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.
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.”
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.”
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.
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 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.”
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.
FERC has approved an SPP tariff change that adds real-time dispatchable interchange transactions to its Integrated Marketplace, extending the current day-ahead market dispatchable transaction model into the real-time balancing market.
The commission said in its Dec. 10 order that the proposed design will allow more economic dispatch by enabling price-sensitive, dispatchable interchange transactions in the real-time market. It directed SPP to make a compliance filing establishing the effective date, currently set at a placeholder of Dec. 31, 9998 (ER25-2753).
The RTO’s Market Monitoring Unit and the Western Area Power Administration both protested the tariff change, saying it could result in market harm through structural market power and transmission withholding. WAPA added that the lack of offer validation for real-time dispatchable transactions (RTDTs) beyond a $2,000/MWh cap could lead to market power.
FERC found the protests alleging market power issues to be “speculative.” It said the MMU did not provide additional explanation beyond high-level arguments of the behavior or its potential to increase. The commission did note that SPP said it will continue to work with the MMU to address instances of market power and that the Monitor could refer the behavior to FERC.
The MMU said SPP’s proposal would remove barriers to participation in the real-time market and could increase market efficiencies across seams by reducing the real-time price volatility associated with the grid operator’s fixed interchange transactions. It said it couldn’t support or oppose the tariff change due to missing details in the RTDTs.
The marketplace’s participants use the interchange transactions to import and export energy out of the SPP balancing authority area. The transactions can be fixed or dispatchable in the day-ahead market and are only fixed in the real-time market.
WAPA said that while it supports the RTDT concept, it thinks SPP’s proposal will harm reserve levels, intraday-reliability unit commitment and ramp distribution between hourly market products and the proposed RTDTs. The federal power agency said the RTO had not yet shared with stakeholders its proposal to address ramp-capability issues and contended the use of non-firm transmission service and hourly non-firm dynamic interchange scheduling also creates reliability concerns.
FERC rejected the parties’ other protests, including the MMU’s claim that SPP’s proposal was missing key details. “We find that the record before us has sufficient information for us to render a decision on the proposal,” the commissioners wrote.
Commission Nixes Accreditation Rehearing
In a Dec. 12 order, FERC rejected rehearing requests by several public interest organizations (PIOs) and clean energy associations over its approval of SPP’s modifications on capacity accreditation (ER24-1317, ER24-2953).
Citing the court decision in Allegheny Defense Project v. FERC, the commission said the requests may be deemed denied by operation of law. However, FERC modified the discussion in the accreditation order and continued to reach the same result in the proceeding.
The commission in July approved SPP’s performance-based accreditation (PBA) for conventional resources and effective load carrying capability (ELCC) methodologies for traditional and renewable resources, respectively. (See “ELCC, PBA Methodology Approved,” FERC Approves SPP’s ERAS Process, Accreditation.)
The PIOs and clean energy groups argued FERC erred in the order by relying on its finding that the proposed accreditation methodologies would be improvements over the status quo. They said the commission accepted a proposal that is unduly discriminatory and accepted revisions that provided an insufficient amount of detail on the loss-of-load expectation (LOLE) model, violating the rule of reason.
FERC agreed with the protesters that “mere improvement” over the status quo is “insufficient to render a tariff filing necessarily just and reasonable.” It said it instead found and continued to find that the proposed accreditation methodologies are just and reasonable under the Federal Power Act’s Section 205 standard.
The commission also said it found that SPP’s revisions provide a “sufficient level of detail” on the use of the LOLE study under the rule of reason.
WASHINGTON — Data center developers’ imperative of speed to market not only stresses the power grid but also is felt on the ground as the giant facilities — often paired with onsite generation — spring up in neighborhoods overburdened with pollution.
Infrastructure developers often pick “communities of least resistance” that usually are low-income and often minority-majority, NAACP CEO Derrick Johnson said at a summit his group hosted to develop strategies to ensure the wave of data center development in the U.S. does not overwhelm communities where they are sited.
“Data centers will exist, unfortunately,” Johnson said. “We know this. The real opportunity here is, how do we collaborate and establish best practices for their existence so they’re not predatory in nature, on our environment, our communities and our quality of life?”
