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December 18, 2025

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CISA Updates Critical Infrastructure Cyber Goals

The Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency has updated its Cross-Sector Cybersecurity Performance Goals to provide critical infrastructure operators “a more robust framework for integrating cybersecurity into daily operations.”

Version 2.0 of the CPGs, released Dec. 11, was developed with the input of industry stakeholders, government agencies and cybersecurity experts, based on CISA’s operational data and research on the current threat landscape. The goals are intended to align with the National Institute of Standards and Technology’s Cybersecurity Framework 2.0, introduced in 2024. (See NIST Expands Cyber Framework in Latest Release.)

CISA introduced the CPGs in 2022, following a directive from President Biden that DHS and NIST establish a set of “baseline security practices” to be followed by critical infrastructure owners and operators across sectors. (See Biden Launches ICS Cybersecurity Initiative.) However, adoption of the goals has led to a gap between large organizations and others, which CISA acknowledged “often struggle to translate high-level goals into concrete action.” The agency wrote that this gap has led to dangerous vulnerabilities in critical facilities.

In a press release, CISA wrote that the CPGs “offer a practical starting point for small- and medium-sized organizations” to improve their cybersecurity posture “by focusing on a limited set of high-impact actions.” Acting Director Madhu Gottumukkala said the update “demonstrates our commitment to listening to and incorporating partner feedback to deliver practical, outcome-driven guidance that organizations can act on.”

“These goals are applicable across all critical infrastructure sectors and offer foundational protection for organizations regardless of their cybersecurity maturity,” Gottumukkala added. “We encourage all organizations to adopt the new CPGs and continue sharing feedback to help us refine future iterations.”

The CPGs are organized into six functions, presenting best practices to address individual risk and aggregate risks to U.S. critical infrastructure overall. The first function, “govern,” is a new addition reflecting “the critical role of organizational leadership in cybersecurity” and mirroring the addition of a similar function in NIST’s framework.

Practices under this function include establishing cybersecurity roles, responsibilities and authorities within the organization, and communicating them with external partners; reviewing cybersecurity program management at least once a year, updating as needed and communicating changes; maintaining and practicing incident response plans; managing supply chain risks; and addressing risks from managed service providers.

Functions carried over from the previous version include identification, which has to do with managing organizational assets, documenting network topology and mitigating known vulnerabilities; protection, which concerns passwords, credential maintenance, encryption and other defensive measures; detection, for spotting unauthorized access attempts; incident response; and recovery.

CISA also consolidated some goals by eliminating duplicate guidance. Specifically, the agency gathered information technology, operational technology and internet of things goals into a single goal set in recognition of the fact that these categories increasingly are blurred in modern infrastructure. CISA wrote that the changes would allow “small- and medium-sized entities [to] apply one framework across their entire estate, without confusion over domain-specific goals.”

Future updates to the CPGs should arrive at a 24- to 36-month cadence, CISA wrote.

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ISO-NE Discusses Final Sensitivities for Economic Study

ISO-NE presented the final stakeholder-requested sensitivities for its 2024 Economic Study at the Dec. 17 meeting of the Planning Advisory Committee, discussing the potential effects of adding 3.9 GW of hydropower to the Hydro-Québec system.

The study, which began in March 2024, aims to evaluate long-term changes to the region’s power system. ISO-NE published the final report in September. The RTO previously discussed stakeholder-requested sensitivities related to advanced solar panels, demand flexibility, thermal generator retirements and a halt on offshore wind development.

The hydropower sensitivity is intended to reflect the potential impacts of a preliminary agreement between Newfoundland & Labrador Hydro and Hydro‑Québec to add a large amount of new hydropower capacity.

Growing demand, extended drought conditions and international HVDC transmission projects have caused Québec to pull back on its exports to New England in recent years. (See Drought, Climate Drive Uncertainty on New England Imports from Québec.) However, ongoing efforts to add significant amounts of new generation throughout Eastern Canada may provide a long-term answer to tightening system conditions.

ISO-NE’s modeling indicates that the added hydropower capability would increase New England’s net imports by about 6.2 TWh relative to the reference case, equal to about a 60% increase.

Net imports to New England from Hydro‑Québec increase by 5.6 TWh under the scenario, while New England remains a net exporter to New Brunswick, ISO-NE’s Ben Wilson said.

The modeling indicates that the increased imports would reduce annual production costs in New England by about $448 million relative to the reference case. This would reduce the economic benefit of congestion relief on the New England system by lowering the potential cost gains associated with displacing marginal resources.

Wilson also added that power exchanges with Hydro‑Québec would likely be “much more bidirectional than in recent years, which have seen mostly unidirectional interchanges.”

