Search
December 14, 2025

Posted on

Senate Finance Committee Looks to Eliminate Energy Tax Credits in 2028

Senate Finance Committee Chair Mike Crapo (R-Idaho) released language for the massive reconciliation bill that includes major cuts to tax subsidies for clean energy. 

A version of the bill already passed the House with deep cuts to energy credits that would cause them to sunset and include restrictions that many in the industry say would render them useless. (See House Passes Reconciliation Package that Would End Energy Tax Credits.) 

The bill would make the 2017 Trump tax cuts permanent, thus avoiding a “$4 trillion tax hike,” Crapo said June 16. 

“The legislation also achieves significant savings by slashing Green New Deal spending and targeting waste, fraud and abuse in spending programs while preserving and protecting them for the most vulnerable,” he added. 

The language the Finance Committee released June 16 would phase down key tax credits even more quickly than in the proposal the House passed. The House version would let clean energy projects get full tax credits through 2028 before being cut over the next several years and expiring entirely on Jan. 1, 2032. 

While the House bill required projects to be completed to receive credits, the Senate version keeps the current language that projects only need to start by a certain date to get them. But it slashes the production tax credit and the investment tax credit to 60% of their current total starting in 2026, then 20% for projects starting in 2027, and finally makes projects that start after Dec. 31, 2027, ineligible for them entirely. 

The language would include new prohibitions for the 45U production tax credit for nuclear plants, limiting the use of fuel from some foreign suppliers. 

The bill also would cut tax credits for plug-in electric vehicles entirely, as well as other credits aimed at making homes and commercial facilities more energy efficient. 

Edison Electric Institute interim CEO Pat Vincent-Collawn said the Senate language offers “more reasonable timelines” for phasing out energy tax credits and preserving their transferability. 

“Financial certainty and access to cost-effective financing are critical tools for electric companies as they continue to make needed investments to meet rising customer demand and to expand generation capacity,” Vincent-Collawn said in a statement. “These modifications are a step in the right direction, and we thank Chairman Crapo for his leadership in balancing business certainty with fiscal responsibility. We look forward to continuing to work with lawmakers to ensure the final package incorporates practical, pro-growth policies that support our shared goals of strengthening America’s energy security and keeping customer bills as low as possible.” 

The Union of Concerned Scientists said the Senate language, like the version that cleared the House, would slow down clean electricity deployment, undermine domestic manufacturing of batteries and electric vehicles, and make EVs more expensive and less available. 

“This proposal specifically and repeatedly sidelines the exact clean technology solutions that are ready and able to deliver benefits for people and communities all across this country,” UCS Energy Analyst Julie McNamara said in a statement. “These are the solutions that have driven enormous gains to date and are poised to deliver so much more — if only lawmakers would let them.” 

Steven Nadel, executive director of the American Council for an Energy-Efficient Economy, called on senators to leave the credits for energy efficiency and electric vehicles in place. 

“Canceling these credits would increase monthly bills for American families and businesses,” Nadel said in a statement. “Why would we stop helping families save energy when prices are going up and up? Americans didn’t vote for higher energy bills. At a time when we’re concerned about strain on the electric grid, it’s particularly absurd to waste more electricity.” 

Posted on

NV Energy Seeks OK for $500M Wildfire Self-insurance Policy

With the risk of catastrophic wildfire growing in Nevada and across the West, NV Energy is seeking approval for a $500 million wildfire liability self-insurance policy.

The self-insurance, to be paid for by ratepayers over 10 years, would bring NV Energy’s wildfire liability coverage to about $1 billion. The company now has $405 million in commercial coverage and $100 million in existing self-insurance.

The Public Utilities Commission of Nevada (PUCN) has scheduled a hearing on the proposal for June 24.

NV Energy wants the additional self-insurance “in order to have adequate wildfire liability insurance in place in the event that a catastrophic wildfire in Nevada is alleged to be caused or exacerbated by utility equipment,” the company said in a filing with the PUCN.

The chance of a wildfire causing $1 billion or more in financial losses in NV Energy territory in the next 10 years is 18% or more, Nathan Pollak, of Scidan Consulting Group, testified as part of NV Energy’s application. And the chance of a wildfire causing $2 billion in financial losses in the next decade is 10%, he said.

Pollak recommended NV Energy have $1 billion to $1.5 billion in wildfire liability coverage.

But NV Energy said it is facing rising costs and reduced availability of commercial insurance.

“The products available are expensive and non-traditional – presenting drawbacks that make them less prudent than the self-insurance policy,” Mariya Coleman, NV Energy’s vice president of corporate insurance and claims, said in the application.

Striking a Balance

NV Energy would create a captive insurance company to administer its self-insurance, just as it did for its existing $100 million self-insurance policy.

The company said the 10-year period to fund the new self-insurance policy strikes a balance between avoiding rate shock to customers while completing the funding in a reasonable amount of time.

About three-quarters of the cost would be paid by customers of Sierra Pacific Power, NV Energy’s subsidiary in northern Nevada, with Nevada Power customers in southern Nevada picking up the remainder.

If there are any payouts from the self-insurance fund, NV Energy has proposed replenishing it with another customer rate hike.

Shareholders would commit to a 10% co-insurance payment on any claims, up to $50 million. The co-insurance payment wouldn’t depend on results of a reasonableness review.