The NAACP has organized against xAI’s Colossus data center in Memphis, which went online this year using unlicensed, onsite gas generation in a city that had some of the worst air quality in the region, according to a letter threatening to sue the firm run by Elon Musk.
“Part of the reason why we’re seeing that kind of thing happen in certain communities is because of the wait in order for them to actually get the energy that they need, and so then they’re trying to find these quick fixes in order to get their data center up and running as quickly as possible,” said Abre’ Conner, director of the NAACP’s Center for Environmental and Climate Justice.
In debates around the massive data center, Tennessee state Rep. Justin Pearson (D) often hears that opponents are just “NIMBY” people.
“And I say we’re not that in the way that you think. We’re ‘NIMBY again’ — not in our backyard again,” Pearson said. “Eighty percent of the pollution that comes out of Shelby County is concentrated in the district that I represent today.”
Data centers and other infrastructure often get sited in poor, minority neighbors because the developers think it will be easy, Pearson said.
“One of the things that really ignited the movement was the company literally said: ‘We chose this community because it’s the path of least resistance,’” Pearson said. “And when they looked at the historicity of our communities, that was a story that was being told. They looked at the fact that we had been red-lined, and that the same places that were red-lined became the same places where industrial parks were placed. And so now in this country, 75% of Black, African American or Latino folks live within three miles of a toxic release inventory facility.”
But organizing can counteract that, as Pearson, who is running for the U.S. House next year, pushed back against the Colossus facility and its impact on Memphis. Now xAI is building another massive data center in Southaven, Miss., just outside Memphis in a largely white area.
“They are buying these tools to check the decibels of sound because they’re so close to the turbines, they can hear it inside their homes, and when they go outside, it nearly doubles,” Pearson said.
While the two communities might have their differences, they both are pushing back against the same opponents.
“I’m working with some Republicans who don’t want to see more datamining, don’t want to see more cryptomining, don’t want to see a data center in their own neighborhoods,” Pearson told reporters. “And so, one of the principles that I’m operating with is we have to find common ground without compromising our values. And this is one of the issues where I think we’re going to find common ground across the political spectrum.”
Pearson is running a primary campaign against Rep. Steve Cohen (D-Tenn.), who has held the seat since 2007, and if he gets into office next Congress, he’s ready to propose some broad outlines for federal legislation around data centers.
“We really need to prioritize transparency, siting [and] health protections for the people who are really suffering right now with the way that many data centers are operating,” Pearson said. “I’m hearing stories every single day from communities where the water is disappearing because of these companies, the air is being polluted and communities are being locked out of the conversation. That’s not fair.”
‘Seat at the Table’ for Communities
While data centers are going up around the country wherever they can get access to the grid, fiber-optic networks and other needed resources, the largest market still is Data Center Alley in Northern Virginia, in the suburbs of Washington, D.C.
In that region, denser development has taken shape near Metro rail stations, and that was the plan for the Silver Line that connects Dulles Airport to the city, said Karen Campblin, chair of the Environmental and Climate Justice Committee of the NAACP’s Virginia State Conference.
“Loudoun County developed a long-range plan that was supposed to complement this to the extension of the Silver Line Metro rail,” Campblin said. “AOL headquarters closed down, and so it was a large swath of land that could be redeveloped, and they identified it as this wonderful mixed-use community. It was going to have affordable housing.”
Instead of new housing and commercial spaces, the land was snapped up by data center developers, so the region now has a new metro station in an area where few people live. Campblin noted that a multi-story car park tied to the station was largely vacant at rush hour recently.
“One of the trends that we’re seeing is localities losing their opportunity to follow their long-term goals,” she added.
The growth around Data Center Alley was intentional as Virginia and the region attracted the businesses with tax incentives and other enticements in the early 2000s, said state Delegate Karen Keys-Gamarra (D).
“They say, if you build it, they will come,” Keys-Gamarra said. “And they have certainly come.”
Keys-Gamarra represents Fairfax County, and she noted that its neighbors in Loudoun County have benefited from data center development in their tax bills, paying about 80 cents per $1,000 worth of real estate compared to $1.30 per $1,000 in her county.
“It creates so much money for the locale,” Keys-Gamarra said. “But now we’re being forced to try to figure out what is the impact on everyone around it.”
