RTO Insider

April 9, 2026April 9, 2026

Reports Flag Soaring Costs, Delays for New Gas-fired Generation

One new report flags risks entailed in the massive planned buildout of gas-fired generation, and another predicts a sharp continued rise in gas turbine prices.

The Institute for Energy Economics and Financial Analysis (IEEFA) on April 8 issued “The Misguided Stampede To Build Gas Power Plants,” which centers on the financial risks and long timelines associated with planning new gas power generation in the United States in the mid-2020s.

Wood Mackenzie on April 1 issued “The U.S. Gas Turbine Market: Navigating Manufacturing Scarcity and Demand Growth,” which predicts that gas turbines will command prices in the range of $600/kW by the end of 2027 — up 195% from 2019.

Commodity price spikes and the age-old law of supply and demand are at the heart of the reports.

To submit a commentary on this topic, email forum@rtoinsider.com.

IEEFA cited S&P Global’s January 2026 estimate that 133 GW of new gas-fired capacity has been proposed in the United States.

This newly built generation would be dependent on a fuel that is vulnerable to price spikes from weather or geopolitical events, IEEFA said. The simultaneous expansion of U.S. LNG exports would subject these power plants to further price volatility by linking the U.S. supply of natural gas to the world market.

Wood Mackenzie said the increase in prices for turbines follows an increase in demand for turbines. Global orders totaled 110 GW by the end of 2025, but global production capacity was only 60 to 70 GW per year, resulting in lead times of up to six years.

The research consultancy expects turbine orders to peak in 2026, and said the major turbine manufacturers — GE Vernova, Mitsubishi Heavy Industries and Siemens Energy — are investing in U.S. production capacity increases.

Major gas turbine manufacturers have increased their U.S. production capacity sharply. | Wood Mackenzie

Wood Mackenzie pointed out that turbines are the largest single cost driver for a combined-cycle generation project but represent only 20 to 30% of the total cost. IEEFA said total costs for the current crop of proposals are running in the $2,500/kW range, roughly triple the price tag of projects built in the early 2020s.

Importantly, that total cost typically does not include the costs of financing or any necessary pipeline upgrades, nor contingency costs if the project runs too far behind schedule due to supply chain constraints or skilled labor shortages.

All of this inevitably is passed along to the consumer, IEEFA said, whether through regulated utility rates or competitive power market prices.

And the economics of gas generation raise the risk of stranded costs.

The report uses these points to argue for solar, storage and wind power development.

“Wind and solar do not share the shortcomings of gas. Their costs are not tracking its rapid upward climb, and the hardware is readily available,” said IEEFA energy analyst Dennis Wamsted, author of the report. “Renewable projects can be built in 18 to 36 months, and they have no fuel costs — ever. Paired with dispatchable battery storage, which continues to benefit from declining capital costs, renewables offer firm power and fixed costs on short development timelines.”

Wood Mackenzie painted a complex web of factors affecting the economics of gas-fired generation.

“This [turbine] supply constraint, compounded by six-year lead times and order books sold through 2027, has fundamentally shifted the market from fuel-economics-driven decisions to procurement-strategy-driven project viability,” said Aurora Tenorio, senior supply chain analyst at Wood Mackenzie.

“Despite the rush in demand for product, the market is also hampered by specialized labor shortages, component bottlenecks in hot-section manufacturing, and ongoing trade-related cost pressures that will continue to limit production throughput improvements. This has all compounded the issue and will affect U.S. power investments well into the next decade.”

Wood Mackenzie identifies data center expansion as the dominant force shaping the gas turbine market. It expects data centers to be the fastest-growing load on the U.S. grid between 2026 and 2031, increasing its power consumption 96%.

IEEFA notes that the U.S. Energy Information Administration and Wood Mackenzie project higher average natural gas prices in the U.S., due to increased exports and increased domestic consumption.

IEEFA said the economic competitiveness of gas-fired generation has depended on three factors — relatively low and stable costs for new turbines, low-cost fuel and low pipeline construction costs — that all seem to be crumbling now.

And IEEFA flags a possibility others have warned about: The data center industry may not grow as much or may not need as much electricity as some analysts predict.

“The stampede for gas makes no sense for consumers, investors or utilities,” the IEEFA report concludes.