“This co-insurance payment preserves a strong incentive on the part of the companies to mitigate wildfire risk and to settle third-party claims prudently,” Michael Behrens, NV Energy’s chief financial officer, said in the application.

The co-insurance share is greater than that of the self-insurance policies of two major California utilities, Behrens noted. The shareholder co-insurance payment in Pacific Gas and Electric’s self-insurance policy is 5%; for Southern California Edison, it’s about 2.5%.

Some stakeholders criticized NV Energy’s proposal, saying it is inefficient to have two separate self-insurance policies with different structures, rules and coverage.

Instead, NV Energy should expand and modify its existing self-insurance policy, said utilities consultant Bradley Mullins, who filed testimony on behalf of several gaming interests and other parties.

Mullins said it would be more appropriate for NV Energy to collect the self-insurance funding from ratepayers over 50 years, since a $1 billion wildfire is estimated to be roughly a 1-in-50-year event. And no costs from “imprudence, gross negligence or willful misconduct” should be borne by ratepayers, he said.

Capital Impacts

In his testimony, Behrens of NV Energy said catastrophic wildfires have had serious financial consequences for electric utilities throughout the West.

In cases where utility equipment was implicated in massive wildfires in California, Hawaii, Oregon and Texas, the respective utilities saw downgrades to their credit ratings, “in many cases to non-investment grade,” Behrens said.

“Even a utility that has not been alleged to have caused or exacerbated a catastrophic wildfire faces the risk of a lower credit rating and higher cost of capital if it is not perceived to have sufficiently prepared for the financial risks,” he said.

Behrens noted that utilities are a capital-intensive sector that use debt to finance the long-term assets needed to provide service.

The impact of wildfires on utility finances also was a topic of discussion June 2 during the Western Conference of Public Service Commissioners. Investment analysts said wildfire risk could hinder Western utilities’ ability to raise capital to fund infrastructure projects. (See Analysts to Western Regulators: Wildfire Risk is Issue du Jour.)

Posted on

IESO Seeks to Shore up Capacity Market

The IESO Technical Panel approved for posting rule changes to reduce unfulfilled capacity commitments by making it easier for participants to transfer their obligations and harder to buy them out.

The panel on June 10 approved posting the revisions for comment by voice vote with no objections or abstentions.

IESO conducts a capacity auction once a year, and suppliers can bid on obligations for either of two periods — summer (defined as May 1 to Oct. 31) or winter (Nov. 1 to April 30) — or for both. Auctions are conducted in late November for the capacity periods beginning the next year. This year’s auction will be held Nov. 26-27 for the periods beginning May 1 and Nov. 1, 2026, with results posted Dec. 4. 

Resources are expected to participate in the energy market during the periods for which they purchased obligations through the auction, or they can buy out or transfer their obligations. Buyouts are subject to a charge equal to 30% of the total obligation value. 

According to IESO, the market saw its “highest level of competition ever” in 2024, with 2,122.2 MW secured for summer and 1,524.6 MW for winter at $332.39/MW-day and $139/MW-day, respectively. It said it secured 15% more capacity than in 2023’s auction, at lower prices. 

But Adam Cumming, IESO market rules adviser, told the Technical Panel that every year “a small number of resources” — representing about 100 MW, according to the ISO — are unable to fulfill their obligations “for a variety of reasons.” Among these is simply not completing the necessary registration requirements during the forward period (after the auction but before the obligation period) by the posted deadlines. 

Unfulfilled obligations reduce “the capacity available to the IESO and distorts auction clearing price signals,” the ISO said in a presentation in May. 

Among the changes the panel approved for posting is an increase in the buyout charge to 50%, intended to deter participants from taking on commitments they cannot meet and incentivize those with obligations to fulfill them. “Hopefully with the increased costs, people will be a little bit more careful in choosing their obligation size,” Cumming said. 

Suppliers who fail to complete the registration process no longer would have the option of simply forfeiting their deposits and would be required to buy out their obligations. “This change will ensure that all instances of unfulfilled commitments are subject to the buyout charge process,” the ISO said. 

The revisions also would remove the requirement that obligations can only be transferred between resources with the same attributes. 

IESO told the panel that stakeholders are supportive of the changes after working on them for over a year; in the case of the buyout charge increase, the figure was proposed by capacity market participants themselves, it said. 

The revisions will be open for comment until June 24. The panel will vote July 15 on recommending them to the Board of Directors for approval at its meeting in August. 

Posted on

PJM Stakeholders Propose Cost Allocation Models for DOE Emergency Orders

The PJM Members Committee is set to vote on several proposals drafted by the RTO and stakeholders to determine how to allocate costs associated with generators required to remain online through the U.S. Department of Energy’s emergency orders under Federal Power Act Section 202(c). 

Package sponsors, RTO staff, the Independent Market Monitor and other stakeholders will meet with PJM’s Board of Managers just before the committee’s meeting June 18 as the final phase of an expedited Critical Issue Fast Path (CIFP) process initiated to determine how to raise the funds to compensate Constellation Energy for continuing to operate its 760-MW Eddystone Generating Station, which DOE ordered to remain online past its May 31 deactivation date through Aug. 28. 