ISO-NE also conducted a sensitivity analysis looking at gas price differentials across New England and New York. The RTO modeled a uniform gas price across the Northeast Power Coordinating Council in the reference case. ISO-NE said this approach was necessitated by its limited insight into the trends affecting fuel prices and by the challenges associated with forecasting fuel prices a decade into the future.

Modeling gas price differentials caused gas prices in New England to increase, pushing up ISO-NE locational marginal prices and production costs.

“Net imports into New England increase by 3.6 TWh while using a gas price differential, with most of the additional energy coming from [New York],” Wilson said, adding that the higher New England energy costs in this sensitivity increased the value of congestion relief.

Asset Condition Projects

Also at the PAC meeting, representatives of transmission owners presented on asset condition projects.

Dave Burnham of Eversource Energy introduced a nearly $6 million project to replace optical ground wire on a line in Western Massachusetts.

The project was placed in service in October, he said, noting that Eversource did not initially present the project to the PAC because it fell short of the $5 million threshold for project presentations. Cost overruns, stemming in part from “unanticipated requirements” from the Massachusetts Department of Transportation, pushed the project past the threshold, he said.

The additional fiber capacity is necessary “to support critical communications and to provide redundancy to avoid loss of communications during failures or outages,” Burnham said.

Joshua Cefaratti of United Illuminating gave an update on a flood mitigation project in Connecticut. Estimated project costs have increased from about $26 million to about $43 million since the company initially presented the project in 2021. The higher cost is largely from increased labor and materials costs, he said.

Kyra Lagunilla of Rhode Island Energy gave an update on a line rebuild project that was initially presented by National Grid in 2005. Rhode Island Energy purchased National Grid’s Rhode Island gas and electric utility business in 2022. The project’s drawn-out timeline has been driven largely by delays associated with community engagement, ISO-NE said.

Rhode Island Energy has withdrawn the original transmission cost allocation for the project and plans to submit a new one, Lagunilla said. The project has an estimated pool transmission facility cost of nearly $14 million.

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DOE Orders Retiring Wash. Coal Plant to Stay Online for Winter

Citing an energy “emergency” in the Pacific Northwest this winter, the U.S. Department of Energy ordered TransAlta to continue operating Washington state’s last coal-fired generating plant for three months beyond its scheduled retirement.

Unit 2 at the Centralia Power Plant was slated for closure at the end of December based on a 2011 Washington law and subsequent agreement between the state and TransAlta.

But in a controversial move that has sparked the ire of environmental groups, DOE on Dec. 16 directed the company to keep the 670-MW unit running until March 16, 2026. Unit 1 at the facility was shut down in 2020 as part of the first phase of the plant’s retirement.

“The reliable supply of power from the Centralia coal plant is essential for grid stability in the Northwest. The order prioritizes minimizing the risk and costs of blackouts,” DOE said in the press release accompanying the order (202-25-11), which follows similar orders to extend the operation of older fossil fuel plants. (See DOE Issues 3rd Emergency Order to Keep Michigan Coal Plant Open and Energy Secretary Wright Issues 3rd Order Keeping Eddystone Open.)

Energy Secretary Chris Wright took the opportunity to criticize Democratic environmental policies that he said have forced the closure of coal generators across the country.

“The last administration’s energy subtraction policies had the United States on track to experience significantly more blackouts in the coming years. Thankfully, President Trump won’t let that happen,” Wright said in the release. “The Trump administration will continue taking action to keep America’s coal plants running so we can stop the price spikes and ensure we don’t lose critical generation sources.”

The order comes a week after Alberta-based TransAlta announced it had signed a long-term tolling agreement with Puget Sound Energy that enables the plant to be converted to a 700-MW natural gas-fired facility.

“TransAlta is currently evaluating the order and will work with the state and federal governments in relation thereto. The coal-to-gas conversion project, announced on Dec. 9, 2025, remains a priority for TransAlta,” the company said in a statement. “Further information regarding the order will be provided as it becomes available in due course.”

The company declined to answer questions about its readiness for keeping Centralia operable for the winter.

‘Sudden Increase’

In describing its rationale for the order, the department pointed to NERC’s 2025-2026 Winter Reliability Assessment released in November, which included WECC’s Northwest region among seven in North America that are at “elevated” risk for grid outages during “extreme weather.”

That risk stems in part from an expected 9.3% increase in regional peak electricity demand, accompanied by tightening supplies. Still, NERC’s assessment did not find any regions to be at “high” risk for outages — including the Northwest. (See NERC Winter Reliability Assessment Finds Many Regions Facing Elevated Risk.)

