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March 6, 2025

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Parties Point to Each Other’s Policies as Drags on Meeting Demand Growth

The House Energy and Commerce Subcommittee on Energy held a hearing March 5 to discuss meeting the growing demand for power, with each party’s members claiming the other side’s policies were hindrances. 

Data centers, industrial shoring and other factors are driving up demand now as thermal generation is retiring, subcommittee Chair Bob Latta (R-Ohio) said. 

“Meanwhile, subsidized intermittent energy resources and public policy decisions in favor of renewable energy are flooding interconnection queues and making baseload power from coal, natural gas and nuclear near uneconomic,” Latta said. “Generation developers continue experiencing ongoing supply chains constraints for distribution transformers and generation turbines.” 

The ranking member of the subcommittee, Rep. Kathy Castor (D-Fla.), pointed to recent disruptions in the federal bureaucracy. 

“It’s rather absurd that we’re tackling strengthening our electrical system while Elon Musk and the Trump administration are taking a sledgehammer to the Department of Energy, and especially the initiatives that strengthen and modernize the grid,” Castor said. “The new administration has spent weeks illegally shutting down DOE grants and loans and partnerships that make energy safe, reliable and affordable.” 

The administration’s tariffs on the country’s largest trading partners are making key grid and generation components more expensive, in addition to the higher power prices already being felt especially in northern states, she added. 

While members took shots at their political opponents, both Latta and Rep. Frank Pallone (D-N.J.), ranking member of the full committee, said the growing demand was an opportunity to seize economic growth and keep the U.S. as the leader in artificial intelligence. 

“It means that companies are investing in America,” Pallone said. “The cutting-edge technologies are being developed here, and the families are making investments of decarbonizing their homes and vehicles. These are good things.” 

Basin Electric Power Cooperative CEO Todd Brickhouse said the co-op is experiencing some of the same rapid load growth as other parts of the country. It serves 3 million customers living across 12% of the U.S.’ territory in nine states. 

“Basin is currently increasing its generation portfolio by more than 40%, and we are increasing our transmission mileage by more than 20% over the next decade; we will spend $12 billion on these endeavors,” Brickhouse said. “That compares to currently $8.5 billion of assets on our balance sheet today.” 

Improvements in federal permitting would help get that work done, with Brickhouse recounting how one transmission project required two different assessments from different bureaus under the Department of the Interior. Basin is also adding 1,500 MW of new renewable resources to help meet that load growth. 

“This has required years of planning and development work, and these business decisions were made based on the availability of production tax credits [PTCs],” Brickhouse said. “We understand and we support the need to put our country on a sustainable physical path, but the immediate removal of PTCs will not allow utilities to plan for and avoid increased costs, and this will also immediately harm ratepayers.” 

The tariffs will also make that $12 billion of overall expenditure more costly for ratepayers as Basin recovers the funds from ratepayers over the next several decades, Brickhouse added. 

PJM is seeing load growth driven by new data centers and manufacturing, said Senior Vice President for Governmental and Member Services Asim Haque. 

“PJM expects its summer peak to climb to 220,000 MW over the next 15 years,” Haque said. “To compare, our all-time summer peak, which occurred in 2006, is 165,563 MW.” 

For years, PJM had a healthy reserve margin, but the load growth and some retirements are eating into that now, with the tighter supply-and-demand balance leading to higher capacity prices. With interconnection queue and capacity market reforms in recent years, the RTO has almost caught up with its queue backlog and is about to implement its new system, Haque said. 

“We want as much supply as we can get in order to meet this growing demand, whether that’s delaying retirements, new supply, that supply in our queue and even additional supply on top of that,” Haque said. 

PJM has cleared 50 GW of primarily renewable resources through its queue, which are having challenges related to financing, the supply chain, and state and federal siting processes. Repealing the Inflation Reduction Act and its tax credits for renewables would add financial strains to those projects, Haque said. 

One way the customers behind the new demand could help the situation is by ensuring that they can offer some flexibility to the grid, said Tyler Norris, a James B. Duke fellow at Duke University. 

The average use rate for the grid is just 53%, meaning that almost half of generation is sitting idle at most times, said Norris, the lead author on a recent study on data center load flexibility. (See US Grid has Flexible Headroom for Data Center Demand Growth.) 

“Our analysis finds that with modest flexibility from new large loads, the grid can accommodate significant demand growth without major new infrastructure,” Norris said. “The U.S. power system is already designed to handle extreme peaks and demand, meaning that in most hours, a substantial portion of the power system is unutilized. … 

“Flexible load strategies can provide a bridge, while long-lead resources such as new transmission and clean firm generation are developed.” 

Noel Black, Southern Co. senior vice president of regulatory affairs, argued his firm’s vertically integrated, traditionally regulated model has prepared the region it serves well for the new load growth, in part by completing the new nuclear reactors at Plant Vogtle. 

“Straightforward regulatory models like ours, where the accountability for the grid is clearly understood, are producing results enabling this innovation economy,” Black said. “In short, the Southeast remains open for business. Regions with unusually complex regulatory processes are experiencing slower infrastructure build out. I think this may be why the concept of co-location has become so popular in certain parts of the country.” 

Co-location is a major issue in PJM, where Haque said the RTO would have more to say in 30 or 60 days, as it is currently working to implement a recent FERC order. (See FERC Launches Rulemaking on Thorny Issues Involving Data Center Co-location.) 

The Electric Power Supply Association, which represents independent power producers active in markets and some of which are pursuing co-location deals, released a statement on the hearing arguing that organized markets were poised to meet the growing demand. 