April 9, 2026

Montana Co-op OK’d to Recover Tx Costs from SPP

FERC accepted SPP’s tariff revisions to add an annual transmission revenue requirement for transmission service using existing and future facilities that Upper Missouri Power Cooperative owns and places under the RTO’s functional control.

The commission suspended the revisions for a nominal period, effective Jan. 1, 2026, subject to refund, condition, and the outcome of hearing and settlement judge procedures. It also conditionally granted a 50 basis point adder to Upper Missouri’s base ROE and directed SPP to make a compliance filing within 30 days of the March 30 order (ER26-102).

In SPP’s October 2025 filing, Upper Missouri said it would be able to recover costs for its existing transmission facilities in the grid operator’s footprint through a formula rate, rather than indirectly by leasing its equipment to fellow SPP member Basin Electric Power Cooperative.

Montana-based Upper Missouri is a transmission cooperative and supplies wholesale power to its 11 distribution cooperative member-owners. It argued that although it is not currently eligible for the Federal Power Act’s exemption from public utility regulation, it sells more than 4 million MWh of power annually and has member-owner cooperatives that are not exempt.

FERC said SPP raised issues of material fact, including whether the cooperative had justified its proposed ROE, hypothetical capital structure and construction-work-in-progress placeholder, that were more appropriately addressed in hearing and settlement judge procedures.

April 9, 2026

Terra-Gen Fined $5M for Using Batteries to Manipulate CAISO Market

FERC fined Terra-Gen nearly $5 million for strategically using its battery storage resources to repeatedly manipulate CAISO’s market for nearly two years.

The commission in its April 7 order also directed Delaware-based Terra-Gen to pay back CAISO $681,007 in profits made between July 7, 2020, and April 17, 2022, by selectively avoiding the requirements of regulation-down awards for two of its wind-plus-battery facilities participating in the ISO’s day-ahead ancillary services market (IN26-2).

During the period in question, Terra-Gen — through its TGP Energy subsidiary — earned regulation-down awards that required its Mojave 89 and Mojave 90 battery storage resources to be placed on automatic generation control (AGC) to allow CAISO to dispatch them to buy energy off the grid in the real-time market when needed.

But Terra-Gen instead began engaging in a practice of claiming outages for the resources, then removing them from AGC when real-time locational marginal prices were high, even though there was no legitimate basis for doing so, FERC found.

A former Terra-Gen vice president instructed his team that, “if CAISO signals the battery to regulate down in a high pricing event, we will leave the market, resulting in only a small portion of lost revenue” due to forfeit of the day-ahead award, the commission wrote in the order.

“Engaging in this conduct only when LMPs were high was a deliberate effort by Terra-Gen to gain the financial benefits of avoiding high-priced purchases of energy from the grid when instructed to do so by CAISO,” FERC said in the decision. “In contrast, the resources did not claim outages or disconnect from automatic generation control when they received regulation-up awards, because these awards allowed Terra-Gen to profit by selling energy into the grid in real time.”

The Mojave facilities were originally hybrid resources in CAISO’s market, meaning each wind farm and associated battery storage facility had one ISO resource ID. But in November 2020, Terra-Gen converted the Mojave 90 into a co-located facility, meaning its wind and battery components each had their own resource IDs. In 2022, Mojave 89 also converted from a hybrid to a co-located facility.

FERC ordered Terra-Gen to repay CAISO the $681,007 in profit plus interest and undergo additional compliance requirements. As part of those additional requirements, Terra-Gen created a new director position, which will oversee energy markets compliance of FERC regulations and CAISO rules.

April 9, 2026

N.J. Removes ‘Moratorium’ Blocking New Nuclear Plants

New Jersey Gov. Mikie Sherrill has paved the way for new nuclear development by signing a law to remove a permitting rule that for four decades created a “de facto moratorium” on reactor construction.

The bill, A4528, makes it easier for the state Commissioner of the Department of Environmental Protection to approve the manner in which new nuclear plants will dispose of their waste.

Under the previous law, the Coastal Area Facility Review Act blocked the issuance of new permits for nuclear plants by requiring the facility dispose of the waste using a method approved by the Nuclear Regulatory Commission, according to a statement from Sherrill’s office

But that is an “outdated standard that cannot be met,” the governor said. The new law, signed April 8, allows the DEP commissioner to approve projects that use a storage method with a “100% effective safety record in the U.S.,” the statement said.

