cyberattack targeted systems managing communication and control between grid operators and DERs, meaning both CHP facilities and systems for dispatching renewable energy, Dragos wrote. Through these tactics, the attackers were able to “gain access to operational technology systems with direct connections to generation assets.”
“Taking over these devices requires capabilities beyond simply understanding their technical flaws. It requires knowledge of their specific implementation,” the firm wrote. “The adversaries demonstrated this by successfully compromising [remote terminal units] at multiple sites, suggesting they had mapped common configurations and operational patterns to exploit systematically.”
Although communication was lost, the default behavior of the affected devices was to remain on; this is why no outage occurred. Dragos wrote that because of limited logging of network communications and commands at the affected sites, investigators have not determined whether Electrum tried to issue operational commands to the generation assets.
The firm warned that the Poland attack could indicate a change in adversaries’ tactics to target DER monitoring and control systems. Attackers gained a “foothold that could enable operational impacts, particularly when similar access is achieved across larger numbers of sites simultaneously or if adversaries develop deeper knowledge of specific site configurations.”
Historically, cyberattacks against power grids have required targeting substations or centralized systems, Dragos wrote, citing the Ukraine grid attacks in 2015 and 2016, which involved “large, centralized control points that manage significant portions of the grid.” The global shift from large generation facilities to smaller distributed facilities has opened new attack vectors, leading the firm to warn that “as your DER portfolio grows, so does the attack surface.”
Grid operators don’t just have more points of vulnerability to worry about with DERs; renewable generation facilities also lack the inertia that traditional thermal plants provide, which helps stabilize grid frequency. More than 50% of Poland’s generation fleet is coal-fired plants, Dragos observed, with wind and solar accounting for about 25% of capacity.
The firm suggested the relatively high amount of inertial generation, coupled with strong AC interconnections to neighboring countries, made the attack “unlikely to cause a nationwide blackout in Poland.” But this built-in stability is not guaranteed, the firm warned, particularly in countries pursuing aggressive decarbonization strategies.
Dragos wrote that the Poland attack “represents both continuity and evolution.” Continuity comes from the technical similarities with previous Electrum operations, including the choice of targets and the malware used. The evolution is represented by the change to target “the distributed edge of the grid,” meaning communication systems that enable the compromise of “dozens of smaller generation sites.”
Based on the attackers’ behavior, the firm judged the incident to have been opportunistic rather than “precisely planned … with specific outcomes.” Dragos wrote that Electrum seems to have “exploited whatever opportunities their access provided.” This indicates that the attackers were rushed, but the firm could not determine why.
From direct evidence and public statements, Dragos is certain of at least 12 sites that were affected, and the firm believes the actual total may be at least twice this number, representing as much as 1.2 GW if they had been operating at full capacity. Poland reported record electric consumption of 30 GW on Jan. 17, meaning that if the affected sites had gone down simultaneously and without warning, it could have had a “noticeable impact on the system frequency [of the kind that] have caused cascading failures in other electrical systems.”
Operational technology/ICS incident response: Organizations must have a plan to prioritize restoring connectivity across dozens of sites at once, performing forensics on corrupted systems and detecting the level of control that attackers achieved.
Defensible architecture: Companies should work to prevent adversaries using common weaknesses to easily compromise multiple sites at once.
OT/ICS network visibility and monitoring: Distributed generation operators must ensure they have constant visibility into their systems and the ability to detect abnormal activity.
Secure remote access: Organizations must ensure remote access is protected through multifactor authentication, automatically expiring logins and other security measures.
Risk-based vulnerability management: Companies should be aware of vulnerabilities in distributed generation assets and enable rapid patching across all remote sites.
SPP staff say they still are waiting for an order from FERC before they can begin distributing millions of dollars in compensation to transmission upgrade sponsors from its beleaguered Attachment Z2 process and unwinding billions of dollars in settlements.
The numbers are huge.