“Appropriately structured competitive wholesale markets can drive innovation and competition and ensure that ratepayers are not exposed to any unnecessary or inefficient investment,” EPSA CEO Todd Snitchler said. “Given the uncertainty surrounding how fast demand will grow in the coming decades, it is critical that investment risk be borne by developers and not shouldered by ratepayers.” 

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ACP Tallies US Clean Energy Surge in 2024

A record 49 GW of clean energy generation came online in the U.S. in 2024, nearly 33% more than in 2023, the American Clean Power Association reported March 5.

Clean energy accounted for 93% of the new capacity added nationwide in 2024, ACP said in its new “Snapshot of Clean Power in 2024,” a condensed preview of the annual market report the trade organization will publish for members next month.

ACP paints a picture of momentum and acceleration of the buildout of U.S. clean energy, which for the purposes of the report is defined as wind, solar and storage.

It took more than 20 years for the U.S. to reach 100 GW of utility-scale clean power capacity, five years to reach 200 GW, then just three years to reach 313 GW.

ACP also repeated the all-of-the-above energy message it has been offering since November, when it became clear that a strong fossil fuel supporter would replace a staunch supporter of renewable energy as president of the United States.

“The only way to meet skyrocketing energy demand is to embrace all American energy resources,” ACP CEO Jason Grumet said in the announcement of the Snapshot. “The clean energy sector’s dominant performance in 2024 demonstrates the unique role clean power is playing in bringing electricity online now to support increased manufacturing and data centers.”

Breaking the 2024 total down into its components, some numbers are more impressive than others. The 33 GW of utility-scale solar and 11 GW of storage installed both far surpassed the previous records, but the 4 GW of land-based wind that came online in 2024 was the smallest amount in a decade.

An ACP map shows 175 MW of U.S. clean energy projects in advanced development or construction at the end of 2024. | American Clean Power Association

And while the single offshore wind farm that came online in 2024 did in fact set a record, it was a minor distinction: It offers only 132 MW, and it was competing against a 12-MW pilot project and a 30-MW near-shore facility that constituted the entirety of the U.S. offshore wind portfolio at the start of the year.

Other facts, figures and highlights from the 2024 Snapshot include:

    • The fourth quarter was the strongest quarter ever for solar installations (nearly 14 GW) and the second largest for clean energy in total (18.8 GW).
    • Onshore wind remains the largest U.S. renewable sector, but solar is closing in fast: 33.3 GW of utility-scale solar was installed, bringing the total to 129.7 GW, while 3.9 GW of new capacity brought the land-based wind total to 154.6 GW.
    • New natural gas generation totaled just 2.4 GW.
    • Nearly 9 GW of generation was retired, with coal- (50%) and gas-fired facilities (43%) accounting for most of the total.
    • Forty states now have more than 1 GW of installed clean power capacity, up from 37 in 2023; a dozen states saw their clean power portfolios increase by 1 GW or more.
    • The pipeline of projects in advanced development or under construction reached 175.2 GW by the end of the year; solar accounted for about half at 89.4 GW, but that was 5% less than a year earlier; battery storage accounted for a quarter of the pipeline at 45.1 GW, which was 49% more than a year earlier.
    • Forty-six clean-energy primary component manufacturing projects came online nationwide, providing $22 billion in direct investment; 85% of those projects were in states that voted for Donald Trump in the 2024 presidential election; and 79 new projects were announced to create or expand production.
    • Clean power generation is operational in 86% of congressional districts; 79% of the total capacity is within Republican-held congressional districts; and 77% of new capacity added in 2024 was within Republican districts.
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FERC Approves ERO’s Energy Assessment Mandates

FERC has approved two new NERC reliability standards that address the risks from energy sources with inconsistent output by requiring utilities to perform energy reliability assessments (ERAs) and develop plans to minimize the risk of any forecast energy emergencies. 

According to the commission’s Feb. 26 letter order (RD25-5), BAL-007-1 (Energy reliability assessments) will take effect on the first day of the first calendar quarter that is 24 calendar months after the effective date of FERC’s order, or April 1, 2027. TOP-003-7 (Transmission operator and balancing authority data and information specification and collection) will become enforceable six months earlier than the other standard. NERC suggested this timeline when it submitted both standards Jan. 6. (See NERC Submits Energy Assurance Standards to FERC.) 

FERC noted that Calpine, Ameren and Public Citizen each filed motions to intervene before the deadline of Feb. 5; however, neither these nor any other party has submitted comments or protests so far. 

Both BAL-007-1 and TOP-003-7 were developed under Project 2022-03 (Energy assurance with energy-constrained resources), in response to weather-dependent resources like solar and wind generators to replace traditional inertial generation. NERC said in its filing that “traditional capacity-based planning methods and strategies may not identify [the] risks” associated with these resources and their inconsistent output resulting from volatility in weather and load. 

BAL-007-1 will require balancing authorities to perform near-term ERAs and create operating plans to identify and minimize the possibility of forecasted energy emergencies. Assessments performed under the standard must review the resources necessary to serve demand while also providing operating reserves for the grid. 

Assessment periods will begin no more than two days after the operating day, and cover between five days and six weeks. The standard allows BAs to specify how often they perform ERAs; all time periods must be covered unless the BA can demonstrate that an ERA is not needed for a specific time period because the risk of an energy emergency is low. 

BAs can perform the near-term ERA for their work areas alone or jointly with other BAs for multiple areas at a time. Minimum elements that must be in near-term ERAs include: 

    • forecast or assumed demand profiles; 
    • resource capabilities and operational limits (including fuel supply); 
    • energy transfers with other BAs; and 
    • known grid transmission constraints that limit the ability of generation to deliver their output to load. 