A statement of explanation attached to the bill states that “extensive operational history across the United States has proven on-site dry cask storage to be highly secure and effective.”

Clean and Reliable

Sherrill, a Democrat who took office in January, pledged to control electricity rate increases and said the state needs to boost electricity supply if it wants to bring down rates. The average residential electricity bill increased by 20% in June 2025.

“By lifting outdated barriers and bringing together leaders across government, industry and labor, we’re setting the stage for our state to pursue new advanced nuclear power,” she said. “This will help New Jersey secure a stronger, cleaner, more affordable and reliable energy future — while keeping the state at the forefront of innovation, job creation and economic growth.”

Sherrill signed the bill at a press conference at the Salem Nuclear Power plant, one of three operated and owned or co-owned by PSEG. The reactors, Salem 1 and 2, and Hope Creek, are the only nuclear generators in the state. Together they produce about 44% of New Jersey’s electricity.

New Jersey supported each of the reactors between 2019 and 2025 with $100 million a year in subsidies to keep the plants open due to their importance to the state’s clean energy goals. PSEG eventually withdrew from the state program to pursue federal tax credits (See PSEG Plans for 80-year Nuclear Generation in NJ.)

The governor told an audience of legislators and press that the state would use new waste disposal methods that have been proven safe “thousands of times” around the country and would be “accompanied by the strictest oversight.”

“We know nuclear has a strong safety record. It’s the most regulated industry on Earth, with meticulous training, monitoring and security,” she said. “This bill recognizes that. It helps us innovate responsibly.”

The governor also announced the creation of a Nuclear Task Force with a goal to “ensure that New Jersey is ready to capture the benefits of new nuclear power, while maintaining the highest standards of public safety and transparency.” The members of the new task force are mainly government workers, with a handful of representatives from the environmental, union and business sectors.

The group, Sherill said, will focus on “five areas, starting with safety and trust, as well as financing, supply chains, workforce and regulatory oversight. And they’ll make sure we’re always listening and addressing people’s concerns in real time.”

Bi-partisan Issue

Like other states, New Jersey is an importer of power because it does not generate enough of its own and views nuclear favorably as it scrambles to generate more electricity. PJM predictions say the region faces a dramatic increase in demand, mainly due to the development of power-hungry data centers.

While Democrats in the state have focused on creating renewable power sources such as solar and wind, nuclear power — which also does not create carbon emissions — is favored by both political parties. The legislation passed with nearly unanimous support in both houses.

Yet, some analysts are skeptical of its viability given the high costs of development, the limited places where such plants could be developed, and the slow pace of development. Analysts say it could take at least five years to develop and build a nuclear plant, and likely a lot longer.

Assemblyman Wayne DeAngelo (D), a primary sponsor of the bill, said the necessity to move to new nuclear sources was clear during last year’s public hearings he and other legislators held on New Jersey’s energy and rate difficulties.

“New Jersey needs generation, plain and simple. That was the bottom line,” he said. “In a state where we’re only generating two thirds of what we use … this is a step in the right direction.”

April 8, 2026

EIA Annual Energy Outlook 2026 Forecasts Major Demand Growth

The Energy Information Administration’s 2026 Annual Energy Outlook, released April 8, includes forecasts for all kinds of energy out to 2050, and when it comes to electricity, the focus is on demand growth.

“After 15 years of nearly flat U.S. electricity consumption, demand has increased by 2.1%/year, on average, over the last five years,” EIA said in the report. “We project electricity consumption will continue growing through 2050 at a rate of 0.9 to 1.6%, with data center server energy use a major factor. Energy use in commercial buildings, home to data center activity, grows more rapidly than in the residential or industrial sectors in all modeled cases.”

Servers used for artificial intelligence are going to skew more energy intensive, and their stock is expected to grow exponentially through 2040 at least. In EIA’s High Electricity Demand case, that growth is assumed to continue through 2050 at least.

Data center energy use grows to 818 billion kWh by 2050 under the high demand case, which is 16 times more energy use from servers than in 2020. The high demand case shows 84% more data center server use than in the baseline case.

“In all cases, electricity use is highest in the commercial sector,” EIA said. “By case design, commercial buildings alone account for the incremental electricity growth in the High Electricity Demand case — largely to meet additional data center server and space cooling demand.”