Constellation and PJM agreed to use the deactivation avoidable cost credit (DACC) model used to compensate resources retained past their deactivation date on reliability-must-run agreements. The allocation methodology associated with the DACC, however, is designed for assigning costs to load in the region of the transmission violations leading to an RMR arrangement; PJM has said it is not suited to instances where the federal government mandates a generator remain online for resource adequacy. (See PJM Board Initiates CIFP Process for Eddystone Compensation.) 

PJM proposed to allocate the costs to all RTO load by dividing each market buyer’s share of the RTO-wide unforced capacity (UCAP) obligation and multiplying that figure by the credit to Constellation. A new line item would be added to billing statements to show the cost of 202(c) credits, with information also posted to PJM’s website. During the CIFP meeting June 12, PJM Senior Director of Market Settlements Lisa Morelli said the RTO had estimated the 90-day cost to load to be $34.72/MW of UCAP. 

Package D from the East Kentucky Power Cooperative would assign costs to all RTO native load and exports using actual megawatt-hour consumption per month unless the resource subject to the 202(c) order is within a zone that fell short of its capacity procurement obligation — in which case the costs would be allocated to that zone — or if the RTO cleared short of its obligation, in which case costs would be assigned to each locational deliverability area (LDA) according to their contribution to the shortfall. The charges would be calculated by adding a market buyer’s energy consumption and exports and dividing that sum by total monthly energy production, then multiplying that by the credit to Constellation. Resources exporting to external balancing authorities they have capacity obligations to would be excluded. 

The cooperative’s Package E would assign costs to each buyer according to the same formula regardless of how each zone cleared in the capacity market. 

Stakeholders were divided on whether the proposal should focus solely on compensating Constellation for operating Eddystone under the current emergency order or establishing rules for other resources subject to a 202(c) order. Morelli said establishing more lasting rules would carry the benefit of avoiding additional rushed CIFP processes if more resources are ordered to remain online. 

Two PJM packages would apply more broadly, though with differing criteria; Package A would apply to all DOE orders under Section 202(c) in which the resource owner opts to be compensated through models similar to the DACC, while Package C would limit that to orders issued within 180 days of PJM filing the cost allocation proposal. Morelli said establishing a time limit for the proposal would give time for stakeholders to continue discussions for a more holistic solution without the result of the CIFP becoming permanent. 

Package B from Gabel Associates and EKPC’s Package E would limit the changes to the Eddystone order expiring on Aug. 28. Package D from EKPC would apply to all units subject to a 202(c) order not subject to an RMR agreement and being compensated through models akin to the DACC. 

Proposals with a wider applicability also differed on how they would allocate costs if future DOE orders specified a region within PJM where localized resource adequacy concerns prompted the need to retain a generator beyond its desired deactivation date. PJM’s packages would assign the charges only to load in the LDAs or zones identified, while Gabel would continue to allocate them to all RTO load. 

Stakeholders opposed to a locational element to allocating costs argued that Eddystone is not being retained to serve a particular zone and future orders could retain generation for resource adequacy issues that have not yet manifested. 

Posted on

New Pipelines Unlikely for New England, Experts Say

BOSTON — Despite interest from the Trump administration, new gas pipelines into New England remain unlikely due to a lack of counterparties willing to pay for the new lines, energy industry experts said at a recent roundtable discussion.  

The pipeline financing uncertainty is driven by the New England states’ push for heating electrification, the lack of incentives for gas generators to procure firm capacity, and a 2016 ruling by the Massachusetts Supreme Judicial Court that electric customers cannot cover the costs of a new pipeline. 

“The biggest reason I am skeptical of a new pipeline is: Who is the counterparty?” Dan Dolan, president of the New England Power Generators Association (NEPGA), told attendees of Raab Associates’ New England Electricity Restructuring Roundtable on June 13. “Unless Enbridge or Williams or Kinder Morgan are willing to build on spec and are willing to take merchant risk … I don’t see it.” 

Cheryl LaFleur, chair of the ISO-NE board of directors, highlighted financing challenges and a lack of interest from the states as the key obstacles to the development of new pipelines. 

“A pipeline is definitely the most efficient way to move gas from point A to point B — that has always been true,” LaFleur said. “It is up to the states how much gas they think the region will need and if they want a pipeline. It is not up to ISO New England.”

In May, the Trump administration reportedly reached a deal with New York to lift a stop-work order on the Empire Wind project in exchange for concessions from Gov. Kathy Hochul (D) on the Constitution Pipeline project, which was halted after failing to receive permits from the state in 2018. (See BOEM Lifts Stop-work Order on Empire Wind.) 

Several speakers agreed that, if New England was offered a similar, hypothetical deal lifting regulatory barriers for offshore wind and gas pipeline projects, lawmakers should take the trade.  

Rachel Fox, director of policy and strategy at the American Petroleum Institute, speculated that, while offshore wind “is by no means favored by this administration,” the Trump administration may allow projects to move forward “if it’s part of a deal for a natural gas pipeline.” 

Liz Stanton, executive director of the Applied Economics Clinic, warned about the health effects of gas generation on local communities, but said the New England states should take the deal because efforts to bring a pipeline to New England appear unlikely to succeed. 