The grid operator says it owes about $147 million in refunds, plus an additional $46 million or so in interest to transmission users that made payments under the Z2 process as far back as 18 years ago. It says it also will have to unwind and recalculate more than $20 billion in market settlements dating back to 2015 to resettle that Z2 activity.
Only about 1 to 2% of the latter resettlements are related to the Z2 process, staff told stakeholders during a Jan. 26 virtual meeting.
“This will impact both network and point-to-point activities, so if you’re a transmission customer or transmission owner, you will be impacted, most likely,” said Steve Davis, SPP’s settlements manager. “It’s a large mountain that we’re chiseling away to have a smaller impact.”
That mountain has grown to Everest proportions since 2008, when SPP received FERC’s approval for its tariff attachment that awards credits to sponsors from upgrade sponsors whose service could not be provided “but for” the upgrade. The attachment also required the RTO to invoice the charges monthly and to make any adjustments within one year.
However, software problems delayed Z2’s final implementation for eight years before 2016, during which the RTO did not invoice any upgrade charges. FERC approved a waiver request to settle more than 365 days in arrears, but in 2019, the commission reversed course and said SPP should have settled Z2 activity from only September 2015 forward. (See FERC Reverses Waiver on SPP’s Z2 Obligations.)
SPP General Counsel Paul Suskie has called the Z2 resettlement headache “the most litigated, drawn-out process we’ve ever had.”
The RTO proposed a solution to unwind credit payment obligations assessed under Z2 and made an informational filing at FERC in 2024. In September, the commission ordered the grid operator to make a compliance filing for the proposal. (See FERC Requires Additional Z2 Filing from SPP.)
SPP answered with a filing in November (ER16-1341). It also issued updated refund balances with accrued interest to entities affected by FERC’s remand.
Asked when SPP expects to see the commission’s order, Davis said, “I wish I knew, and that’s probably the best answer we could give. We would love it to be tomorrow, but honestly, I don’t know that we have any indication from FERC.”
SPP’s Charles Locke reminded stakeholders that FERC’s initial order in the proceeding indicated SPP was not to act on the Z2 refunds “until it was specifically authorized to do so by FERC.”
Davis said whenever a favorable order comes, “We plan on hitting the ground running.”
About a month after FERC’s order, SPP will issue final invoices for the refund period. Staff then will complete and deploy an interim Z2 resettlement system and calculate and administer the revised credit payment obligations.
When that process is complete — about eight to 12 months, SPP says — resettlement invoices will be issued for the 2015-2020 operating days. Staff said more than $580 million in Z2 credits have been applied since Sept. 1, 2015; undoing and refunding those historical settlements will require recalculating each operating day since, a process projected to take about two years.
“I keep calling it ‘reshaking of the snow globe,’” Davis said. “We have to recalculate inputs into the Z2 process as if the 2009 period through the September 2015 really never happened.”
Market participants facing big bills will be able to take advantage of a five-year payment plan, using FERC’s interest rate. The commission’s rate for the first quarter of 2026 is 7.20%.
At some point, SPP will transition to the current settlement system for production invoices. Additional resettlements will be run on that system monthly, with staff expecting to resettle three historical operating months each month. They expect to be in sync with normal monthly settlements in 2031.
Ironically, SPP no longer uses the Z2 process. Stakeholders recommended, and the grid operator approved, eliminating Z2 credits in 2020 and replaced them with incremental long-term congestion rights (ILTCRs) for new upgrades. The ILTCRs will limit total compensation to each upgrade’s directly assigned upgrade costs and interest.
After years of declining or stagnant power demand in New England, annual energy demand ticked up for the second straight year in 2025, potentially indicating the start of a broader upward trend.
Total system demand grew by about 0.8% in 2025, while in-region power production increased by about 2.8%, according to RTO Insider’s review of data recently released by ISO-NE. Over the past two years, total energy demand has increased by about 2.6%, and in June 2025, the region experienced its highest peak load since 2013.