Quoting from the assessment, DOE noted NERC found that the Northwest should have “sufficient resources” for expected peak load conditions but that the region’s balancing authorities were “likely to require external assistance during extreme winter weather that causes thermal plant outages and adverse wind turbine conditions for area internal resources,” with that assistance possibly compromised by a “regionwide” extreme event.

DOE’s other justification for the order: a September 2025 study on Northwest resource adequacy by Environmental and Energy Economics that found “accelerated load growth and continued retirements create a resource gap beginning in 2026 and growing to 9 GW by 2030” and that “load growth and retirements mean the region faces a power supply shortfall in 2026.” (See 9-GW Power Gap Looms over Northwest, Co-op Warns.)

The order contends that Section 202(c) of the Federal Power Act authorizes the energy secretary “to require the continued operation of Centralia Unit 2 when the secretary has determined that such continued operation will best meet an emergency caused by a sudden increase in the demand for electric energy or a shortage of generation capacity … Such is the case here.”

The order calls for TransAlta “take all measures necessary” to ensure Centralia is “available to operate at the direction of either” the Bonneville Power Administration in its role as a BA or CAISO in its role as the reliability coordinator. It also requires the plant to comply with “applicable environmental requirements” and directs TransAlta to provide DOE with information about its operations plan by Dec. 30.

The department also directed BPA to “facilitate” Centralia’s transmission service “as needed.”

Asked about the roles outlined for BPA and whether DOE had consulted with the federal power agency before issuing the order, BPA spokesperson Kevin Wingert said it still was reviewing the text and directed questions to DOE.

CAISO spokesperson Jayme Ackemann told RTO Insider the ISO was made aware of the order only after it was issued and was still reviewing it.

The department did not respond to questions about what Western electricity sector entities it consulted before issuing the order.

‘Incredibly Unproductive’

Environmental groups lashed out at the order, with the Environmental Defense Fund calling it an “illegal mandate.”

“Once again, the Trump administration is upending state and local decisions to force an aging, costly, polluting coal plant to stay open,” Ted Kelly, EDF’s director and lead counsel for U.S. clean energy, said in a statement.

EDF pointed to DOE’s repeated extension of emergency orders for the J.H. Campbell coal plant in Michigan and the Eddystone oil-and-gas plant in Pennsylvania, “despite evidence that both plants are unreliable, highly polluting facilities and are not necessary to meet near or long-term energy needs.”

“Let us be clear: There is no ‘energy emergency’ in the Pacific Northwest that would justify forcing the continued operation of an old and dirty coal plant that endangers public health, worsens climate pollution and has long been slated for retirement,” Sierra Club Washington State Director Ben Avery said in a statement. “All the evidence shows that when Centralia shuts down, customers’ costs will decrease and air quality will improve. Instead of lowering bills or protecting families from harmful pollution, the Trump administration is abusing emergency powers to prop up fossil fuels at any cost.”

“This federal overreach is incredibly unproductive,” said Lauren McCloy, utility and regulatory director at the NW Energy Coalition. “People across the industry in the Northwest are working hard to plan for, acquire and build the resources we need to have a clean, affordable, reliable electricity grid. The closure of this plant has been planned for over a decade, and keeping it running beyond its useful and economic life is not the answer.”

“The shutdown of Washington’s last coal plant has been in the works for nearly 15 years,” Earthjustice attorney Patti Goldman said. “Washingtonians don’t want or need coal in their stockings this year.”

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WEM Board OKs Gas Management Changes to Provide ‘Equitable Access’ to Markets

The Western Energy Markets Governing Body approved a set of revisions to CAISO’s Gas Resource Management program after two years of work with stakeholders in the West.

The approved proposal provides gas resource entities with more opportunities to reflect their fuel costs and conditions in the day-ahead and real-time markets. It also revises day-ahead advisory market runs to improve fuel procurement forecasts, among other items.

“Gas resources face unique challenges in managing uncertainty across [the] independent but linked gas and electric markets,” CAISO Vice President of Market Design and Analysis Anna McKenna said in a Dec. 10 memorandum. “When gas prices are volatile or the gas system experiences constraints, energy offers from gas resources can quickly become obsolete if those bids do not adequately account for price uncertainty.”

Currently in the Western Energy Imbalance Market (WEIM), participants manage their fuel-cost procurement risk by submitting hourly base schedules and only bid for real-time dispatch based on the availability and cost of gas imbalances, McKenna said.

But in the Extended Day-Ahead Market (EDAM), set to open in May 2026, base scheduling is not available, which means that energy resources will use market offers for day-ahead commitments.