Dolan of NEPGA was skeptical the Trump administration would seek this type of deal with the region, noting that the under-construction Vineyard Wind and Revolution Wind projects are well under way and have not been specifically targeted by the Trump administration. He said a deal likely would need to clear obstacles to incremental offshore wind generation beyond these projects, which the administration may be reluctant to do. 

Retail Gas Demand

On the gas distribution side, speakers discussed an apparent rift that has emerged in Massachusetts between lawmakers and utilities over the interpretation of language in a major 2024 clean energy bill passed in the state. (See Mass. Clean Energy Permitting, Gas Reform Bill Back on Track.) 

According to Sen. Michael Barrett, one of the lead negotiators on the bill, the bill authorized gas utilities to disconnect customers from the gas system if viable heating alternatives are available. This change was intended to amend the utilities’ “obligation to serve,” preventing a single gas customer from holding up the decommissioning of an entire section of gas pipe. 

“Last year, we amended Section 92 of Chapter 164, which is the sole basis for the so-called obligation to serve in Massachusetts, and we amended it with the legislative intent of giving our state DPU flexibility … to resolve the so-called holdout problem,” Barrett said.  

But despite the legislative changes, gas companies continue to argue they are not authorized to deny gas services to existing customers, and that the change in state law applies only to new customers. 

“There’s a disagreement, I think, in terms of what authority the utilities have to substitute electric for gas, or for the DPU to authorize that substitution,” said Jamie Van Nostrand, chair of the Massachusetts Department of Public Utilities.  

He said the issue of holdout customers has come up in a National Grid electrification demonstration project, which aims to “decommission one or more leak-prone gas pipe segments through coordinated whole-home electrification of customers.” 

The company, Van Nostrand said, has taken “is taking the position that decommissioning a segment will require 100% participation of the customers on that segment,” creating numerous potential points of failure for the efforts to decommission each segment of pipe.  

As the state looks to move the bulk of its residential gas customers to electric heating, it would be “very hard to achieve a gas transition without addressing this issue,” Van Nostrand said. 

Looking forward, Van Nostrand said the DPU plans to look at the issue more closely “and give the parties an opportunity to brief on that, because it is a real critical issue as we look at the success of these electrification projects.”  

Caroline Hon, vice president of New England regulation and pricing for National Grid, did not directly answer a question from Sen. Barrett about why National Grid continues to take the stance the utilities do not have the authority to disconnect customers when viable alternatives exist. 

Hon framed customer conversions as an equity issue and said that “if we aren’t thinking about this thoughtfully, it can be very regressive, and the most vulnerable people, the customers who can’t actually to convert, are going to be the ones who really suffer.” 

Posted on

Texas RE Adds AI as Risk to ERCOT Region’s Reliability

The Texas Reliability Entity has added key risks related to artificial intelligence and large loads as part of its annual Reliability Performance and Regional Risk Assessment.

ERCOT’s Regional Entity says AI “introduces some new challenges that we need to be cognizant of.”

Texas RE’s David Penney, director of reliability services, said during a June 16 webinar that the organization looks at three aspects of AI: as a large load, operating patterns and cybersecurity.

“When you look at the load patterns the AI-type data centers put on the grid, it’s not the typical pattern that you can see from a normal data center,” he said during the “Talk with Texas RE” session. “Most normal data centers have a fairly flat, stable load protocol. [With] AI-type data centers, it’s more of a sawtooth pattern with very steep ramps, up and down ramps over short periods.”

Penney said AI data centers’ ramps will stress the grid’s voltage support in local areas. And then there’s the cybersecurity risk brought by their operations.

“AI brings significant opportunities for the electric grid to be able to modernize and make quicker decisions,” he said. “When we incorporate this, there’s also a huge cybersecurity risk along with it. Machine-learning type models can possibly be compromised by an adversary.”

Texas RE assesses AI integration risks as having a moderate impact on the ERCOT region. “As AI increases in scale and integration, however, associated risks may increase in both likelihood and impact,” it said, promising to monitor AI developments.

The entity assessed the “disorganized integration” of large loads as a likely risk — and the largest — with major impacts, an escalation from its 2024 report. It said the load integration’s pace and scope and forecasts of negative reserve margins beginning as soon as 2026 are expected to have a major effect on bulk power system reliability.

ERCOT’s large-load interconnection queue gained more than 25 GW of capacity in March. The queue contains more than 136 GW of study requests, with a little more than 4.5 GW energized since 2022.

“While a number of these resources will likely not materialize, the rapid increase in load on the system presents significant forward-looking challenges. These load increases reflected in future reserve estimates have been striking,” the report says.

The Texas Legislature has passed a law that directs the state’s Public Utility Commission to create a framework for adding data centers and bitcoin miners without stressing the grid or saddling other consumers with an unfair share of infrastructure costs. Gov. Greg Abbott (R) has yet to sign the legislation.

The Texas RE says the generation necessary to meet the increasing demand continues to “evolve toward” variable resources and energy storage. Solar generation has increased exponentially and, along with wind, produced 34.8% of total energy in 2024, the report said.

Storage capacity neared 10 GW in 2024 and is forecasted to almost triple to 27.5 GW over the next two years. That places “increasing dependence” on inverter-based resources, the RE said.

Penney said the ERCOT region had one hour in 2023 where renewable penetration was over 70%. That increased to 39 hours in 2024 and already has exceeded 100 hours in 2025.