From the early 2000s through 2023, net energy for load in New England steadily declined because of energy efficiency investments and the growth of behind-the-meter solar. But ISO-NE expects electrification of heating and transportation to reverse this trend and predicts that annual energy demand will increase by 11.4% from 2025 to 2034, accompanied by a more than 2-GW increase in peak load. By 2050, ISO-NE forecasts peak load reaching up to 57 GW. (See ISO-NE’s Final 10-year Demand Forecast Tapers Expectations and ISO-NE Prices Transmission Upgrades Needed by 2050: up to $26B.)
These forecasts generally do not account for potential data center demand growth, which could add an additional significant source of demand growth. While high power prices have largely kept developers of large-scale data centers away from the region, its largest electric utilities have indicated an uptick in interest in large load interconnections from developers.
As demand increased in the past year, net imports from Québec declined by about 54%. 2025 marks the third straight year with a significant decline in imports from the province. Net imports accounted for just 2% of energy in the region in 2025, compared to an average of over 11% between 2014 and 2022.
The decline in net imports appears to be driven in part by an ongoing multiyear drought affecting hydropower reservoirs in Québec. According to data from the energy consulting firm McCullough Research, the combined energy content at three of Hydro-Québec’s largest reservoirs entered the winter at its lowest point in the last six years. (See Drought, Climate Drive Uncertainty on New England Imports from Québec.)
Hydro-Québec has said it reduced its exports in the leadup to the New England Clean Energy Connect (NECEC) and Champlain Hudson Power Express (CHPE) transmission projects coming online. Both lines include significant supply obligations for the company. NECEC began commercial operations Jan. 16, while CHPE expects to come online by midyear.
It is unclear how the NECEC line will impact New England’s net imports from Québec. While Hydro-Québec has signed 20-year supply contracts with Massachusetts electric utilities for firm power at a fixed price, it is not prohibited from simultaneously importing power from New England on other lines.
While Hydro-Québec plans to make significant long-term investments to add renewable capacity and increase hydropower production, it has a slim reserve margin for the current winter, and reliability issues in the province have forced it to cut or reduce supply along the line for extended periods over the past five days. The contracted supply is not associated with new capacity supply obligations with ISO-NE, but the company faces penalties by Massachusetts for supply interruptions on the line. (See Hydro-Québec Halted NECEC Deliveries amid Reliability Concerns.)
Increased generation from gas, oil, wind, solar and nuclear resources helped fill the gap left by the decline in imports from Québec.
Nuclear and wind power saw the biggest year-over-year growth, both increasing by over 1,000 GWh. The region’s nuclear fleet produced at its highest level since 2019, the year the Pilgrim Nuclear Power Station closed.
Wind power in the region saw a boost as Vineyard Wind ramped up power production in the latter half of 2025. By the end of the year, the 800-MW project had reached about 72% of its production capability. Wind power should be in line for another big year in 2026 if Vineyard and Revolution Wind are both able to complete construction. Revolution is in the late stages of construction but has yet to start producing power. Both projects have obtained stays on the Trump administration’s December stop-work order.
Wind and solar power each accounted for about 4% of total energy in 2025. Solar production increased modestly, by about 6%. This does not include behind-the-meter solar, which has grown significantly in recent years and is the largest category of solar in the region. ISO-NE’s most recent load forecast projected behind-the-meter solar providing 6,316 GWh of energy in 2025, compared to the 4,836 GWh provided by front-of-meter solar during the year.
Oil-fired generation also spiked significantly in 2025. About 80% of this use occurred in January, February or December. The region’s reliance on oil tends to be concentrated during high-demand winter periods when generators have limited access to pipeline gas. Over the past week, sustained cold weather has caused generators to rely heavily on their stored fuel inventories, with oil frequently meeting about a third of energy demand in the region.
Despite the region’s heavy reliance on oil when temperatures drop, oil-fired generation accounted for less than 1% of total energy in 2025.
Gas generation in New England hit another record in 2025, increasing by about 0.8%. Annual gas generation in New England has increased by 21.4% since 2020.
The increased reliance on gas and oil generation contributed to an annual increase in power system carbon emissions. Based on data through Nov. 30, ISO-NE estimates that annual emissions rose by about 2%.