TOP-003-7 introduces relatively minor updates to TOP-003-6.1 intended to “ensure that [BAs] have the necessary data to perform the [near-term] ERAs” by adding them to the activities for which they “must have documented data specifications to collect data from relevant entities.”  

This requirement is the reason for the gap between the two standards’ effective dates. NERC told FERC in January that staggering them would give entities time to collect the data needed for the assessments required under BAL-007-1. 

FERC’s order constitutes final agency action, the commission said. Requests for rehearing must be filed within 30 days of the order’s issuance. 

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NJ Conference Confronts Electricity Demand Squeeze

GLASSBORO, N.J. — Facing a projected 40% hike in regional electricity demand by 2030, New Jersey needs to rapidly craft a plan on how to boost generation and develop its transmission and distribution system, according to speakers at a Feb. 27 conference on the state’s energy future.

Power demand from data centers and artificial intelligence projects, along with the expected increase in electric vehicle use and building electrification, are driving demand forecasts that project a power shortfall without significant action, industry stakeholders and state officials said at Meeting New Jersey’s Energy Needs, held at and hosted by Rowan University’s Steve Sweeney Center for Public Policy.

The most visible sign of the shortfall was the Basic Generation Service auction held by the New Jersey Board of Public Utilities in February, which will trigger a hike of about 20% in the average residential bill in June.

“It’s a supply-and-demand issue … We need more electrons on the grid,” BPU President Christine Guhl-Sadovy told the conference of about 150 energy executives, government officials and other stakeholders. She added that it is “unrealistic to think that this kind of price shock can be absorbed by ratepayers without impact.”

Yet it is not clear in the current, uncertain political and energy environments where the additional supply to New Jersey, an energy importer, will come from, speakers said. The stalling of the state’s offshore wind projects, and the lack of clarity over the future economics of solar and other forms of renewable energy generation in the face of opposition to subsidies from the Trump administration, could upend the state’s expected reliance on those sources, speakers said. (See NJ Abandons 4th OSW Solicitation.)

“All these trends are evident in New Jersey,” former state Sen. Bob Gordon, a former BPU commissioner, said as he introduced a panel of generation company executives. “And we’re starting to see some real impacts of the supply-demand imbalance.”

NJEDA CEO Tim Sullivan | © RTO Insider LLC 

The disruptions are unfolding amid ongoing warnings by PJM that aging fossil fuel plants are going offline at a faster rate than replacement plants are arriving, and the RTO is struggling to maintain a generation balance.

“The supply-demand crunch has come to us quickly,” said Asim Haque, senior vice president for PJM, who underscored the urgency of the situation by noting that the RTO saw its highest ever winter peak demand this year on Jan. 20, Martin Luther King Jr. Day.

In assessing how to boost generation, states need to understand that different generators have different “capabilities of how they can contribute to reliability on the system,” he said.

The suddenly oncoming demand suggests the state should move cautiously in its rush toward electrification, said Michael J. Renna, CEO of South Jersey Industries, which owns several natural gas distribution utilities in the state.

New Jersey’s heating-fueled winter peak is three times as high as the air-conditioning-driven summer peak, and “the grid, including all the way down to the utility levels, is built for the summer peak,” Renna said.

“You rush to electrification, you’ve got big problems, because neither the grid nor the utility systems are capable of moving that much electricity, let alone the fact that we have a generation cap,” he said.

He suggested the state instead focus on decarbonization by using gas with lower carbon content that can be used on existing infrastructure, such as “renewable natural gas or green hydrogen that can safely be blended with the geologic natural gas.”

Tim Sullivan, CEO of the New Jersey Economic Development Authority, which funded much of the state’s offshore wind initiatives, said he continues to believe that the economic and employment benefits of wind generation, and the escalating pressure to add supply sources, will return wind to the fore.

“We are not giving up on wind,” he said. “One of the reasons I’m confident in that is that we actually are seeing, outside of Jersey, progress in offshore wind projects. You’ve got electrons that are flowing in Virginia, New York and Massachusetts that are hitting their grids.

New Jersey BPU President Christine Guhl-Sadovy | © RTO Insider LLC

“It’s very hard to disabuse me of the notion that the best way forward for New Jersey” is to address the supply-demand imbalance with offshore wind, he said.

Nor is the state going to shy from the energy challenge presented by the demands of AI projects, Sullivan said.

“AI across the country, across the globe, is going to be an energy monster,” he said. He acknowledged that AI projects need “hundreds of megawatts to a gigawatt of power, and they need hundreds of acres of space,” both of which are limited in New Jersey.

Nevertheless, Gov. Phil Murphy is “smartly positioning the state to be a leader, not a follower, in AI,” Sullivan said. He noted that the state recently launched a program that will award $500 million in tax credits to support AI infrastructure and cited the example of a $1.2 billion state-of-the-art data center planned by CoreWeave. The company signed a lease in October on 280,000 square feet of space at the former global headquarters of pharmaceutical giant Merck in North Jersey.

Harnessing Existing Infrastructure

Hanging over any solution that helps boost generation is how to overcome the challenging task of connecting a project to the state’s transmission and distribution system, speakers said. That includes the well known delays with PJM’s generator interconnection queues.

In addition, all of the state’s four utilities, to varying degrees, have areas where projects cannot be connected because the infrastructure cannot accept them, said Lyle Rawlings, president of the Mid-Atlantic Solar & Storage Industries Association (MSSIA).