U.S. Rep. Jennifer McClellan (D-Va.) now serves in Congress, but during her time in the Virginia legislature she was one of the main sponsors of the Virginia Clean Economy Act and was a chief backer of the Environmental Justice Act, which was the first time the commonwealth looked into those issues.
“What does environmental justice look like?” McClellan said. “How do we ensure that more people have a seat at the table for zoning decisions, permitting decisions, whether it’s data centers, energy projects, you name it?”
Communities were interested in the tax and other benefits from hosting these major facilities, but residents often did not find out about development plans until it was too late to influence them, she added. Data centers are inevitable, with everyone using the internet requiring their expansion.
“That is a fact of life we’ve got to come to terms with,” McClellan said. “But that doesn’t mean that we can’t be thoughtful about how, where, when data centers are built, how they are operated, how they use energy, how they use water, and where they go. And we’ve got to make sure that the public has a seat at the table at the beginning of the process, not in the middle or at the end.”
‘Disturbing Trend’
Data Center Alley has been a major driver of increased demand in PJM, which has contributed to much higher capacity prices in recent auctions. But the RTO is home to plenty of other smaller data center markets, including the area of southern New Jersey (Exit 1 off the New Jersey Turnpike) that Assemblyman Dave Bailey (D) represents.
“What happens in Virginia affects my folks in New Jersey,” Bailey said. “What I’m doing in New Jersey or not doing in New Jersey affects my cousins in Delaware and Maryland and Ohio and different places across the country. So, it’s important that we keep our eye on the goal.”
Rising costs and narrowing reserve margins have led to calls for reform at PJM, and while Bailey welcomes those, he said the RTO already has made improvements in terms of responding to state concerns. (See Governors Call for More State Authority in PJM.)
“If you look at the minutes of their meetings and their various meetings they’ve had recently, they’re just a different tone,” Bailey said. “There is more transparency. It’s not perfect yet. We’ve got to continue to fight for that, and I fully agree that we need to continue to look at their overall voting procedures and how they make decisions at the various committee levels.”
Ultimately, FERC is the main regulator of PJM, and McClellan said she worries about the agency’s independence.
“Right now, I don’t think FERC has the ability, because of how many federal employees have been fired,” McClellan said. “Trump fired the chair of FERC for no reason, and Congress is not doing its oversight job as strongly as it should be. And so, I think we’ve got to make sure we have a robust federal oversight role of all of the grid operators.”
The situation FERC faces has played out in the states, where legislators often get involved in ratemaking decisions. The NAACP event was held four days after the Supreme Court heard arguments in Trump v. Slaughter, which could lead to the end of independent regulatory agencies at the federal level. (See Supreme Court Justices Seem Skeptical on Agency Independence.)
McClellan pointed to what she called a “disturbing trend” in Virginia and other states in which authority that was granted to expert-driven public utility commissions a century ago is being stripped away.
“Too much of that authority is taken away and given to legislators that are part-time generalists, and to me, that has been one of the biggest problems in electric rate regulation at the state level, and we’re beginning to see it at the federal level,” she said.
When surging seawater inundated Con Edison’s 13th Street substation during Superstorm Sandy in 2012, explosions lit up the New York City sky. As control room staff were being rescued by boat, a million people in its service area were left in the dark, five times as many as the previous high from Hurricane Irene just a year earlier. If water and electricity are a bad combination, salt water and electricity are worse.
As part of a billion-dollar resilience program, it took nearly a decade and $180 million for ConEd to harden that substation to withstand future storms, elevating the control room two stories, installing corrosion-resistant fiberglass components, and adding retaining walls and floodgates.
Storm surge events like Sandy offer insights into what the worst of sea level rise may do to an area’s infrastructure and how the power industry needs to think about this slow-moving but inevitable threat.
It’s easy to think of sea level rise as a subtle and future challenge: After all, sea level rose by only 0.14 inches per year from 2006–2015. However, that was 2.5 times the average annual 0.06-inch rise throughout most of the 20th century. In total, the seas have risen 8 to 9 inches since the late 1800s, when Edison was building his first power plants.