Data center demand is the largest in the South Atlantic and West South Central census divisions, which are home to Virginia and Texas, respectively.

Another major source of demand in the projections comes from electric vehicles. EIA expects overall demand growth of 25 to 50% by 2050, with data centers and EVs making up 50 to 80% of that, but given how much electricity is used already, they represent only 10 to 25% of overall power demand in 2050.

The future of EVs in the report includes the end of tax credits, but it varies greatly depending on what EPA does with tailpipe emission standards going forward.

“We project about 53% of light-duty vehicles sold in the United States each year are electric by 2032 before stabilizing under those policies; without the policies, sales share gradually increases to around 20% by 2050,” EIA said.

Total generation is expected to grow between 25 and 50% through 2050, depending on the growth of AI and the broader economy.

“Natural gas, solar and wind generation increasingly meet U.S. power demand across all cases examined here,” EIA said. “The combined generation share of these technologies rises from about 60% in 2025 to around 80% in most cases by 2050; in the counterfactual baseline case, natural gas accounts for about 40%, wind for 20% and solar for 20% in 2050.”

Coal generation is expected to fall from 16% to 1% in 2050 if the federal government imposes a cost on carbon, but even without that, it would fall to 5%. Nuclear generation is flatter, but it is expected to drop from 17% in 2025 to 12 to 15% by 2050.

“Natural gas prices and technology costs affect the generation mix because of tight cost competition between natural gas and renewables for new power plant construction,” EIA said. “Wind capacity additions are very sensitive to natural gas price changes, with over five times more additions in the Low Oil and Gas Supply case than in the High Oil and Gas Supply case. Solar additions, meanwhile, vary by a factor of two across the cases and are less sensitive to natural gas prices in part because of their tendency to suppress peak mid-day electricity prices.”

Renewable capacity will increase in all regions, but they vary significantly. The Mid-Continent census division sees the most wind growth at between 20 and 170 GW, with between 75 and 300 GW of renewable growth overall.

Solar is expected to grow by 100 to 235% across the entire country, and the Southeast will see the highest growth at anywhere from double to sevenfold depending on the price of gas and the cost of solar technologies.

April 8, 2026

N.Y. Reports Progress on Energy Storage Buildout

New York has far exceeded the interim target on its energy storage road map — 1.5 GW of capacity by the end of 2025 — but has more work ahead as it pursues 6 GW by 2030.

The 2026 “State of Storage” report issued April 1 by the Department of Public Service (DPS) paints an optimistic picture of progress but notes that only 529 MW of the 1,952-MW storage portfolio was installed as of March 31 (Case 18-E-0130). The other 1,423 MW of contracted or awarded capacity is in various stages of planning or construction but not yet online.

Previous “State of Storage” reports showed 480 MW of storage in service in March 2025, 396 MW in March 2024 and 130 MW in October 2022.

DPS in the report said state-incentivized commercial storage systems of up to 5 MW capacity have an average total installed cost of $666/kWh. At 268 MW, this class of battery energy storage system (BESS) constitutes the majority of in-service projects. Residential systems averaged $638/kWh. Bulk systems larger than 5 MW that provide wholesale market services averaged $524/kWh.

To submit a commentary on this topic, email forum@rtoinsider.com.

When New York boosted its storage goal to 6 GW, it proudly called the road map to that goal “nation leading.” (See NY Sets Strategy to Reach 6 GW of Energy Storage.)

In terms of stated goals, it did lead the nation, but in terms of progress, New York has been far behind the leading states.

As of April 2026, Texas has 12,740 MW of operational storage. As of November 2025, California had 16,942 MW of storage capacity online. The U.S. Energy Information Administration reported in February that developers plan to add 12.9 GW of BESS in Texas and 3.4 GW in California in 2026.

DPS in the report said there has been progress in New York in cost reduction, workforce development and safety requirements.

However, wholesale markets could “better accommodate and make use of energy storage resources,” DPS writes, such as through a participation model for storage as a transmission asset (SATA).

A NYISO SATA proposal introduced in 2024 is expected to reach final tariff development and filing in 2026, the report notes.

‘Dramatic Need’

When New York Battery and Energy Storage Technology Consortium (NY-BEST) Executive Director William Acker spoke to RTO Insider in March, three weeks before the release of the 2026 report, he too flagged SATA.