In a Dec. 9 memorandum, the ISO’s Department of Market Monitoring added that EDAM might “create additional challenges for gas procurement in regional markets outside of the CAISO area.” These challenges include an increased uncertainty about gas procurement requirements, more frequent purchasing of gas after the close of the morning gas market and more exposure to higher levels of gas price variability, the DMM said.

The approved proposal allows gas resources to more easily customize cost inputs, access cost-adjustment mechanisms and recover costs, McKenna said. The revisions try to also guarantee that all gas systems, regardless of location within the Western footprint, have equitable access to the market, she said.

While stakeholders supported the overall process proposed for customizing fuel volatility covered in reference levels, some raised concerns about certain design details, McKenna said. The DMM cautioned that frequent cost-adjustment requests could be subject to gaming.

“It’s fair to say this is a really complex policy,” Danny Johnson, CAISO market design manager, said at the Governing Body’s meeting Dec. 16. “The proposed methodology balances implementation feasibility and needed flexibility sought by stakeholders. As part of the audit process, the ISO will monitor for any adverse or unintended consequences.”

CAISO management agreed that the audit process is an important feature of the proposal, McKenna said.

As part of its stakeholder process, the ISO studied the existing tools for accommodating fuel-cost variations for gas generators in parts of the WEIM, where “physical gas system characteristics and fuel supply arrangements are diverse,” the proposal says. It addresses “exceptional circumstances” on the grid when gas-fired resources face more uncertainty than usual. Under such circumstances, CAISO might anticipate that gas resources will need additional flexibility to request cost adjustments.

“As a general principle, gas resources either need more certainty for fuel procurement or more flexibility to manage uncertainty related to fuel procurement,” the proposal says.

CAISO’s proposal therefore provides gas generators with additional flexibility to request cost adjustments when the ISO forecasts that same-day gas will be needed to support day-ahead commitments and incremental real-time dispatch, the proposal says.

The proposal also includes a customizable multiplier on the gas price index because some resources face more gas price volatility than others. The multiplier will cover specifically the volatility of a gas resource’s circumstances to ensure that reference levels and the reasonableness threshold all reflect a resource’s adjusted gas price volatility, the proposal says.

The proposal also grants gas resource entities the ability to request after-the-fact cost recovery, but only if they can demonstrate that a physical gas disruption occurred.

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Can Expanding Transmission Reduce Electricity Costs?

By Travis Fisher and Nick Loris

Advocates of large-scale transmission expansion have recited a simple slogan for years: There is no transition without transmission. By this, they mean that the shift to renewable energy will require vast new power lines. Whatever one thinks of climate policy, that argument no longer carries much weight. The relevant question now is whether building more transmission will make electricity more affordable.

Yes, expanding transmission can reduce electricity costs for consumers, but only if the buildout uses consumer welfare as the North Star and ignores narrow political or business interests. The goal of transmission reforms in Congress should be straightforward: Deliver reliable power that meets our growing needs at the lowest possible cost to end users.

In nearly every other sector — pipelines, railroads, ports, broadband — infrastructure is built when customers are willing to pay for the value it provides. Projects move forward based on contracts, price signals and risk-taking. Investors bear losses when they guess incorrectly. That discipline helps ensure that infrastructure is built to meet demand at least cost.

Electric transmission is different only because decades of poorly designed regulations — and dogged political fights over competing energy resources — have made it so. A consumer-centered approach would optimize the buildout of new transmission lines and allow competition from non-wire alternatives such as local or on-site generation of all stripes, storage, demand response, grid-enhancing technologies and microgrids.

Nick Loris

It would allow new large customers such as data centers to pay for all required transmission upgrades if they choose to so that their costs don’t spill over to existing customers. And it would subject utility-initiated projects to real scrutiny, ensuring consumers are not locked into paying for upgrades that are not the least-cost option. Short of restructuring the entire transmission grid (again), minimizing costs to consumers is the most open-ended and market-friendly federal policy.

The consumer-first approach does not assume a particular generation mix or require sweeping national planning exercises. It rests on a more straightforward principle: Transmission should be built when it lowers the total cost of reliable electricity for consumers. FERC has long held up “reliability at least cost” as a policy goal but has brought precious little analytical expertise to the table to ensure that outcome. Adhering to the “beneficiary pays” principle and subjecting projects to rigorous cost-benefit analysis will provide better outcomes that protect ratepayers.

Congress should encourage transmission projects that reduce the cost of delivered power and hold FERC accountable for finding the sweet spot between too much transmission and too little. Could a FERC analysis show that smaller transmission projects are a costly short-term bandage while larger projects generate long-term savings? The “smile curve” framework introduced by MISO offers a consumer-focused approach to analyzing the role of transmission in minimizing total costs.