Still, the report said the region’s reliability performance “remains strong while navigating these challenges.”

The assessment comes on the heels of NERC’s annual State of Reliability report, which was released June 12. (See NERC State of Reliability Report Highlights Progress and New Challenges.)

Posted on

N.J. Lawmakers Bless Wide-ranging Energy Options

New Jersey legislators, responding to fears of a dramatic shortfall in electricity, have pushed ahead with a series of legislative proposals, among them plans to harness wave, nuclear and storage power.

The Assembly Science, Innovation and Technology Committee backed A4215, which would direct the New Jersey Economic Development Authority to create an incentive program to stimulate the construction and operation of small modular nuclear reactors (SMRs).

The legislation defines eligible projects as nuclear fission reactors that can generate up to 300 MW of electricity and are licensed by the U.S. Nuclear Regulatory Commission. They can be built and operated independently or in conjunction with other reactors.

The bill also would direct the New Jersey Board of Public Utilities (BPU) to adopt regulations for the reactors and to study issues such as whether a nuclear reactor would replace a loss of generating capacity due to the closure of a fossil fuel facility. It also directs the BPU to look at whether such projects can use existing land and infrastructure.

Ray Cantor, senior lobbyist for the New Jersey Business & Industry Association (NJBIA), told committee members his organization backs the bill as a way to address the forecasted power shortage.

“We support an all-of-the-above approach to energy, but we believe that nuclear power and SMRs are part of the future,” he said. “I wish we had pursued this many years ago, and we would not be in the situation we’re at right now.”

Nuclear Power Advisory Commission

New Jersey is an electricity importer. PJM says fossil fuel generators are closing far faster than new — mainly clean energy — facilities open. That’s occurring as demand is expected to rise from data centers, electric vehicles and building electrification.

The state had counted on the development of its offshore wind sector, with a planned capacity of 11 GW of power, to boost in-state generating capacity. But the plans have stalled, initially stymied by rising costs and supply chain problems, and now by President Donald Trump’s moves to shut down clean energy development.

Several other bills advancing through committees would, if enacted, expand the state’s community solar program, boost the development of storage capacity through an incentive program and require the state to study the viability of generating electricity with ocean wave and tidal power.

The Senate Environment and Energy Committee backed S220, which would set up a seven-member Nuclear Power Advisory Commission inside the New Jersey Department of Environmental Protection. The commission would consider issues such as “the value of nuclear energy generation as a reliable, zero-emission source of energy.” It also would look at the impact of the closure of existing nuclear plants, emerging technologies in reactor designs and the viability of small-scale nuclear plants.

The Legislature is considering another nuclear bill, S4423, that would authorize the BPU to give site approval for an SMR in a municipality where a nuclear facility previously was located. (See N.J. Advances Nuclear, Data Center Legislation.)

Harnessing Wave and Tidal Power

The shift toward nuclear, while favored by Democrats and Republicans, is considered a longer — and more expensive — play than other options. Some advocates believe solar energy is the quickest, cheapest way to develop new energy generation.

To that end, the Senate Environment and Energy Committee advanced a bill, S4530, that would direct the BPU to open registration by Aug. 1 for an additional 3,000 MW of community solar projects, removing the state’s existing annual goal of 150 MW of new capacity a year.

The BPU would set solar renewable energy certificate levels to ensure the full capacity is awarded by Dec. 31, 2029.

The Assembly Telecommunications and Utilities Committee approved a similar bill, as well as a bill, A1478, that directs the BPU to study and promote the harnessing of ocean energy, in particular wave and tidal power.

The legislation would direct the agency to conduct a “comprehensive study” of the topic and incorporate wave and tidal energy generation into the state Energy Master Plan. The agency also should look at the “feasibility and desirability” of establishing a program to stimulate development of ocean-based projects by awarding wave renewable energy credits, similar to the way solar renewable credits are awarded.

Assemblyman Paul Kanitra (R), whose district sits on the Jersey Shore, balked at the suggestion, saying he saw parallels to the way he believes offshore wind projects would impact his district. He expressed concern about “how much is this going to industrialize the ocean? How is it going to affect our marine and fishing industries?”

Committee Chairman Wayne P. DeAngelo (D) said the pilot program and the study would address those kinds of questions.

But Kanitra, who abstained from voting, also questioned the cost of the study, worrying that “as it was with offshore wind, I’m assuming that there’s somebody sitting here in the audience right now whose company probably stands to make a ton of money on this situation, and I’d love to have some clarity on who that is.”

Assemblyman Christian E. Barranco (R), the sole vote against the bill, called it a “half measure” considering the seriousness of the state’s position as a “desert of electrical energy.”

“This is an energy experiment,” he said of the bill, adding that the state needs “robust fired generation.”

“This is not going to help us in any way with the freight train that we’re facing of electrical costs in New Jersey,” he said. “Everything that takes away from the fact that we need generating assets, turbines spinning right now, is getting in the way of what we need to do to make sure we don’t go broke paying our electric bills.”

Data Center Tariff

The Assembly committee also approved A5462, which would require the BPU to develop a tariff for data centers. The bill aims to protect ratepayers from footing the cost of meeting demand from data centers. It also seeks to “incentivize data centers to develop and utilize methods to increase energy efficiency, including through the use of technologies that capture and utilize the heat produced by the data center.”