The Oregon Public Utility Commission questioned Portland General Electric’s proposals concerning grid infrastructure cost allocation for data centers, voicing concern that the utility risked prioritizing data centers over other customers.
The Oregon PUC held the hearing under docket UM 2377, which it created in March 2025 to investigate the impact that large loads have on other customers. But with Oregon legislators passing the POWER Act in 2025, UM 2377 has become a first step in rolling out the law.
The POWER Act aims to create a separate customer category for large energy users, such as data centers, and require those users to pay a proportionate share of their infrastructure and energy costs. The law defines a large energy use facility as one that uses more than 20 MW. It applies only to Oregon’s investor-owned utilities. (See Oregon House Passes Bill to Shift Energy Costs onto Data Centers.)
The Jan. 21 hearing focused on PGE’s written testimony submitted on Dec. 19.
PGE wrote that it aims to create a “durable, transparent and equitable rate structure that fairly allocates growth-related costs to the customers driving system growth, whether they are large loads such as data centers or residential demand from increasing use of air conditioning, so that each customer class pays for the costs it causes and the system benefits it receives.”
PUC Chair Letha Tawney asked for clarification on PGE’s proposal, including its proposal to continue to offer an opt-in approach for grid flexibility from data centers.
Tawney asked why the utility is sticking to its voluntary flexibility approach instead of implementing a mandatory requirement to tackle potential “scarcity events” that can impact the system and other customers.
“Your proposition is the opt-in is working: We shouldn’t worry about mandating something,” Tawney said. “I guess I’m really concerned about grid constraints driving pricing and reliability events, truly. So, why should I have confidence that the opt-in is sufficient, as opposed to mandating, from a reliability perspective, that this flexibility has to be on the table?”
In exchange for flexibility, PGE offers data center developers “speed to market,” which has resulted in “very aggressive flexibility proposals,” PGE’s Isaac Barrow replied.
Barrow contended that the opt-in approach has led to “significant resources [at] zero cost to the utility or any other participant, to provide the most benefit.”
“There is also a technical challenge, because it is very bespoke,” Barrow said. “I’m not sure what requirements you could bring forward that would allow that specific optimization of the flexibility proposals.”
Tawney also asked how PGE’s proposals could impact other customers’ compliance with Oregon House Bill 2021, which directs the state’s investor-owned utilities to reduce greenhouse gas emissions by 80% by 2030, on the path to achieving 100% GHG-free generation by 2040. (See Clean Energy, Equity Goals to Reshape Oregon IRP Process.)
PGE has proposed implementing a Peak Growth Modifier (PGM), a methodology to allocate fixed generation and transmission costs to customer classes based on their contribution to peak load growth.
“I am concerned that there is a limited universe of large-scale clean energy projects that are well priced and have reasonable commercial online dates, have interconnection agreements signed and some sort of line of sight to actually energizing,” Tawney said.
She asked how the PGM could address the potential of large loads consuming lower-cost generation resources while leaving residential customers with higher-cost options for HB 2021 compliance.
PGE has proposed new special contracts aimed at allowing large load customers to accelerate buildout of clean energy on the grid with the idea that it would “only be the resources that are left over from an RFP process, allowing for the best projects to go to our cost-of-service customers,” according to Jacquelyn Ferchland, senior manager of rates and regulatory affairs at PGE.
Barrow added that the special contracts would address effective load carrying capability and “what is the appropriate risk allocation for underproduction as well as overproduction of the specific contracted asset.”
He noted that if PGE does not serve data centers within the HB 2021 framework, other entities without decarbonization requirements may take over.
“With the demand we’re seeing, if … PGE does not serve these entities within our service portfolio, within the protections of House Bill 2021, there is a strong potential that they get served by an entity that does not have decarbonization as to the greenhouse gas requirements or is not subject to the Power Act or House Bill 2021,” Barrow said.
Financial Concerns
The hearing also touched on the financial pressure from buildout of resources to meet demand from data center customers.