He said New York lacks a compensation model that recognizes the value of storage to the state’s aging grid, as it limits the need to expand capacity to meet load growth.

“I think we clearly have a dramatic need for this technology in New York state,” Acker said. “Our challenge is making sure that the rule sets are right, and particularly that the energy storage is properly counted toward reliability, as far as T&D as we’re looking at these buildout solutions going forward.”

Another significant headwind for storage development in New York is the state’s regulatory structure, he said. “And it’s not just for storage, actually building anything is difficult.”

Acker pointed to one of the bullet points in a January 2026 NYISO report on the causes of New York’s high electricity prices: Of the 106 projects that had completed the NYISO interconnection process since 2019, only seven had begun construction. An earlier NYISO report tallied 4,315 MW of capacity leaving the system since 2019 and only 2,274 MW being added.

An added hurdle for storage: It is not permitted at the state level, leaving it vulnerable to local moratoria and restrictions imposed by officials worried about fire after three highly publicized BESS blazes in as many months in New York in 2023.

This remains a vexing issue for NY-BEST. Fires are rare and they most often strike older technology placed in outdated configurations, Acker said.

But when BESS fires do happen, they stick in the public mind.

New York added some of the nation’s strongest BESS fire codes Jan. 1, he said. “We’re hopeful that as people understand that better, we can open up more of the siting around the state. But really, that’s I think the major barrier right now.”

Acker sees other signs of progress.

“So, what’s changed over the past year really has been quite a few projects being approved and moving forward with the new and necessary incentives,” he said. “But actual commissioned projects, I don’t think has increased that much.”

Three weeks later, the 2026 “State of Storage” report would bear out Acker’s estimation: In-service storage capacity rose 10%, from 480 MW in 2025 to 529 MW in 2026, while storage capacity contracted but not yet in service jumped 54%, from 923 MW to 1,423 MW.

Another step forward was New York launching its first index storage credit solicitation in July 2025, Acker said. When bidding closed in January 2026, the state had received proposals for 46 projects comprising roughly 6 GW of power capacity and 30 GWh of storage capacity.

“The index storage credit,” Acker said, “makes for a method to give more confidence in the future revenues of the project, and clearly, it received a lot of attention from the developer space.”

April 8, 2026April 9, 2026

Xcel Files Large Load Tariff Proposal in Colorado

Xcel Energy is seeking approval for a large load tariff in Colorado that includes an optional clean transition tariff to encourage the development of carbon-free resources.

Public Service Company of Colorado (PSCo), an Xcel subsidiary, filed the proposal with the Colorado Public Utilities Commission on April 2.

The proposal is intended to address concerns “over the immense energy needs of new, large customers, such as data centers,” Robert Kenney, president of Xcel Energy Colorado, said in a release.

“Addressing those concerns by updating rules and policies will help make sure we manage this growth responsibly as we protect customers,” said Kenney, who noted the potential jobs, investments and innovation that large load customers bring.

To submit a commentary on this topic, email forum@rtoinsider.com.

The tariff would apply to new customers with an electric load of at least 50 MW and to existing customers that are expanding by 50 MW or more. Large customers would pay for the power infrastructure needed to serve them, including transmission, substations, interconnection upgrades and new electric generation.

“This ensures that existing customers are not paying for the needs of the large load customers,” Xcel said.

In other provisions, customers would be required to provide credit support such as a guaranty or cash deposit. The minimum service period would be 15 years. Customers would be able to cancel service with 24 months’ notice but could be required to pay an exit fee.

Clean Transition Tariff

PSCo also proposed an optional clean transition tariff (CTT), aimed at supporting the acquisition of certain carbon-free generation resources.

A CTT resource is one that uses “emerging carbon-free electric generation technologies or long-duration storage technologies,” PSCo said in its filing. Examples include geothermal, hydroelectric, hydrokinetic, nuclear, renewably sourced hydrogen or fossil resources with carbon capture and storage. “Commercially mature” wind, solar, short-duration storage and carbon-emitting resources would not be eligible.

Under the proposal, the CTT resources may be those identified through PSCo’s resource planning process but not chosen for development or procurement. Alternatively, they could be emerging-technology projects that would not be selected through the company’s least-cost procurement process.

The customer would choose the resources and pay for them through agreements with PSCo, which would have discretion to evaluate project feasibility and negotiate the ownership structure.