“That’s the big bad problem that we’re facing. It’s already putting tremendous downward pressure on our ability to deliver solar in this state,” he said.

The issue was a major factor in the drop in installed solar capacity in 2024, he said. BPU figures show installations were 40% below the 2023 level even as the state reached a milestone of 5 GW of installed projects.

Still, Rawlings said, the state is “on track” to reach its goal of 17 GW of installed solar power by 2035, and MSSIA modeling shows that by then it could account for 24.5% of New Jersey’s electricity, with nuclear contributing 34%. (See Struggling NJ Solar Sector Evaluates Net-metering Reform.)

Former Commissioner Gordon suggested that part of supply could be swiftly increased by connecting grid-scale battery storage through the infrastructure left behind by now closed generating facilities.

Sam Salustro, Oceantic Network (left), and MSSIA CEO Lyle Rawlings | © RTO Insider LLC 

“The task of getting the PJM approval for a battery storage facility located at an old fossil fuel generating plant could take much less time than a brand new project,” he said. “I mean, maybe 90% of the analysis has already been done, and you’re not likely to encounter the political pushback from building something new in an area that might affect the neighbors, because people been living with this generating plant for decades.”

PJM’s Haque said the RTO is awaiting the result of an application to FERC to grant approval in such a situation. He said PJM also has sought permission to grant accelerated approval to projects that pair a generating facility that already has been approved with a battery storage project.

“It’s about trying to expedite resources,” he said. So an approved solar project could be paired with storage, enabling the batteries to “produce during periods where that solar unit can’t produce” and without forcing the storage operator to “go through the queue.”

Leveraging the Footprint

A similar strategy of harnessing “surplus interconnection opportunity” could be adopted by upgrading the state’s existing solar projects, said Lawrence Barth, director of corporate strategy at NJR Clean Energy Ventures, an energy project developer and operator.

“We ought to be thinking about how do we leverage that footprint now that we’ve got panels that produce two to three times that amount than when they were originally installed, at lower cost,” he said.

Several speakers suggested the state consider boosting generation by adding to the nuclear fleet in South Jersey, the Salem 1 and 2 plants and Hope Creek, which are operated by Public Service Enterprise Group and generate about 40% of the state’s electricity. They cited the example of Plant Vogtle — one of the first nuclear reactors built in the U.S. in nearly a decade — that came online in Atlanta in 2024.

But they also noted the extensive permitting bureaucracy, massive investment and lengthy construction timeline needed; Vogtle took 15 years to build. More feasible would be a small nuclear reactor, which could be built in five or six years, said Erick Ford, president of the New Jersey Energy Coalition.

“If they’re going to start the process now, [by] 2030 they should be able to have it online,” he said.

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7th ‘Issue Alert’ Highlights Markets+ Footprint

Proponents of SPP’s Markets+ argued in their latest “issue alert” published Feb. 28 that the day-ahead market option provides a robust footprint with “exceptional generation and load diversity” across the region while also claiming recent warnings about its seam with CAISO’s Extended Day-Ahead Market (EDAM) are overblown. 

The alert is the seventh and last in a series of notices highlighting the purported advantages of Markets+ over EDAM and the Western Energy Imbalance Market (WEIM). The alerts have covered topics such as governance, reliability, pricing practices, market seams, emissions and market operations. 

The contributing parties include Arizona Public Service, Chelan County Public Utility District (PUD), Grant County PUD, Powerex, Public Service Company of Colorado, Salt River Project, Snohomish County PUD, Tacoma Power, Tri-State Generation and Transmission Association, and Tucson Electric Power. 

In their seventh alert, the proponents argued Markets+ will “be substantial in size with exceptional generation and load diversity.” For example, the market will have peak demand of over 52 GW and annual demand of over 280 TWh; a significant mix of resource diversity; clean flexible supply; and a “large geographical footprint — encompassing parts of 11 different states — resulting in a reduced probability that heat waves and cold snaps affect the entire Markets+ footprint simultaneously.” 

The alert also took aim at recent production cost studies, some of which have suggested EDAM would provide the most because of its large footprint, which includes California. (See Brattle Study Shows Big Benefits for California in ‘Expanded’ EDAM.) 

However, the studies do not capture the full economic picture and fail to account for the differences in market design between Markets+ and EDAM, the alert argued. The models assume Markets+ and EDAM will be isolated with limited trade when, in reality, entities in each will continue trading with one another, it said. 

“This defies real-world expectations and ultimately promotes an incorrect conclusion that being in the largest possible market footprint should be the only relevant consideration informing an entity’s market choice above all other factors, including fundamental differences in governance and market design that are not evaluated by these studies,” the proponents contended. 

The alert also covered congestion costs. The proponents argued that Markets+ provides enhanced protection from congestion costs by allocating congestion revenue to firm transmission rights holders in proportion to the congestion costs incurred on their specific transmission paths. 

In contrast, EDAM participants will miss out on robust congestion cost protections, the proponents claimed. 

“EDAM will not return these congestion charges back to the firm [open-access transmission tariff] rightsholders that are exposed to the congestion costs and will instead return the revenue to the [balancing authority area] where the constraint is located, which public data show is most often the CAISO BAA,” the alert argued. “Among the many negative consequences of this design, it is likely to impose large new costs for the transmission customers and ratepayers of EDAM participants outside of California, to the benefit of customers in the CAISO BAA.” 

When asked to comment on the issue alert, CAISO’s head of communications, Jayme Ackemann, pointed to another study by the Brattle Group that suggests some EDAM participants “could conservatively save consumers nearly $900 million annually.” (See Updated EDAM Study Shows Doubling of PacifiCorp Benefits.) 