Travis Fisher

Transmission is a means to that end, not an end in itself. More transmission can reduce costs by connecting customers to lower-cost generation, relieving congestion or improving reliability in an economically efficient way. But more transmission also can raise bills if it is overbuilt, poorly targeted or used to inflate profits for incumbent utilities.

Today’s regulatory framework prevents complete oversight. No regulator is responsible for the full cost of electricity paid by consumers. FERC oversees wholesale markets and transmission rates. State public utility commissions typically oversee transmission siting, the distribution network, retail rates and sometimes the generation portfolio. But neither the feds nor the states are accountable for the total bill consumers pay, and decisions that look reasonable in isolation can stack up to higher costs with no one asking whether households and businesses are better off.

Transmission spending illustrates the problem. It has become one of the fastest-growing components of electricity bills, with tens of billions of dollars flowing to new projects each year. Those costs are passed directly to consumers through regulated rates, largely shielded from competition.

In PJM — the nation’s largest regional grid operator — environmental advocates note that utilities recently allocated roughly $4.4 billion in transmission upgrade costs in a single year to serve new data center demand. These costs were broadly socialized across ratepayers, even though the upgrades primarily benefited a narrow set of large loads. That is not an argument against transmission, nor is it an argument against AI-related load growth (which, according to Berkeley Lab, could help reduce rates). Instead, it is an argument against building transmission without clear accountability and under rules that fail to meet today’s moment of rapid demand growth.

The crutch of low-voltage transmission projects underscores the point. These projects are proposed unilaterally by utilities, outside the regional planning process, with limited competitive pressure and little obligation to demonstrate that they are the lowest-cost solution to a reliability problem. In PJM, spending on small ball projects such as “supplemental” upgrades has grown dramatically over time, exceeding spending on high-voltage lines that span multiple utility territories or states.

America has the capital, engineering expertise and entrepreneurial talent to build a world-class transmission system. What it lacks is a regulatory framework that consistently asks whether new investment makes electricity bills more affordable. Expanding transmission can reduce electricity costs, but catchy slogans won’t get us there. We need a consumer-first, market-disciplined approach that reliably meets today’s growth without raising electricity bills for everyday Americans.

Travis Fisher is the Director of Energy and Environmental Policy Studies at the Cato Institute and Nick Loris is the Executive Vice President of Policy at the Conservative Coalition for Climate Solutions.

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Brattle/Dragos: Battery Systems Create New Cybersecurity Risks

A new white paper from The Brattle Group and cybersecurity firm Dragos is sounding the alarm about the potential cybersecurity vulnerabilities posed by battery energy storage system infrastructure.

Between widespread equipment standardization, foreign-sourced equipment and the increasingly networked nature of BESS installations, the paper says now is the time to implement cybersecurity measures. A 400-MWh BESS that is compromised could result in more than $1 million in damages from an outage, according to the paper, released Dec. 9.

“There are already many cases where battery systems have been compromised,” Phil Tonkin, field chief technology officer of Dragos and paper co-author, said in an interview.

BESS infrastructure is growing rapidly across the U.S. and Europe. According to Brattle’s analysis, roughly a third of the nameplate megawatt-hours added to the U.S. grid will be battery systems between now and 2029. Most of these systems are controlled remotely and are standardized across the industry, lowering barriers to attack.

With standardization of BESS components, a dedicated attacker could “copy and paste” an attack across hundreds of sites, Tonkin said. Because batteries can be critical for local reliability and grid operations, they present a tempting target to state actors, he explained.

“The grid is a deeply interconnected, essentially zero-latency machine,” said Brattle principal and paper co-author Peter Fox-Penner. A malicious actor with access to hundreds of BESS sites could shut them down unexpectedly, which could propagate a blackout. “You’ll surprise the grid operator. They won’t have enough reserves, and the supply-demand balance will be disrupted.”

Fox-Penner went on to say that a sophisticated attacker might attempt to oscillate the batteries slightly above or below the normal operating frequency by controlling the power inverters. Oscillations in the grid can create disruptions. The Iberian Blackout this year was caused partly by mismanaged grid oscillation and voltage dynamics. (See European Regulator Issues ‘Factual Report’ on Iberian Outages.)

Tonkin said BESS systems could become compromised when they are “overly connected” to the internet. The paper highlights various components of storage systems as particular security concerns. The Battery Management System, a combined hardware and software package, is a potential vector for cybersecurity threats. In some BESS, power conversion systems also are a potentially troubling spot. If improperly protected, these components create “attack surfaces” for cybersecurity threats to exploit.