Even looking at a 30-year time frame, the threat sounds concerning, not catastrophic. If you play around with NOAA’s sea level rise map and look at what the estimated rise by 2050 will do, it’s hardly Water World. The scariest numbers — if all of Antarctica’s up-to-three-mile-thick ice were to melt, global sea levels would rise by around 200 feet, and Greenland’s ice sheet would add an additional 23 feet of sea level rise — aren’t forecast this millennium.
Estimates for sea level rise in 2100 range from 16.9 inches higher than today’s sea level as the median in a low-emissions scenario to 33.1 inches as the medium high-emissions scenarios and 43.3 inches in the upper likely range for that scenario. | ICPP
But 2050? The next 30 years see an additional 8- to 10-inch rise if the midpoint of climate scenarios plays out. There’s little evidence, however, that policy changes and demand spikes won’t send us stumbling into poorer climate scenarios. Worse: The high-emissions scenario adds a couple of inches to that estimate. Worst: The Antarctic ice sheets join the party.
The real concern is when we look out to the end of the century, and in an industry that builds infrastructure that’s expected to last into the 2100s. That’s where we should be focused. While most scenarios range from 16 inches to three feet in rise over today’s sea levels, some threats could add significantly to that. Most concerning is the potential collapse of Antarctica’s Thwaites Glacier (or, as his friends call him, “Doomsday”), which not only holds enough ice to raise sea levels a couple of feet, but also is the stopper holding back much of the massive West Antarctic Ice Sheet.
Sea levels rise not only because ice caps and glaciers are melting, but also because the oceans expand as they warm. There’s also displacement as land held down by the weight of ice rises as that ice thins.
All Coasts are Not Equal
It’s easy to assume sea level is, well, level in the same way a water level finds equilibrium. But the global mean sea level is just an average. The coastal impact will vary significantly, based on how the earth rotates, how the oceans flow and how tectonic plates are moving; it’s why the Pacific Ocean side of the Panama Canal is eight inches higher than the Atlantic side.
For the United States, NOAA’s model predicts the Gulf coast will rise 14 to 18 inches by 2050 and the East Coast from Virginia to Maine will rise 10 to 14 inches but the Pacific Coast will rise only 4 to 8 inches. This means infrastructure owners have to plan and prioritize their upgrades using detailed local projections.
The NOAA mapping tool uses mean higher high water (MHHW), not mean sea level, as the starting point, as it represents the elevation of the normal daily tide movements where the shoreline normally is inundated. The MHHW is the high point of “normal.” If the MHHW rises, not only is the daily sea level higher, but also king tides and storm surges start from a higher baseline.
Oh, We Do Like to be Beside the Seaside
Face it: We love the ocean. More than swimming in it or gazing at it, we love shipping goods across it, cooling power plants with it, sucking oil out from under it and reclaiming it to expand cities.
All of this commerce means coastal cities and counties are home to more than a third of Americans. The result: while around 13 million homes are at risk of flooding in the upper end of NOAA’s regional scenarios, the infrastructure many millions more depend on is at risk. That infrastructure ranges from airports (12 of the nation’s busiest airports have runways at risk of storm surge) to hospitals to water treatment plants.
The energy sector is no exception: Many power plants, substations and transmission corridors were historically sited near water for cooling and logistics. These assets may be damaged by storm surge, tidal flooding and erosion. Additionally, buried cables, conduits, control systems and transformers near the coast are at risk of saltwater intrusion as groundwater rises.
Asset owners will need to invest in moving, raising or otherwise hardening those coastal assets if they are to maintain service reliability and manage the cost of insuring those assets.
Substation by the Sea
More than 150 substations are expected to be heavily affected by flooding twice or more annually by 2050 | USC Study
A significant number of energy assets are built by the shore: 2,681 power stations and 8,750 substations, according to the Union of Concerned Scientists (UCS). The UCS study looked at all critical infrastructure: power and substations, public safety and health facilities such as hospitals and fire stations, educational institutions, public and affordable housing, industrial contamination sites, and government facilities.
Some states have significantly more critical infrastructure at risk than others, with Louisiana (334) and New Jersey (304) most at risk by 2050 under a medium sea level rise scenario. As time goes on, Florida leaves all other states behind, and by 2100, it has more than three times the number of critical infrastructure assets (4,599) at risk than any other state under the high sea level rise scenario.