Jasmine Metellus, a lobbyist for the New Jersey League of Conservation Voters, said the bill not only would “provide an incentive for data centers to drive down consumption, but would protect ratepayers from shouldering an unfair burden.”

“We don’t have enough (electricity) to host the data centers,” she said. “Data centers anywhere on our grid will drive up the cost.”

Storage Expansion

The Senate Budget and Appropriations Committee supported S4289, which would require the BPU to “establish a program to procure and provide incentive awards for the development of transmission-scale energy storage systems” that are likely to be completed in a timely manner.

Clean energy advocates consider storage essential to providing energy when wind and solar cannot, and to helping meet sudden peaks in demand.

The bill would make storage systems eligible for support if they have a capacity of at least 5 MW, are connected to the PJM transmission network and are “qualified to provide energy, capacity, or ancillary services in the wholesale markets established by PJM Interconnection.”

The bill would require the BPU to procure at least 1,000 MW of installed capacity by June 30, 2026, with 350 MW procured by Dec. 31, 2025, and the remainder by June 30, 2026.

The BPU for more than two years has been considering the issues involved in a storage incentive program. The state missed a legislative goal of developing 600 MW of storage by 2021 and now is seeking to put 2,000 MW of storage in place by 2030. (See Developers Seek Deadline Extension in NJ Storage Plan.)

Pam Frank, speaking at the hearing for the American Clean Power Association, said the bill, by helping install grid-scale storage, could save ratepayers tens or hundreds of millions of dollars by avoiding the use of high-cost power at peak times.

But Brian Lipman, director of the New Jersey Rate Counsel, said he’s concerned the proposed program would be overpaying, with incentives that he calculated at $900 million over 15 years. “While some incentive may be needed, we are not convinced that this is the right amount,” he said in an interview with RTO Insider.

Sen. Declan O’Scanlon (R) opposed the bill, saying he needs clarity on the cost to ratepayers.

“We definitely have confusion of whether this will increase cost, decrease cost,” he said. This and other energy bills are designed to make up for “this administration’s woeful lack of planning for our energy future” and its excessive focus on wind generation.

In response, Sen. Paul Sarlo (D), the committee’s chairman, said storage should be part of the “more balanced approach” the state needs in its energy delivery strategy.

“And if it’s a combination of solar with battery power, more battery storage, combination of continuing to buy natural gas — it’s something that we need to all move on,” he said.

Backing the bill, Sen. John Burzichelli (D) said PJM has been “continually hesitant to let solar in the system without battery backup.”

“PJM wants power that’s ready on demand, no matter what time of year and no matter what the weather circumstances are,” he said. He called the position “very reasonable” given their responsibility to provide power. “The issue of this battery storage, and the legislative voice, [is] saying, ‘Look, this has got to be a priority.’”

Posted on

NRG Energy Seeks FERC Approval for LS Power Deal

NRG Energy told FERC that its purchase of generation and the CPower subsidiary from LS Power will not impact competition, despite some overlap in assets in New York and PJM. 

The deal announced in May would see NRG buying 13 GW of natural gas-fired power plants from LS along with the demand response aggregator for $12 billion. (See NRG to Buy 13 GW of Generation Capacity from LS Power.) 

NRG is paying for part of the deal with shares that are estimated to represent 11% of its shares at closing, which would exceed the 10% threshold for functional control in FERC’s merger reviews, the company said in the application filed with the commission June 12 (EC25-102). To avoid getting over that threshold, NRG will deliver only enough shares to LS Power’s shareholders to prevent them from owning 10% or more of NRG’s securities. 

The rest of the shares owed will be delivered to an independent trustee administering a voting trust, which is similar to a deal FERC accepted in 2019. The shareholders could direct the trustee’s vote only when or if the new NRG issues stock, liquidates the company, enters bankruptcy, agrees to a merger or a few other deals FERC previously has found are limited enough to render them “non-voting securities,” the application said. 

The deal will double NRG’s capacity, with most of LS Power’s gas generators being sold located in NYISO and PJM, but the application said standard market screens showed no significant increase in market power. 

“The transaction essentially flips the sizes of NRG and LS Power in both New York and PJM, with very little changes in market concentration,” said the market power analysis filed with the application. 

NRG currently owns 1,201 MW of capacity in NYISO and 2,081 MW in PJM, while LS Power has 1,947 MW and 11,552 MW, respectively, in the two markets. After the deal, NRG would have 2,163 MW in NYISO and 9,463 MW in PJM, while LS Power would have 985 MW and 4,170 MW in the two markets, respectively. 

NRG has only a few other assets in the two markets, including a tolling agreement expiring in 2029 for an 895-MW gas plant on Staten Island, and a contract for 175 MW of transmission capacity on the Linden VFT that can ship power between the two markets, which expires in 2028. It also holds 25% of the Bayonne Energy Center in an arrangement that ends in 2027. 

The analysis NRG conducted found the deal will not materially change market concentration in either the NYISO capacity market or the New York City submarket. The analysis found similar results for PJM and its submarkets. 

The transaction would have LS Power retaining control over 985 MW of the Ravenswood plant in New York City under a tolling agreement, with NRG controlling the rest. The Ravenswood deal will help eliminate any competitive impacts on the New York City submarket, the application said. 