“Electric infrastructure has for a long time been the No. 1 target of state actors trying to disrupt infrastructure,” Tonkin said during a recent webinar. Dragos has been tracking groups attacking Ukrainian substations, and they have evolved from exploiting vulnerabilities of specific facilities to using more “IT-based” attacks, he said.

Cybersecurity Hygiene

Fox-Penner and Tonkin recommend that owners and operators of BESS audit software and hardware to know all the components of their systems. They should use a software and hardware “bill of materials” to verify that all components of a BESS are produced by trusted parties and meet functional requirements. Software bills can also be used to identify unnecessary packages and programs that may inadvertently increase the vulnerability of a battery system.

Beyond this, establishing appropriate communication segmentation on-site, creating and maintaining firewalls, and establishing secure remote access need to be priorities to secure a battery system. Hardware, software and network safety measures need to be taken proactively rather than retroactively, they said. Establishing secure supply chains also is critical for maintaining grid safety.

“There’s tremendous growth in the battery installed base over the next five years,” Fox-Penner said. “This is our chance to, say, vaccinate it before it gets installed when it’s more effective and cheaper to do.”

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Permitting Bill Runs into Difficulty Involving Offshore Wind

U.S. House Republicans’ central contribution to Congress’ infrastructure permitting reform push, the SPEED Act, ran into at least a partisan pothole as a deal over presidents reversing their predecessors’ permit approvals was upended in the Rules Committee.

The bill advanced out of the House Natural Resources Committee with some bipartisan support in November, and issues around presidential permit reversals already proved difficult to deal with then. (See House Natural Resources Committee Advances Permitting Bills.)

The deal struck in committee was that presidents no longer could reverse permits approved by prior administrations. For many Democrats, that was not enough because it would do nothing to salvage major offshore wind and other projects that President Donald Trump has upended or could before signing the bill into law.

Some Republicans felt even that restriction on presidential power went too far. Rep. Jefferson Van Drew (R-N.J.), who represents a district covering most of New Jersey’s coast and has long been an opponent of offshore wind, got an amendment passed specifically exempting offshore wind projects from that part of the bill.

“I support real permitting reform, and the SPEED Act does a lot of good things to unleash our energy potential,” Van Drew said in a statement. “But as it was previously written, it would have permanently protected offshore wind projects that were forced through the permitting process under the previous administration. I could not support that. After lengthy and deliberative discussions on the House floor, the amendment we secured today makes a critical change. It protects actions to terminate offshore wind permits and leases.”

Without the language around offshore wind companies, Van Drew said he would keep working with the Department of Interior to revoke offshore wind leases altogether.

While winning over Van Drew and other conservatives, the amendment led the American Clean Power Association to withdraw its support of the bill, it said in a letter to House leadership. Other groups influential with Democrats such as major environmentalist organizations were against the bill already, or neutral on it.

“Our support for permitting reform has always rested on one principle: fixing a broken system for all energy resources,” ACP CEO Jason Grumet said in a statement. “The amendment adopted last night violates that principle. Technology neutrality wasn’t just good policy — it was the political foundation that made reform achievable. Chairman Westerman’s original legislation demonstrated that Congress could move beyond stale energy debates. It’s disappointing that a partisan amendment in Rules Committee has now jeopardized that progress, turning what should have been a win for American energy into another missed opportunity.”

Without permitting reform, energy prices could spike and grid reliability deteriorate, he said, adding that ACP looks forward to working with Senate leaders to restore a balanced, technology-neutral approach that can become law.

The American Council on Renewable Energy released a statement thanking Natural Resources Committee Chair Bruce Westerman (R-Ark.) for his work on the SPEED Act.

“Durable, bipartisan, technology-neutral permitting reforms that support and advance the full suite of American electricity resources and the necessary expansion of transmission infrastructure to get that electricity from where it’s generated to where it’s needed are essential to meeting that challenge reliably, securely and, most importantly, affordably,” ACORE CEO Ray Long said in a statement. “Unfortunately, the changes made on the House floor are a disappointing step backward from achieving these objectives.”

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ICF Paper Shows Where New Data Centers Can be Sited Quickly

Determining where to build new data centers is increasingly high stakes and complex with developers having to navigate electric grid infrastructure, fiber optic cables, environmental requirements and government policies.

With speed to power the paramount goal of developers, ICF International released a paper Dec. 17 titled “How to find the ‘sweet spots’ to build all those data centers.”

“It really is a synthesis of all the siting support work that we’ve been doing, really in the last decade or more, for our energy asset developer clients, and we have leveraged that experience in the last year and a half to support data centers,” ICF Vice President of Energy Markets and report co-author Himali Parmar said in an interview.