In terms of the energy sector, by 2050, 151 electrical substations are likely to be heavily affected by flooding at least twice annually under a medium-sea-level-rise scenario. By 2100, more than 1,000 substations and 240 power plants are at risk of monthly flooding under a high-sea-level-rise scenario.
Companies with assets near the coast can explore the interactive map to discover which critical infrastructure assets in are at risk.
Preparing to be High and Dry
The IEEE model for wildfire preparedness discussed earlier in this series includes three lines of defense: prevention, mitigation and proactive response, and recovery preparedness. Sea-level rise needs a similar approach, though in its case, utilities can’t prevent it.
Most actions fall into the second line of defense: mitigating damage by hardening, raising or moving infrastructure inland. ConEd’s post-Sandy upgrades, for example, included “walls to keep water out of substations, submersible equipment that keeps operating even when submerged in salty water, stronger poles and wiring for the overhead system, transformers that can be installed quickly and other measures,” a spokesperson told RTO Insider.
“It also included the reconfiguring of two electric networks in Lower Manhattan, allowing us to shut off service (due to flooding) to customers near the coast while leaving the customers located more inland to stay in service.
“We estimate that the upgrades made since Sandy have prevented more than 1.2 million outages.”
In some areas, there’s a tradeoff to consider: Do you lessen the chance of wind damage by undergrounding assets, or does that increase their chance of being damaged by sea level rise? And, as with any emergency, having islandable backup power for hospitals and other critical infrastructure will improve safety and resilience.
For grid and power plant owners and operators with assets in coastal areas, the only good news about sea level rise is that it’s relatively predictable and there’s time to act. While it may not save assets from storm surge as named storms become more frequent, there is time to prepare for 2050- and 2100-level sea levels.
Preparation Starts with Data
Infrastructure upgrades start with good modeling to understand what’s at risk. Just like with other climate-exacerbated disasters, asset owners shouldn’t base plans on outdated FEMA maps; utilities need forward-looking, climate-adjusted models that include groundwater rise and compound flooding. And given the expected variation in sea-level rise along coasts, local studies are critical, particularly for major cities.
While watching Ken Burns’ “American Revolution” recently, I was surprised to see a map of Boston that looked nothing like the Boston I know. Today, it has a significant amount of reclaimed land; half the city is built on landfill and earth moved from hills flattened after the tea went into the harbor. As a result, a lot of its important infrastructure is at sea level. As RTO Insider’s Jon Lamson reported last year, a report delves into the local impacts that could be felt, and it’s a solid starting point for prioritizing upgrades.
Similarly, following the big freeze in Texas, the state’s regulators, ERCOT and state emergency management officials mapped its critical infrastructure to ensure better coordination in future emergencies.
For areas that have no granular studies, the NOAA tool offers a range of local scenarios that map low, intermediate and high projections up to 2100 and that can be overlaid onto existing infrastructure maps.
Along with physical preparation, utilities need to incorporate climate projections into integrated resource planning (IRPs) and state PUCs need to align requirements with future climate risks, not historical conditions.
“We went to our regulator and got approval to invest $1 billion to fortify our energy systems against extreme weather,” the ConEd spokesperson said. “Fortifying the energy systems against extreme weather is now part of our ongoing planning and investing.”
Regulators in areas that haven’t had a Superstorm Sandy-style wakeup call would be well-served by helping utilities invest in fortification before a similar crisis strikes.
The Calm Before the Storm
Proactive response is critical, especially for storm surge, which is sea level rise on steroids. With larger storms and the surge starting from a higher baseline, the threat is amplified compared to past storms.
It’s not feasible to move or harden all infrastructure that could be affected by storm surge, but acting ahead of a storm can minimize damage. When storm surge is expected, powering down at-risk infrastructure may inconvenience customers, but ultimately leads to shorter blackouts and less equipment damage, as shown in Superstorm Sandy when Brooklyn’s Farragut substation was proactively powered down hours before the 13th Street substation was involuntarily powered down by sea water. Farragut was deenergized when it was inundated, and equipment was quickly dried and power restored by noon the day after the storm.