In PJM, NRG will wind up with an additional 7,382 MW of additional capacity, but the dynamics of the deal makes the company’s Herfindahl-Hirschman Index score of market concentration actually fall slightly, according to the analysis. 

Posted on

Nuclear Conference Opens amid Momentous Times

The American Nuclear Society’s annual conference was well-timed in 2025, as the industry is riding a wave of optimism on a series of recent policy and market moves. 

Panelists in the opening discussions June 16 noted the stark differences today compared to several years ago, when U.S. nuclear plants were being shut down because they were uneconomical to run. 

Speakers also noted the cooperative effort that will be needed to turn this confluence of favorable factors into the increase in nuclear generation that so many of the 1,400-plus conference attendees hope to see. 

ANS Executive Director Craig Piercy summed it up in opening remarks: “We’ve gone from how do we wind down what we have to how fast can we get more? … The challenge now is moving from that intention to that implementation.” 

He cited indications that tax credits critical to making nuclear power economical will remain in place, and he cited President Trump’s May 23 executive orders intended to accelerate and expand development of nuclear generation, in part through streamlining oversight by the Nuclear Regulatory Commission. (See Trump Orders Nuclear Regulatory Acceleration, Streamlining.) 

If any further indication was needed that the 2025 conference came amid a time of momentous change, Trump provided it — firing NRC Commissioner Christopher Hanson, who was appointed by President Biden and formerly chaired the commission. 

Later June 16, ANS said in a news release: “A competent, effective and fully staffed U.S. Nuclear Regulatory Commission is essential to the rapid deployment of new reactors and advanced technologies. The arbitrary removal of commissioners without due cause creates regulatory uncertainty that threatens to delay America’s nuclear energy expansion.” 

Speaking that morning, Piercy cautioned about the wholesale slash-and-burn approach implied in Trump’s May 23 directive: “We all have to keep an open mind, but we have to get this right. A full reset of regulation at this stage will likely slow things to a crawl. It’s time we put away the meat cleaver and pull out the scalpel, because we need NRC on the road to recovery as soon as possible.” 

The largest U.S. commercial nuclear operator, Constellation Energy, was represented at the conference by Chief Generation Officer Bryan Hanson, who tempered the grandest aspirations for U.S. nuclear with some hard statistics: The United States built about 100 GW of civilian nuclear capacity roughly from 1965 to 1990, then little more than zero since then. Now President Trump wants to reach 400 GW between 2025 and 2050. 

“So the challenge is real,” he said. “The hearts and minds of all of you in the room today have to embrace and accept that challenge that says what they did from 1965 to 1990 was incredibly challenging.” 

What is not so challenging as it appears, Hanson said, is meeting the coming growth of load demand. “I think the forecasts are incredible at best,” he said. And he noted a recent Duke University study showing extensive U.S. grid capacity could be freed up with demand response. (See U.S. Grid Has Flexible ‘Headroom’ for Data Center Demand Growth.) 

NRC Commissioner Matthew Marzano noted this is not the first “nuclear renaissance” declared in recent memory: Construction of new reactors begun in Georgia (Plant Vogtle) in 2009 and South Carolina (V.C. Summer) in 2013 was heralded as such. But Vogtle took more than a decade and more than $30 billion to complete. The V.C. Summer expansion was abandoned after $9 billion was poured into it. 

“I don’t like to use the word, but there was the first ‘renaissance,’ and V.C. Summer was kind of the death knell of that when that project shut down,” he said. “But I think that this moment is different. There is a confluence of factors … that really makes a huge difference in terms of the future. And so we’re very excited. And of course, this administration has very ambitious goals.” 

Marzano said the ADVANCE Act of 2024 is a springboard toward those goals, making the NRC more efficient and effective. 

He spoke of a cultural shift under way within the NRC after the ADVANCE Act but called it a series of small steps that add up to a very big change — a different approach from the one Trump laid out in May. 

Marzano also asked for input on the process: “We won’t be able to see everything. So that’s where our licensees, our applicants, our stakeholders are going to be very important in helping NRC identify where its blind spots are.” 

Much more is on the agenda at the ANS conference as it continues through June 18, including the workforce development and technology evolution the nuclear power industry will need if it is to exploit the growth potential that stands before it now. But that growth set the tone for the introductory discussions. 

Kirsten Laurin-Kovitz, associate laboratory director for nuclear technologies and national security at Argonne National Laboratory, said: “Everything is aligning for nuclear energy, something we haven’t seen since the 1970s. But this isn’t just a comeback story. It is nuclear energy’s moment to truly energize the world.” 

GE Vernova Hitachi Nuclear Energy Chief Commercial Officer Nicole Holmes listed four factors critical to nuclear seizing the moment: 

    • Companies in the nuclear sector like to be the second to go, but somebody actually has to go first. 
    • The industry must dramatically improve its delivery model, and the government needs to offer support for early movers to have assurance of completion amid the risks. 
    • There need to be partnerships, ecosystems and an array of people supporting the vision. 
    • The United States needs to look beyond its own borders. 

The first small modular reactor in North America, for example, is a GE Vernova Hitachi BWRX-300 that Ontario Power Generation will operate near Toronto, and the reactor pressure vessel was made in Italy. 