Although tools like Contributions in Aid of Construction could alleviate some of the pressure, that might not be enough, Tawney said. She noted the risk of PGE running out of capital for other projects.
PGE keeps the balance sheet in mind, which is why the utility does not build at the speed data center customers would like, according to Ferchland. PGE’s flexibility approach and special contracts aim to allow data centers to connect to the utility’s system faster, she said.
“But otherwise, we are concerned about pressure on our balance sheet, and we would want to make sure that we move only as quickly as appropriate to ensure that our balance sheet remains healthy,” Ferchland said.
“I am concerned that you’re articulating a pacing based on your financial situation that I’m not seeing in the tariff,” Tawney said. “And I’m not understanding how you would be able to accomplish without sort of being accused of a discriminatory behavior towards a particular customer. So, understanding that would be really helpful.”
The commission’s final order is due by April 30, 2026, according to the docket.
A judge has lifted the federal stop-work order on Vineyard Wind 1, allowing work to resume on the long-running, nearly completed Massachusetts offshore wind project.
Four of the five facilities under construction in U.S. waters have won permission in January from four federal judges to resume work.
The fifth, Sunrise Wind, is set for a Feb. 2 hearing on its request for a preliminary injunction (1:26-cv-00028) before the same judge who granted Revolution Wind’s request for a preliminary injunction Jan. 12. (See Judge Again Lifts Revolution Wind Stop-work Order.)
Vineyard was the last of the five projects to request an injunction, waiting until Jan. 15 to file in court. Later Jan. 27, after the injunction was issued, Vineyard said it “will continue to work with the administration to understand the matters raised in the [stop-work] order.”
“Vineyard Wind will focus on working in coordination with its contractors, the federal government, and other relevant stakeholders and authorities to safely restart activities as it continues to deliver a critical source of new power to the New England region,” it added.
The 62-turbine, 800-MW Vineyard Wind 1 is a joint venture of Avangrid and Copenhagen Infrastructure Partners that put its first steel in the water in June 2023. It was far behind its original schedule even before the stop-work order, but it is nearly complete and has begun sending power to the grid.
The impact of the stop-work order has extended beyond the developers themselves.
GE Vernova, the manufacturer of the turbines and blades being installed off the south coast of Massachusetts, said Jan. 28 that the federal stop-work order contributed to the $225 million loss the company’s wind business recorded in the fourth quarter of 2025.
CFO Ken Parks said during an earnings call that one turbine is left to be installed and 10 need blades installed.
If GE Vernova does not install these components before March 31, he said, it will lose access to the installation vessel needed for the work. If it cannot install the equipment, it cannot bill the developer for the work, potentially resulting in a $250 million loss in 2026, he said.
For this and other reasons, the wind business will record a $600 million loss for 2025, 50% more than the $400 million predicted in early December, giving it a ‑6.6% EBITDA margin for the year.
GE Vernova’s two other component businesses fared much better: Power recorded 52% more orders and 10% more revenue in 2025 than in 2024 and boosted its EBITDA margin to 14.7%. Electrification recorded 21% more orders and 26% more revenue year over year and bumped its EBITDA margin up to 14.9%.
“This stay is an important step in the process to fight back against the Trump administration’s lawless attacks against our union jobs, grid security and energy affordability,” they said. “Vineyard Wind 1 is currently delivering affordable and reliable power into our grid and has the permits, financing and approval to deliver even more. Shutting off Vineyard Wind 1 would kill thousands of local union jobs, prevent power from reaching 400,000 homes, and cause us to lose out on $3 billion of energy savings.”
State regulators in MISO asked FERC to let power industry stakeholders determine how to allocate the costs of an Indiana coal plant forced to stay online by the Trump administration’s Department of Energy.
The Organization of MISO States (OMS) said the RTO’s stakeholders and regulators should decide on now to divvy up the costs of sustaining operations at thermal plants whose retirements are delayed under emergency orders issued by DOE under Section 202(c) of the Federal Power Act.