Ackemann also pointed to the West-Wide Governance Pathways Initiative, an effort to ensure independent governance of CAISO’s EDAM and WEIM. California state lawmakers recently introduced legislation as part of the initiative. (See Pathways ‘Step 2’ Bill Sets Conditions for EDAM Governance.) 

“With FERC’s approval of EDAM’s market design and more than 50% of the load in the West planning to participate, it is clear that maintaining a strong, geographically diverse and interconnected system is crucial to maximizing consumer benefits through widespread participation in WEIM and EDAM,” Ackemann added. 

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PJM Stakeholders Approve SIS Manual Language

VALLEY FORGE, Pa. — The PJM Planning Committee on March 4 endorsed by acclamation revisions to Manual 14H to conform with changes to the RTO’s surplus interconnection service (SIS) process FERC approved in February (ER25-778).  

The committee discussed the specifics of how PJM would implement the changes during its meeting before approving the language. (See FERC Approves PJM’s One-time Fast-track Interconnection Process.) 

SIS allows developers to add new resources to an existing point of interconnection that is not fully used; for example, if an existing resource does not operate at all times of day. Injection is capped at the capacity interconnection rights in the original resource’s interconnection service agreement, and surplus interconnection requests do not trigger the need for new network upgrades. 

The new manual language would eliminate categorical prohibition on storage eligibility for SIS; change how PJM models proposed resources alongside projects in the generation interconnection queue; expand eligibility to allow SIS applications when the host resource is still in development; and allow projects that consume transmission headroom but do not require network upgrades. It would also allow projects that require additional interconnection facilities for the service while still prohibiting new network upgrades. 

PJM’s Ed Franks said SIS applications would be studied using the most recent cluster phase 3 model to be commenced, which he said would strike a balance that allows projects to proceed without being disrupted if others in that cluster drop out. Franks said it is less likely for projects later in the queue to withdraw, reducing the risk of cluster analyses having to be retooled in a manner that impacts the potential for SIS projects to be assigned network upgrades. 

“This would only be exponentially more complicated if we were using an earlier model,” he said. 

Responding to stakeholder questions on what battery storage configurations would be allowable, Franks said both open- and closed-loop storage would be permitted so long as network upgrades are not triggered. 

Ken Foladare, director of RTO and regulatory affairs for Tangibl Group, said the change would allow existing renewable resources to increase their reliability contribution by adding storage, transforming a non-dispatchable resource into semi-dispatchable. 

Jason Connell, PJM | © RTO Insider LLC

“This is a good opportunity for PJM to be able to add megawatts, especially if you’re adding battery storage to standalone wind, standalone storage and contribute to resource adequacy,” he said. 

Stakeholders questioned whether there would be a cure process for cases in which network upgrades are identified and allow for developers to change the scope of their projects to mitigate those violations. PJM Vice President of Planning Jason Connell said the tariff is clear in that if the SIS request causes a need for network upgrades, it would be denied. 

PJM Director of Interconnection Planning Donnie Bielak said developers could submit a new application with changes that could avoid triggering the upgrades that led to rejection. He said the RTO wants to avoid taking on the role of a design consultant engaging with a back-and-forth with the developer on what can be done to avoid network upgrades. 

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Petition Asks FERC to Potentially Claim Jurisdiction over Puerto Rico

Puerto Rican company Pluvia filed a petition with FERC in February asking the commission to find that its proposal to link the territory to the continental U.S. via grid-scale batteries on cargo ships could trigger its jurisdiction over the island (EL25-57). 

The batteries being shipped back and forth would be storage-as-transmission-only assets (SATOA), and similar projects have been proposed using railcars. The mobile storage could also ship power the other way. The firm’s filing says the technology could be used for day-to-day shipping and under emergency conditions. 

The firm filed its petition in early February, and FERC noticed it a couple of weeks later. It has largely flown under the radar, with only Public Citizen filing a “doc-less” motion to intervene before the comment period closed March 3. 

Pluvia describes itself only as “a domestic limited liability company wholly owned by citizens of the United States and organized under the laws of the commonwealth of Puerto Rico, inter alia, to produce, transmit and sell electric energy at wholesale.” Exactly who is behind the firm is unclear: Its petition was filed by one lawyer, and its incorporation documents with Puerto Rican authorities only list another lawyer. 

The state-owned Puerto Rico Electric Power Authority (PREPA) entered into contracts with Luma Energy (a subsidiary of Canadian utility Atco and Quantas Services) to run its grid in 2021, and with Genera PR (a subsidiary of the LNG firm New Fortress Energy) to run its generation in 2023. Pluvia told FERC that those deals have kept a monopoly in place, which is overall detrimental to the island’s population. 

“Public electricity monopolies have been effectively managed by other states, which have cooperated to lower costs and improve service to customers by implementing federal electric competition policy under the” Federal Power Act, Pluvia said. “The government of Puerto Rico’s administration, however, has been unsuccessful. The damage Puerto Rico’s electricity monopoly has caused is considered a human-made disaster with appalling humanitarian and economic impacts in Puerto Rico that also impact United States taxpayers.” 

The island was infamously impacted by Hurricane Maria, which in 2017 destroyed the island’s power grid and kept some of its residents without power for four weeks. 

“It’s really not done well since the hurricanes; the reliability of the system is probably about 10 times worse in terms of safety and safety metrics than the U.S. average,” Cathy Kunkel, energy consultant for the Institute for Energy Economics and Financial Analysis, said in an interview. “And the reliability has actually declined over the last year or so.” 