“We need to cast a global vision,” Holmes said. “We’re not going to do this all in the United States.” 

One obvious example is the leadership that controls and guides this growth, she said, apparently adding one more yellow flag to those raised by other speakers referring to Trump’s changes. 

“Really, we need to continue to be in a leadership position on how we think about regulation and training programs,” she said. “The world is looking to the U.S. a bit to say, ‘How are we doing this?’ And I think not doing a wholesale changeover of what’s been working, just improving, that would be a smart idea for continued collaboration.” 

Constellation’s Hanson was asked when the nation’s largest nuclear operator might expand its fleet with a new build. 

After the spinoff from Exelon in 2022, he said, “New nuclear was nowhere on our strategy. I would say it’s starting to creep up into the strategy now, because that’s what our customers want.” 

But first, the company will concentrate on existing assets — restart of Unit 1 at the former Three Mile Island and uprates of operating reactors elsewhere. That will add 2 GW of capacity and cost $7 billion to $8 billion. 

“So our dance card is pretty full, when you think about it,” Hanson said. 

Posted on

Stakeholder Forum: Storms, Droughts, and Day-Ahead Markets; Now Hydropower’s Moment to Shine

hydro

Marshall Moutenot

Hydropower has been around for a long time. Over its long history, it has become a steady (if not sometimes forgotten) backdrop to the complicated balancing act of providing reliable national energy grids. Dependable, relatively predictable and dispatchable, hydropower now is stepping into a much more dynamic role in energy markets. 

U.S. power markets, in particular, are evolving rapidly. The increased penetration of wind and solar power means energy grids have to balance volatility, price cannibalization and variable resources that may cause imbalance in grid frequencies. And while this has driven battery storage in markets with high levels of wind and solar, such as ERCOT and CAISO, there still is a need for long-duration storage and dispatchable power. 

Increased weather volatility isn’t just grabbing headlines; it’s reshaping how we generate and trade electricity. To meet market needs and new policies like the extended day-ahead market (EDAM) in California, hydropower is taking center stage. Its reliable supply is crucial for dynamic, inter-market energy trading. 

Why Hydro, Why Now?

With the intermittency of wind and solar now a fundamental part of energy markets, and daily (even hourly — nay, even minute-by-minute) fluctuations common, energy traders need precise generation forecasts for dispatchable resources more than ever. Hydropower, with its storage and ability to quickly adjust output, is uniquely suited for this.  

The overlooked challenge in deploying hydropower, as modern energy grids now demand, is that traditional water forecasting methods haven’t kept pace with emerging climatic trends and variability. 

Conventional forecasts often miss short-term variability for a variety of reasons, including sudden snowmelt, basin-specific behaviors, or unexpected storm impacts. This leaves energy traders with uncertainty, putting resource allocation at risk, and driving (sometimes extreme) fluctuations in price as resources either fall short or overload the market. More precise inflow forecasting doesn’t just improve resource adequacy — it enables energy traders to capture value across volatile markets.  

Accurate short- and medium-term projections empower traders to position hydro assets strategically across day-ahead, real-time and ancillary service markets, so they can make timing decisions with higher confidence. Enhanced lead-time visibility enables bidding strategies that respond dynamically to shifting local marginal prices (LMPs), grid congestion and imbalance settlement penalties.    

By reducing forecast error, traders can better anticipate when to hold back water for peak pricing events or dispatch preemptively during surplus periods, improving P&L performance. Forecast granularity also supports more effective hedging, as predictable inflow reduces exposure to weather-driven volume risk. In intertie-heavy markets like CAISO, EDAM or SPP, forecasting upstream hydrology allows traders to arbitrage regional differences in supply-demand balance, particularly during snowmelt or storm-driven volatility. 

AI Forecasting: More Than Just Hype

While the challenge of adapting to a new model of energy trading won’t be solved overnight, the step change in artificial intelligence and machine learning, and their respective deployment into streamlining the energy transition for legacy energy grids, bring significant advantages in lessening the impact of intermittent energy resource and climatic volatility. 

The soon-to-launch Western EDAM will integrate Pacific Northwest hydropower more closely with California’s demanding markets. Accurate, real-time inflow forecasting is quickly shifting from being advantageous to becoming essential. 

Uncertainty at NOAA

NOAA’s public weather data is invaluable. Unfortunately, recent budget cuts introduce uncertainty about its long-term reliability and resilience, in spite of the heroic efforts by those who remain at the agency.  

Crucially, over the longer term, the private sector has the ability to consistently invest in research and development that will further enhance the latest AI forecasting technologies. While we believe a partnership between national forecasting and private solutions is most desirable, reduced funding for public forecasting may see the gap in accuracy between public and private forecasting increase. 

Hydro Steps up

Realizing hydropower’s full potential starts with accurately forecasting water, an essential first step for navigating the intricate constraints and optimization challenges it faces. Traders who embrace advanced forecasting tools will transform water into a strategic asset while generating enhanced returns. 

We’re moving beyond an era of simply spinning turbines. Hydropower is now positioned at the forefront of strategic energy trading, proactive market engagement and informed risk management in an increasingly volatile landscape. With enhanced forecasting capabilities, hydropower is confidently embracing this expanded role. 

Marshall Moutenot is CEO of Upstream Tech, a software company that provides services in the land and water management industries.