Northern Indiana Public Service Co. — whose units 17 and 18 at its R.M. Schahfer Generating Station are under such orders through March 23 — filed in late 2025 to recover costs of running the plant from MISO Midwest participants (EL26-36). (See Enviros Warn NIPSCO Against Rebuilding Coal Unit on DOE Emergency Order.)
FERC previously approved a cost allocation plan for MISO Midwest entities to split the expenses of running the J.H. Campbell coal plant in Michigan — another of a handful of aging thermal plants set to retire that DOE says can’t be spared due to reliability concerns.
OMS said instead of applying a similar allocation, FERC this time should task MISO with engaging its member states and stakeholders to design a cost allocation for the Schahfer units. If FERC decides against that avenue, it should open NIPSCO’s request for an allocation plan to a hearing that weighs anticipated rate impacts and provides opportunity for comments from affected states and customers, OMS said.
“In either case, OMS stresses that any ultimate cost assignment that results from this proceeding should be based on a clear demonstration of need and commensurate with benefits received to help mitigate unintended consequences,” OMS wrote.
OMS said if FERC continues to allow the costs of emergency orders to be allocated across MISO Midwest, generation owners could start to exploit a predictable outcome.
“If the commission routinely approves broad regional cost allocation for 202(c) order costs without a demonstrated, commensurate benefit, utilities may be incentivized to accelerate retirements and cash in on a 202(c) order cost shift, moving costs away from local customers and onto an 11-state region,” OMS wrote in Jan. 20 comments to FERC.
The regulators’ group said DOE’s “self-determined energy emergency does not obviate the commission’s obligation to establish just and reasonable rates.” It said a cost allocation design should be “equitable and durable,” especially because DOE is likely to order other retiring thermal units to stay in service.
OMS noted also that while FERC regulates wholesale markets and interstate transmission, “states are responsible for determining what generation is needed, where it is located, how it is financed and whether it is prudent to serve retail customers.”
OMS said NIPSCO’s proposal would spread Schahfer expenses broadly across MISO Midwest, even to customers who won’t experience any reliability benefit, “including Indiana.” The group noted that PJM, its member states and stakeholders were allowed to develop a cost-recovery plan last year when DOE ordered Constellation Energy’s Eddystone Generating Station to keep running.
Multiple OMS members abstained from the vote to submit the comments, including the Arkansas Public Service Commission, the Louisiana Public Service Commission, the Mississippi Public Service Commission, the New Orleans City Council, the Public Utility Commission of Texas, and, interestingly, the Indiana Utility Regulatory Commission.
Consulting Firm Predicts Tens of Millions in Costs
Keeping Schahfer units 17 and 18 operating is likely to come with steep costs. Synapse Energy Economics estimated that DOE’s initial 90-day extension of the trio of Indiana coal plants under emergency orders — the Schahfer units and CenterPoint’s Culley Unit 2 — would cost $20.6 million under economic commitment practices. Schahfer would account for the lion’s share of the cost, which could rise significantly, the consulting firm found.
“If DOE extends the order long term, we estimate the coal units would require an additional $33.7 million per year in capital expenditures to replace equipment as it wears out and install environmental controls to maintain compliance with environmental regulations,” Synapse wrote in a report prepared for Earthjustice, Sierra Club and the Environmental Law and Policy Center.
All three units were to retire at the end of 2025.
Synapse’s numbers don’t account for the extensive turbine repairs NIPSCO has said Schahfer Unit 18 requires immediately before becoming available for dispatch. NIPSCO officials have said that work could take six months or more.
The Illinois Commerce Commission likewise asked FERC to give states and stakeholders space to asses a suitable cost-recovery for the Culley unit under CenterPoint’s complaint for a cost allocation mechanism (EL26-38). The ICC said DOE’s orders are becoming “routine” and order issuances could go on for years.
“The likely frequency and length of these orders, much longer than [an] initial 90-day period, is crucial in considering how to handle cost allocation for generating units that are unexpectedly and unnecessarily being retained on the system,” ICC wrote in Jan. 23 comments to FERC.