PREPA’s system was contracted to Luma and Genera after the hurricane, with Kunkel saying it was not sold outright because that would have put at risk federal disaster relief funds being used to shore up the grid. 

High costs and an unreliable power system have been impairments to economic growth on the island and its ability to stop people from moving to the mainland, Pluvia said in its petition. 

On top of still running a creaky grid before and after Maria ravaged PREPA’s system, the public utility has been bankrupt, which has hampered its ability to attract needed investment, Pluvia said 

“PREPA’s lack of credit creates a barrier to normal project financing for energy projects, as financing sources hesitate to bet on PREPA’s performance of its long-term contractual obligations to buy electricity in quantities and at prices stated in” power purchase agreements, Pluvia said. 

The combination of public monopoly and insolvency leads consumers and investors to a dead end, while creating the misleading appearance of an energy transition through multiple phases of bids and awards that produce contracts needing affordable financing, it added. 

While Pluvia and its backers might have run into trouble with securing contacts, Kunkel noted that major deals have been struck recently. 

“There’s definitely been long-term contracts that have been signed in the last several years,” Kunkel said. “There’s been a number of new renewable energy contracts and some battery storage contracts and a new natural gas plant contract that was signed in December.” 

Another trend since Maria has been end-use consumers’ increasing adoption of distributed solar and storage, which Kunkel said makes up about 9% of Puerto Rico’s electricity consumption. 

The issue of FERC jurisdiction over Puerto Rico’s grid has come up before, such as when Alternative Transmission filed a petition in 2023 seeking a finding from the commission that its proposed undersea cable would not trigger commission jurisdiction (EL23-14). The project and its details were a little too vague for FERC to give a firm answer, but it did discuss the jurisdictional issues and said it could forswear oversight of Puerto Rico’s grid as it has in similar cases involving ERCOT. (See FERC Weighs in on Jurisdictional Questions over Puerto Rico Project.) 

The Alternative Transmission case came up in Pluvia’s petition as it seeks to clarify that its proposal of shipping batteries back and forth by sea could trigger FERC jurisdiction over the island’s power system, which the commission said could happen with an undersea cable. 

The petition does not ask FERC to claim jurisdiction immediately, but Pluvia said it may request that in future proceedings, and it expressly reserved the right to do so. 

Puerto Rico has a version of a state regulator already called the Energy Bureau, which was set up about a decade ago to oversee PREPA. IEFFA’s Kunkel said it has helped bring some normalcy to the island’s regulatory structure. 

“One of the problems with PREPA … was that it really had just kind of become a very politically driven entity and was not making decisions based on best-practice, sound utility planning,” Kunkel said. “For example, it had not had a base rate case since the 1980s. One of the first things that the Energy [Bureau] did was to have a base rate case.” 

As for bringing RTO-style markets to the island, it is unclear how much benefit they would bring: Puerto Rico’s system is far smaller than any of the continental organized markets, meaning it would lack the benefits that come from centrally dispatching large amounts of generation across a wide footprint, Kunkel said. 

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Offshore Wind Development Rebound Expected — Outside US

With one notable exception, the offshore wind industry is on track for a global rebound, Rystad Energy predicts in its 2025 outlook, released March 2.

The energy research and intelligence company expects capacity additions to reach 19 GW — substantially more than the roughly 8 GW and 10 GW seen in 2024 and 2023, respectively — and expects investment to reach $80 billion.

Mainland China, the world’s largest offshore wind market, will account for more than 12 GW of the total. With South Korea and Taiwan added in, Rystad projects 74% of 2025 offshore generation capacity additions will be in Asian waters. The U.K., Germany, France and Netherlands account for the remaining 26%.

The world’s largest economy, which until very recently offered robust policy support for offshore wind development, is zeroed out in Rystad’s 2025 forecast of capacity additions.

“U.S. federal policy is creating significant global ripple effects, hindering offshore wind development, especially where a large portion of auctioned capacity lies,” Petra Manuel, Rystad’s senior offshore wind analyst, said in announcing the outlook. “President Donald Trump’s January memorandum halting new leasing and approvals on the Outer Continental Shelf, citing environmental and safety concerns, could last throughout his term, pausing new developments and creating continued uncertainty for ongoing projects.”

One U.S. offshore wind project now under construction, the 800-MW Vineyard Wind 1, could potentially have a 2025 commercial operation date, but it has experienced repeated delays.

Four other projects are in the works: Offshore and onshore construction are underway on Revolution Wind and Coastal Virginia Offshore Wind, while onshore work has begun for Sunrise Wind and Empire Wind 1.

None of the four are scheduled to be completed this year.

Trump’s Jan. 20 memorandum suspended new offshore wind leasing and directed “a comprehensive review of the ecological, economic and environmental necessity of terminating or amending any existing wind energy leases,” injecting a new degree of risk and uncertainty into an industry already struggling to build momentum in the U.S.

While China will dominate construction completion in 2025, Rystad expects that European projects will represent the bulk of final investment decisions (FIDs) made in 2025 for future construction starts — 9.5 GW in total, with Poland, Germany and the U.K. accounting for 6.9 GW. Worldwide, 2025 FIDs are expected to be about equal to those of 2024.

Another barometer of future planning is site leasing. Rystad notes that seabed areas holding a record 55 GW of potential capacity were offered at auction in 2025 outside China. But not all of that capacity found a buyer, particularly in the U.S., where two of four auctions were called off before being held and a third drew bids for only half the lease areas offered.