Before the recent growth in data centers, ICF’s main siting practice was focused on renewables and battery storage, and the two practices share some commonalities, Parmar said. Wind or solar facilities need a lot more land than data centers, but battery storage facilities have comparable footprints.

“Access and availability of the grid to accommodate you is extremely important, and it is common between energy assets and data centers,” Parmar said. “I’d say, amongst all the factors that we review for energy assets versus data centers, optical fiber was one thing that’s a new layer that we included as we develop the data center siting module. And the second one, [which] was not as important for renewable assets, was the gas infrastructure.”

Solar and batteries do not need access to natural gas infrastructure, but many data centers need pipelines nearby so they can be assured of reliable, around-the-clock power, she added.

Energy typically carries the most weight in siting data centers because of their huge demand for power, which means parcels need access to electricity, the local grid needs some headroom for new demand, and the grid needs to be stable enough to ensure operational stability, the paper says.

“Historically, securing supply through interconnection to a utility-owned electric grid is the preferred choice for data center developers,” the paper says. “It provides the necessary level of reliability, has generally been sufficiently timely and does not require the data centers to have to undertake potentially complex and more costly energy management. However, sites where the electric grid has the capacity to serve data centers are disappearing rapidly as electricity demand skyrockets across the U.S.”

Data centers must ask utilities to interconnect to their grid, and it can take months of review that can add up to wasted time if a request is rejected.

“Utilities have an opportunity to offer proactive guidance to data center developers before they formally submit interconnection proposals, publish grid capacity maps for their service territories and publish preferred development zones that identify areas where favorable conditions for development converge,” the paper says. “These sources of information would help developers submit interconnection proposals with a higher chance of success. It would also allow utilities to save time on reviews and effectively plan for grid upgrades.”

The grid already is in a tight situation, with PJM load forecasts out to 2030 showing a reserve margin approaching 0% in some forecasts, Parmar said. That comes on top of well documented issues with the queue, along with supply chain difficulties.

That has some data center developers seeking out access to turbines wherever they can get them to bring facilities online as soon as possible, she added.

“A data center developer is not interested in the business of being an” independent power producer, Parmar said. “However, the challenges that they’re seeing in the grid not being able to give them the megawatts of supply that they need in a timely fashion is really the driver for why folks have started thinking about behind-the-meter power or direct offtakes.”

Behind-the-meter generation is viable only if the natural gas system also has some spare capacity, with the paper noting that pipelines are constrained, and some gas utilities expect new delivery bottlenecks in the next few years.

“Understanding pipeline networks and supply capacity is critical — both for developers considering gas turbines and midstream and downstream gas companies that may need to plan for new demand,” the paper says.

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States Sue Trump Administration to Recover EV Charger Funding

Sixteen states and the District of Columbia sued the Trump administration Dec. 16 in an effort to recover billions of dollars in funding for EV charging infrastructure.

California Attorney General Rob Bonta co-led the lawsuit with Colorado Attorney General Philip Weiser and Washington State Attorney General Nick Brown. Other states joining the complaint are Arizona, Delaware, Illinois, Maryland, Massachusetts, Michigan, New Jersey, New York, Oregon, Pennsylvania, Rhode Island, Vermont and Wisconsin, as well as the District of Columbia.

The complaint, filed in the U.S. District Court in Seattle, accuses the Trump administration of unlawfully suspending two grant programs for electric vehicle charging infrastructure that Congress approved in 2022 as part of the Infrastructure Investment and Jobs Act (IIJA). The programs are the $2.5 billion Charging and Fueling Infrastructure (CFI) grant program and the Electric Vehicle Charger Reliability and Accessibility Accelerator program. Both are five-year programs for building or repairing EV chargers.

The IIJA reserved 10% of the $5 billion appropriated for the National Electric Vehicle Infrastructure (NEVI) program for the Accelerator program, which provides grants to states or local governments that need extra help to deploy EV chargers.

The states allege the U.S. Department of Transportation has refused to approve any new funding under the two programs, without any explanation or notice.

The complaint says the Trump administration’s refusal to spend the appropriated EV charger funds is unlawful because it violates the separation of powers and the Administrative Procedure Act. The complaint asks the court to declare the defendants’ actions unlawful and to permanently stop the administration from withholding these funds.

“The Trump administration’s illegal attempt to stop funding for electric vehicle infrastructure must come to an end,” Bonta said in a release. “This is just another reckless attempt that will stall the fight against air pollution and climate change, slow innovation, thwart green job creation and leave communities without access to clean, affordable transportation.”

The complaint follows legal action taken by states earlier this year seeking the release of funding for the NEVI program. In June, the court found that suspension of the NEVI funds was likely unlawful and granted the plaintiff states’ motion for a preliminary injunction.