The state commission said given the “volume of DOE 202(c) orders, and the potential harmful impacts on ratepayers across the MISO region, a robust stakeholder process is needed.” It said DOE’s continued orders to retiring coal plants will “result in significant, but currently unknown costs with unknown benefits.”
MISO announced further delays in its generator interconnection queue for the cycles of projects that entered in 2022, 2023 and 2025.
The grid operator said it does not expect to complete the second phase of studies for 2022 project entries until May 7, 2026. MISO similarly said 2023 project entries would not finish second phase studies until Sept. 3, 2026. The RTO conducts its interconnection studies in three phases.
The updated timeline is months behind what MISO originally said it could manage as it rolled out a new, automated study process.
Now, MISO does not expect the 2022 cycle of projects to execute generation agreements until early January 2027. The 2023 cycle would follow in late March 2027.
MISO reported that the 2022 class of generation hopefuls are experiencing modeling delays across all regions.
“We’re still so bogged down by previous cycles and restudies and the backlog churn,” Senior Manager of Resource Utilization Kyle Trotter explained at a meeting of the Interconnection Process Working Group on Jan. 27. “We have ’21, ’22, ’23 and ’25 all in flight at the same time.”
MISO is nearing completion on its 2021 cycle, save for a cascading model delay for projects located in its Central region.
The later timeline leaves the 2025 cycle of projects pushed later as well, though MISO has yet to estimate realistic dates. The RTO’s most recent queue processing chart targets the 2025 cycle’s dates according to the scheduling prescribed by FERC Order 2023. If MISO were to follow that, it would have to complete the second study phase by mid-July and sign interconnection agreements in early February 2027, months ahead of the expected wrap up of the 2023 group.
But Trotter said MISO would not begin the second batch of studies on the 2025 cycle of projects until it has sufficiently moved the 2023 cycle along. He said it would seek a waiver with FERC to delay studies for the 2025 cycle.
“We haven’t yet been in contact with FERC about it, in filing a waiver for the 2025 cycle,” Trotter said.
Trotter declined to provide more details on what exactly the RTO would request to waive. He said it is still discussing details internally with its legal team and must engage FERC before presenting its request to stakeholders.
David Ticknor, senior interconnection engineer at RES Group, reminded MISO of the importance of working quickly to approve projects so that renewables can secure federal tax credits before their discontinuation.
Stakeholders asked where it stands on acceptance of 2026 cycle of generation projects.
“We would project the 2026 cycle closing at the end of the year, similar to years past,” Trotter answered, adding that study kickoff would occur in early 2027.
In a related queue matter, MISO wants to standardize its collection of data from generation developers to help speed up its power flow modeling delays.
Manager of Resource Utilization Rob Lamoureux said the RTO needs rule changes to make sure it receives consistent modeling data from developers. He said it could complete studies faster and more accurately if it could draw on identical fields for modeling data.
Lamoureux said the various fields slow down MISO’s modeling and that a more regimented data collection would produce better models for Pearl Street’s SUGAR software, which the RTO is using to automate studies.
“Half of the files from ’23 and ’25 had to be manually reworked,” Lamoureux told stakeholders. He said MISO had to intervene to manually feed data into its systems for 50% of the modeling files from the 2023 cycle and 53% of files in the 2025 cycle.
He reminded stakeholders that MISO would face penalties of $1,000 to $2,500 per business day by the 2027 cycle under Order 2023 if it does not reasonably meet deadlines.
Ryan Westphal said MISO’s tariff currently permits more than a dozen formatting methods. In some cases, it receives conflicting data in redundant entries from the same developer, he said.
Lamoureux said MISO would put together a draft data standard for stakeholder review in time for the IPWG’s March 10 meeting.
“If we get these changes out soon, they could be implemented before the 2026 cycle,” he said.
The Bonneville Power Administration provided updates on the agency’s $5 billion in transmission projects as some stakeholders asked about sunsetting of tax credits and coordination efforts with other developers in the West.