Rystad expects significantly less capacity to be offered at auction in 2025 — about 30 to 40 GW worldwide, which would be in line with activity seen in 2021 and 2022.

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Ontario Threatens 25% Tariff on Electricity to US

Ontario Premier Doug Ford announced March 4 that the province will enact a retaliatory 25% tariff on its electricity exports to the U.S. — or even halt them — if President Donald Trump doesn’t stand down in a burgeoning trade war. 

“Today, I am writing to every senator, every congressman and woman and the governors from New York state, Michigan and Minnesota, telling them that [if] these tariffs persist, if the Trump administration follows through on any more tariffs, we will immediately apply a 25% surcharge on the electricity we export,” Ford said from a podium emblazoned with “Canada is not for sale.” 

“We will not hesitate to shut off their power as well,” Ford told reporters at the press conference. 

According to a draft public notice of tariff  rules  posted March 3, a 25% tariff on nearly all goods from Mexico and Canada and a 10% tariff on Canadian energy went into effect at 12:01 a.m. March 4.  

Ford’s announcement was part of an unfolding Canadian response. He said it was a “tough day” for both the U.S. and Canada. 

“Canada and Ontario did not start this fight. We want to work with our American friends and allies, not against them. We said we’d never start a trade and tariff war with the U.S. But you’d better believe we’re ready to win one,” he said. 

Ford added that the U.S. leaders he has spoken to agree that Trump’s tariffs on Canada are a “massive mistake” that stand to hurt both countries. He said the two could have worked together to economically sustain one another.  

“We have no choice. We have to respond … tariff for tariff, dollar for dollar,” he said. Ford said Canadians should be prepared for a long fight and escalations, including “surcharges or outright restrictions” on the critical minerals and electricity Canada supplies to the U.S. Ford said Ontario’s tariffs would be used to help the workers affected. 

Canadian power exports to the U.S. fluctuate year to year, though the U.S. is consistently a net importer of power. In 2023, the U.S. took in 15 TWh compared to 42 TWh in 2022, according to the U.S. Energy Information Administration. The decline was brought on by an ongoing drought affecting Canadian hydropower and lower natural gas prices in the U.S.  

Ontario exports power through New York, Michigan and Minnesota. The province powers about 1.5 million homes across those states. 

During a separate and routine press conference March 4, New York Gov. Kathy Hochul said she does not think her state has a “target on our backs from Canada.”  

“Fortunately for our state, I’m good at developing positive relationships with our allies, not embarrassing them,” Hochul said. She said the western part of the state and Canada share an “incredible synergy” and that she had previous assurances from Ford that he would not harm the state.  

“Now, whether that means he can help the flow of energy that we’re already counting on to keep coming here … I’m happy to have additional conversations with him on how we can support each other during this crisis,” she said. 

In response to RTO Insider, MISO said it had more to do to understand how the U.S.’ tariffs work and did not address the prospect of Ontario’s retaliation. The MISO footprint includes Michigan and Minnesota. 

“This is a fluid situation, and it is unclear whether the U.S. import tariffs apply to imports of electricity from Canada, and it is uncertain whether or when this will be resolved. MISO has received no confirmation from federal agencies regarding the duties’ applicability to electricity or who will be responsible for paying or collecting them,” spokesperson Brandon Morris told RTO Insider. 

However, MISO noted that less than 1% of its total energy in 2024 was supplied via Canadian imports, with less than half of that hailing from Ontario. 

“For context, that amount is equivalent to approximately one power plant. MISO manages the loss of power plants like this every day to ensure reliability across our footprint,” Morris said. 

Stacey LaRouche, press secretary for Michigan Gov. Gretchen Whitmer, said the governor and her team are monitoring the situation. Whitmer has previously warned that tariffs would put jobs on both sides of the border at risk and stand to further slow supply chains and raise consumer costs. 

Minnesota Gov. Tim Walz called the tariff back-and-forth “totally avoidable.”  

“And if I had some advice on this one: President Trump can just claim victory. We’ll create an award here and award it [to] him that he won the trade war. Good for you,” Walz said during a March 4 press conference before the agricultural community of Cannon Falls, Minn. “But let us get back to the work of real economics; the growing of food; making sure that we’re innovating for the future.”   

Ford said he was encouraging his fellow premiers to follow suit with reciprocal surcharges. If any make similar announcements, ISO-NE could be included in Canada’s counteroffensive. 

“New England’s power system is connected to Quebec and New Brunswick, not Ontario, and the region’s grid is operating reliably today,” ISO-NE said in an email to RTO Insider. 

Vincent Gabrielle and Jon Lamson contributed to this report. 

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Former BPA Leaders Again Protest Workforce Cuts

IRVING, Texas — Former Bonneville Power Administration heads Randy Hardy (1991-1997) and Stephen Wright (2000-2013) have again collaborated on a public letter distributed in the Pacific Northwest about the “tremendous risk being created” in the region by workforce reductions at the federal agency.

In a letter made public March 3, which followed a previous letter in February, Hardy and Wright argued that the reductions will not realize taxpayer savings, as all BPA expenses are funded through electricity rates charged to its utility customers and passed on to retail consumers. They noted that the federal power marketing administration has already lost 14% of its workforce and a fifth of its power dispatchers, endangering the entire Northwest power grid.

“There has been no strategy to the workforce reductions such as targeting less important positions, or fencing off positions critical to ensuring public health and safety such as power dispatchers and lineworkers,” the former administrators wrote. “While BPA management is strictly limiting communication, from our experience we can presume that management is now attempting to plug round pegs into square holes and in many cases not having anywhere near enough pegs.”