The third line of defense, recovery preparedness, is essential as well. It’s an investment that will pay off across all types of crises. For example, ConEd’s hardening program included buying 110 bucket trucks and staging them an hour outside of Manhattan, so crews flown in from other states can be deployed rapidly for future recovery efforts.
No Utility is an Island
Sea level rise will affect many types of coastal infrastructure, so coordinated plans should be developed to use construction projects. It is planning that should be done at the state or national level, though many states still are using 20th-century assumptions for 21st-century risks.
Some measures, such as building sea walls, may help entire cities and their infrastructure. But seawalls are expensive and not an option in many areas due to geography or geology. Miami, for example, is built on porous limestone, so a barrier around the edge would do nothing to stop the water from seeping up through the ground in low-lying areas. Parts of Miami already experience sunny-day flooding during high tides, and some are suggesting it’s time to talk about managed retreat. But as one of the most vulnerable cities in the country, Miami’s been proactive in assessing its risk and planning a coordinated response. Its Sea Level Rise Adaptation Plan provides a complete, though sobering, look at everything needed to keep Miami inhabitable as the seas rise.
For many utility upgrades, it will be more cost-effective to coordinate with other services that need to be hardened than to have all affected infrastructure owners prepare piecemeal for the coming sea level rise.
Physics, not Politics, Must Guide Us
The grid and power system must be redesigned for the coastline we will have, not the one we remember. The physics of rising seas is not negotiable. While storms will give us a taste of how damaging rising sea levels can be, there is time to prepare for the everyday sea-level rise that utilities and grid operators in coastal communities will face.
Utilities, regulators and policymakers must treat this as an engineering and planning challenge, not a political one. While climate reports are being removed from federal agency websites, leaders in affected communities know they can’t afford to waste time debating whether it’s happening and why.
For power plant and grid owners and operators, there’s no simple choice between investing now to avoid catastrophic outages or paying later in dollars and lives. The cost of proactive resilience is massive for a problem of this scale. What is clear is that we must understand where the risks are before we can prioritize where to invest.
The seas are rising whether we prepare or not. The grid needs to rise to the challenge.
In its final meeting of the year, the NYISO Business Issues Committee unanimously approved a motion recommending the Management Committee approve changes to the tariff to update the interconnection agreement between the ISO and Hydro-Quebec ahead of the completion of the Champlain Hudson Power Express.
Stakeholders also unanimously approved a motion recommending the MC approve new tariff revisions to implement the Improve Duct Firing Modeling project, which will accommodate combined cycle generators equipped with duct-firing capability for real-time dispatch.
The committee also heard a market operations report for November. The average locational-based marginal price was $57.14/MWh, $10 more than in October and much higher than November 2024’s price of $35.26/MWh. The average year-to-date monthly cost of power was $70.24/MWh, a 70% increase over that of last year.
Natural gas and distillate prices also rose over the last month. Natural gas rose about a dollar to $3.16/MMBtu in November. Year-over-year natural gas prices have risen 60.6%. Jet Kerosene Gulf Coast rose about a dollar to $16.57/MMBtu, up 8.6% from last year. Ultra Low Sulfur No. 2 Diesel also rose a little over a dollar to $17.91/MMBtu. Distillate prices were up 12.8% year over year.
Operating Committee
The Operating Committee also unanimously recommended the MC approve the tariff changes to facilitate CHPE integration.
Stakeholders also heard and approved a system impact study for a large load interconnection of a data center in the Buffalo area. Digihost, the project owner-operator, is seeking to increase its retail load from 9.8 MW to 60 MW. NYISO found that the project would not cause thermal or voltage issues on the local grid and that no new upgrades would be needed to support the project.
The OC heard a brief presentation of November’s operations metrics. Peak load for the month hit on Nov. 11 during the 5 p.m. hour at 20,325 MW. This set the peak for the 2025/26 winter reliability period so far but was below the all-time record of 25,738 MW set in January 2014. Peak wind occurred on Nov. 28 with 2,338 MW. Combined front- and behind-the-meter solar peaked at 3,510 MW on Nov. 4.
Several notable system events occurred during the month. On Nov. 11, NYISO issued an alert during the 11 p.m. hour and reduced power flows to 90% of ratings because of an intense solar storm. Several elements of the Smart Path Connect transmission project were put in service incrementally throughout the month.