BPA staff discussed the agency’s Grid Expansion and Reinforcement Portfolio (GERP) during a Jan. 27 meeting. GERP consists of more than 20 proposed transmission line and substation projects. The initiative, previously called Evolving Grid, aims to improve transmission and reliability in the Northwest, according to the agency’s website. (See Stakeholders Seek More Details on BPA’s ‘Evolving Grid’ Projects.)
BPA launched GERP in two phases in 2023 and 2024.
GERP 1.0 includes 10 proposed projects focused on 363 miles of transmission lines at a preliminary cost of $2 billion. It includes upgrades, rebuilds and improvements to existing facilities, as well as two new substations and one new transmission line.
The projects are all proposed as they have not undergone an environmental assessment under the National Environmental Policy Act (NEPA), according to BPA’s Eric Orth.
Orth said he does not anticipate many NEPA challenges because many of the GERP 1.0 projects concern upgrades to existing facilities.
“They’re not brand-new lines going through new territory,” Orth said. “We will do our due diligence when it comes to NEPA, but I don’t anticipate any big challenges with these lines or substation projects.”
The largest upgrade under GERP 1.0 is the replacement of a 91-mile, 230-kV line with a 500-kV line between BPA’s Big Eddy substation and Pearl substation. The upgrade has a preliminary estimated cost of $670 million and an estimated completion by 2033.
Orth said staff are scoping the project.
“We are well on our way,” Orth said. “We’ve got a good plan of service, and we’re currently putting together plans to solicit the project this summer for an engineer, procure, construct contract. And so that’s exciting. That’s a big step. Essentially … the project will be at a 30% design, and we will bid that out competitively to a pool of contractors to finish the project.”
Many of the GERP 1.0 projects have an estimated completion date after Dec. 31, 2029, when federal tax credits for solar and wind projects are set to expire, according to Alex Swerzbin, vice president of power marketing and transmission at NewSun Energy.
“If these generating projects aren’t energized, they’re going to lose out on your tax credits, which could be 30, 40% tax rate and value of the project,” Swerzbin said.
Customers can help by coordinating with BPA “as projects develop through scoping and design. Many of the schedules are tied to how long it takes to procure some of the materials,” Orth said.
BPA is working on “on ways to condense schedules,” Orth said. “But I think the question is a good reminder for us to maybe go back and look at which projects are tied to some renewable generation interconnection requests and see if we can do anything with the timing.”
GERP 2.0
GERP 2.0 includes 13 proposed projects with a preliminary projected cost of $3.9 billion. BPA aims to complete GERP 1.0 projects in the next five to six years, while GERP 2.0 projects have a longer timeline. Many of the 2.0 projects build on 1.0 upgrades, BPA’s Matt Hagensen said.
One major GERP 2.0 project is the Lower Columbia NOB initiative, a three-part effort aimed at improving connectivity from the lower Columbia region to the Nevada-Oregon border with 500-kV transmission lines and a new substation near the border.
The project has a preliminary estimated cost of $1.9 billion with an estimated completion by 2035.
“It’ll help create more interregional connectivity,” Hagensen said about Lower Columbia NOB. “We do have some joint studies going on with some southern partners in Nevada that would build up to that station. And so really creating that opportunity and that resource diversity between the Northwest and the Southwest.”
Fred Heutte, senior policy associate at the NW Energy Coalition, asked about coordination with other developers, pointing to PacifiCorp’s Blueprint South project, a new 180-mile line in south-central Oregon.
Hagensen said BPA coordinates with other stakeholders through regional planning to assess how projects interact.
Heutte noted “these are multibillion dollar projects,” saying “we kind of got to get it right.”
Western regional assessments focus primarily on east-west connectivity, according to Heutte.
“I think the north-south configuration is something that really needs more attention,” he said. “So, just to say, this is a very interesting project. It has lots of big pieces and there are other forces at play here. And just to encourage Bonneville to provide more information about the discussions and studies that are being done, and again, more context, because this is a very big deal.”