In August, Transportation Secretary Sean Duffy issued guidance for states to claim the NEVI funding. (See DOT Issues Guidance to Resume NEVI Funding.)

Environmental Groups Sue

In a separate action on Dec. 16, environmental organizations filed a challenge to the Trump administration’s hold on $2.5 billion in federal funding through the CFI program. The groups include the Sierra Club, Climate Solutions, Natural Resources Defense Council and Earthjustice.

The lawsuit seeks to unfreeze more than 140 EV charging grants totaling nearly $1.8 billion to state and local agencies and tribes. Transportation projects across the country are in jeopardy because of the funding freeze, the groups said.

“If this Congress-approved money isn’t used, it disappears — exactly what the Trump administration is hoping will happen,” Sierra Club Senior Attorney Zachary Fabish said in a release. “We won’t let the Trump administration sit on it any longer.”

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FERC Clarifies Cold Weather Standard Approval, Effective Date

FERC has clarified the reporting requirements of its Sept. 18 order approving NERC’s most recent cold weather standard as the ERO requested in October, while also answering a clarification request from a group of trade associations on the commission’s authority to set the effective date of the standard (RD25-7).

FERC approved EOP-012-3 (Extreme cold weather preparedness and operations) at its September open meeting, ordering that it take effect Oct. 1, less than two weeks later. (See NERC Cold Weather Standard Gains FERC Approval.) NERC had requested that the standard take effect at a later date, but commissioners said the Oct. 1 deadline would allow the standard to be enforceable before the coming winter and argued that registered entities should already be aware of the coming new requirements because the process was public.

In its approval order, FERC directed the ERO to collect and submit informational filings every two years starting no later than October 2026 and ending in October 2034. The filings must include:

    • the number of cold weather constraint declarations submitted to each regional entity;
    • the number of declarations approved, and their aggregate megavolt-amperes; and
    • a summary of the rationales provided for approved declarations.

NERC told the commission Oct. 17 that it does not currently analyze generating units based on megavolt-amperes but on their real power in megawatts. It asked whether reporting the aggregate megawatts would be sufficient. The ERO also asked whether it could consolidate the biennial filings for EOP-012-3 with the annual filings that FERC directed in its approval order for the prior standard EOP-012-1, observing “significant overlap in some aspects of the information” to be collected in each order.

In its Dec. 5 response, FERC clarified that it ordered NERC to report the aggregate megavolt-amperes “to help the commission understand the reliability risk … from a generator cold weather constraint.” FERC added that it was “persuaded by NERC that collecting real power data [in megawatts] is a reasonable alternative” and gave it permission to use that information in its filings.

The commission then addressed NERC’s question about the EOP-012-1 filings, stating that the biennial filings for EOP-012-3 “build upon” the annual filings and were intended to supplement them. FERC therefore agreed that NERC could consolidate the filings as it suggested. It also clarified that the 2034 sunset date for the biennial filings would apply to the consolidated filings overall, meaning that the ERO would not have to continue the EOP-012-1 filings after that date.

Associations’ Request Denied in Part

A group including the American Public Power Association, Electric Power Supply Association, Large Public Power Council, National Rural Electric Cooperative Association and Transmission Access Policy Study Group (filing as the Joint Trade Associations) asked for clarification on the commission’s authority to set Oct. 1, 2025, as the effective date for EOP-012-3.

The associations wrote that they did not object to the Oct. 1 date, but they pointed out that the implementation plan for the standard said that if it was approved after July 1, 2025, the standard would take effect Jan. 1, 2026. They further observed that the Federal Power Act requires FERC to remand a standard to NERC for further consideration if the commission concludes that it is “not just and reasonable.”

Asserting that NERC’s Rules of Procedure call the effective date “a mandatory and enforceable component of” a standard and that the commission sees the “effective date(s) [as] an element … in determining whether a … standard is just and reasonable,” the associations requested clarity on FERC’s authority to change the date. Specifically, they asked whether the commission “acted based on [language] in the proposed implementation plan specifying that [EOP-012-3] could become effective ‘as otherwise provided for by the applicable governmental authority.’”

In its response, FERC affirmed it “relied on” the language the trade associations cited in establishing the Oct. 1 date. However, it went on to write that NERC’s ROP “do not apply to the commission or otherwise limit commission actions.” They also cited FERC’s “policy that the requirements [of a standard] are [its] essential, substantive language … and that the commission can direct revisions to compliance-related provisions … without a remand.”

As a result, FERC denied the clarification request “to the extent it suggests that the commission lacked the authority to alter the effective date without remanding the standard to NERC,” despite answering the associations’ question about language in the implementation plan.