“The implications of those people dropping out of the workforce without a plan just leads one to question: ‘What are the impacts going to be?’” Wright, a member of SPP’s Board of Directors, told RTO Insider as the letter was being released. “When you have people that are everything from duty schedulers, hydro schedulers to linemen, it just leaves you with a bunch of questions about, well, how are they going to manage through this? And then what implications are there for others that are impacted by their operations? They’re so interconnected, there’s a chance that that could be widespread.”

The administrators added three concerns to those expressed in their previous letter:

    • The reductions will increase outage repair times across BPA’s six-state region.
    • Employee safety will be compromised with crews stretched thin and likely requiring more overtime.
    • Geopolitical tension translates to risk of cybersecurity intrusions.

“We reemphasize that we strongly support seeking efficiency gains especially through the adoption of new technology,” Hardy and Wright wrote. “But electricity delivery, unlike many other businesses, is a function where the public reasonably expects — and public health and safety demands — round-the-clock, uninterrupted service.”

They closed their missive by asking for relief from the Department of Energy, urging a total exemption from pending reductions, lifting an existing hiring freeze, rehiring the 100 or so probationary employees already laid off, and exempting the U.S. Army Corp of Engineers and Bureau of Reclamation staff who are funded by BPA revenues.

BPA is part of DOE and provides about 28% of the Northwestern U.S.’ electricity, managing a 15,000-mile transmission network. It is one of the key potential participants in SPP’s Markets+, a day-ahead service offering. Wright serves as chair of the Interim Markets+ Independent Panel and is one of three SPP directors serving on it.

The letter was written for those in the Northwest and distributed by the Public Power Council and others. Hardy took the message to The Seattle Times.

Wright said he and Hardy are simply doing what others can’t.

“We’re putting information out right for people to be aware of,” he said. “The problem is, it’s difficult for the agencies to talk about this, and so, to some extent, we have to surmise some things. But between Randy and me, we just have enough years having been at Bonneville; we can put pieces together that it might not be easy for other people to put together.”

Wright was speaking during a break in SPP’s Energy Synergy Summit. In a separate meeting earlier that day, he asked SPP legal staff about staff reductions at FERC and the potential effect on the grid operator’s “specific issues.”

“I was asking the question because I don’t know what’s going on, but the way [job reductions] landed at Bonneville, I don’t know why it would be significantly different: … the relatively random nature in which people are choosing to resign, or the implications of probationary employees,” he said. “And by the way, ‘probationary employee’ doesn’t mean that they’re new.”

According to the U.S. government, probationary federal workers are new or reassigned employees under evaluation during a trial period, which generally lasts a year. A federal employee can become probationary with a transfer or new job within the same department.

When it was pointed out to Wright during the meeting that he is helping to raise awareness of the layoffs and their potential effect on the Northwest, he said, “This is a very active conversation in the Northwest.”

“The thing that really is bothersome about this is that it doesn’t do anything for the federal deficit,” he said.

In the letter, Wright and Hardy wrote, “Reducing BPA staff does not save U.S. taxpayers one dime.”

The former administrators are not alone in expressing their concerns over the BPA job reductions. Wright reeled off a list of several other public figures who are also speaking up: All but one of Washington state’s Democratic U.S. representatives, who wrote a letter to Energy Secretary Chris Wright (Rep. Marie Gluesenkamp Perez was the lone holdout); Energy and Commerce Committee member Rep. Kim Schrier (D-Wash.), who made a speech on the House floor; and Oregon’s U.S. senators, Ron Wyden (D) and Jeff Merkley (D), who wrote a letter to President Donald Trump. (See Ore. Senators Ask Trump to Justify ‘Reckless’ Job Cuts at BPA.)

Wright said the only Pacific Northwest Republican who has spoken about the issue is U.S. Rep. Dan Newhouse (Wash.). “He did it in a newsletter to his constituents, just saying he’s concerned about the impacts on the energy and research issues. He also has a National Lab in his district,” Wright said.

Asked if the outreach to the government and stakeholders is working, Wright said, “It’s definitely getting attention. I mean, a fair amount of attention.”

Fred Heutte, senior policy associate with the Northwest Energy Coalition, agreed with the sentiments in the letter. He told RTO Insider that though NWEC disagrees with BPA on many issues, “we are absolutely committed to the idea that Bonneville must have the staff to operate the system day-to-day.”

The staffing crisis “is a direct threat to reliability,” Heutte said. He added that regional entities, such as WECC, “have a role in standing up and saying that their main focus under the [Energy Policy Act of 2005] is reliability.”

Heutte sits on WECC’s Member Advisory Committee. The organization oversees compliance with reliability standards. It also conducts resource assessments and planning functions for the Western Interconnection.

Approximately 90 million people are served in the Western Interconnection. Heutte said that WECC speaking up would send a “very important signal.”

“We want people to say, ‘If I flip the switch, the lights will go on.’ That’s a good thing, but there’s an enormous amount of work and enormous amount of vulnerability now to not having the staff sufficient to make that happen. So I hope at the appropriate time that WECC will speak up.”

When asked to comment on the letter, BPA spokesperson Doug Johnson told RTO Insider in an email that “there is nothing in the letter we feel the need to correct or expand upon.”

“WECC is aware of the personnel impacts at Bonneville Power Administration and other federal entities in the West,” Kris Raper, vice president of strategic engagement and external affairs at WECC, told RTO Insider in an email. “We will continue to monitor the situation as it develops, including collaborating and coordinating with BPA and other electric industry owners and operators in support of their role in serving customers with the essential power that they need.”