The PUC has not yet set a procedural schedule for considering the tariff. Xcel asked that the new tariff become effective May 3.

Xcel is also working on large load tariffs in Minnesota, Wisconsin and Texas, CEO Bob Frenzel said during a fourth-quarter earnings call in February.

Large Load Tariffs Spreading

As the number of large load customers grows across the U.S., so does the adoption of large load tariffs.

In their Database of Emerging Large-Load Tariffs (DELTa), the Smart Electric Power Alliance and North Carolina Clean Energy Technology Center found 77 either in place or being considered at utilities around the country. Large load tariffs have not been considered or adopted in only 12 states. (See SEPA Tracks 77 Large Load Tariffs Nationally with DELTa Database.)

A November 2025 study by RMI looked at the most common safeguards in 65 large load tariffs. Those included a minimum contract term, minimum monthly billing, collateral requirements and exit fees. Twelve of the tariffs reviewed allow large customers to transfer to another customer contracted capacity that is no longer needed — along with financial responsibility for the capacity.

PSCo’s commitment to filing a large load tariff came out of a PUC proceeding on the company’s Just Transition Solicitation, its proposal for how much energy it needs to serve customers for the next five years, with coal plant retirements factored in. The proposal also aims to reduce emissions and support communities where coal plants are retiring.

During the proceeding, environmental groups including the Natural Resources Defense Council, Sierra Club, Southwest Energy Efficiency Project and Western Resource Advocates backed the idea of a CTT.

Many companies developing large data centers might be willing to pay more for resources that help them meet clean energy goals, the groups said.

“At a high level, the clean transition tariff should allow large customers to voluntarily pay to be served by innovative, zero-emission resources that Public Service would not otherwise procure,” the commission said in November in its Phase I decision on the JTS.

April 8, 2026

Spill at Northwest Dams Risks Causing ‘Catastrophic Harm,’ Feds Tell 9th Circuit

Federal agencies urged the U.S. 9th Circuit Court of Appeals to pause a lower court’s order that would increase spill levels at eight dams on the Columbia and Snake rivers, saying the order risks increasing rates and causing costly blackouts.

In the April 7 motion for stay pending appeal, the federal defendants said U.S. District Judge Michael H. Simon’s order aimed at protecting migrating salmon and steelhead “substantially increases the risk of catastrophic harm to the public through blackouts.”

Represented by the U.S. Department of Justice, the federal defendants include the U.S. Army Corps of Engineers, the Bureau of Reclamation, the National Marine Fisheries Service and the U.S. Fish and Wildlife Service.

“A stay pending appeal is warranted,” the motion stated. “Absent a stay, the elevated spill levels will cause irreparable harm to the public by increasing the cost of electricity, reducing grid stability and substantially increasing the risk of blackouts. Blackouts in neighborhoods disrupt communities, blackouts in hospitals cost lives and blackouts in military installations threaten national security.”

The agencies said the Bonneville Power Administration, which is not a party to the suit, expects the spill levels “to result in a loss of generation capacity of 1,000 average MW in August and 500 average MW in September.”

BPA has said it expected to end fiscal year 2028 with $397 million in financial reserves. But with the court order, the agency anticipates ending 2028 with $196 million in reserves.

BPA has launched a rate proceeding to tackle the issue. (See BPA Explores Rate Alternatives Following Order to Increase Dam Spills.)

In an email, Charisa Gowen-Takahashi, an attorney with Earthjustice who represents the plaintiffs, said the federal agencies’ request to block the injunction “is yet another attempt to stall on preventing extinction.”

“These salmon need help urgently,” Gowen-Takahashi added. “The stakes are too high for further delay.”

The Public Power Council filed a separate appeal the same day as the agencies’ motion.

In a news release, PPC said the appeal seeks to mitigate the order’s impact on electricity costs and grid reliability.

PPC CEO Scott Simms said Simon failed to account for the systemwide consequences of his order.

“An appeal is necessary to restore balance,” Simms said in a statement. “The law requires consideration of all authorized purposes of the Columbia River system – not just one – and that balance was not fully achieved here where the science supports the conclusion that the threatened fish species are recovering.”

The Inland Ports and Navigation Group also has appealed.

‘Overblown’

The issue stems from a Feb. 25 court order in which Simon granted a preliminary injunction sought by the states of Oregon and Washington, tribes and environmental groups. (See Judge Orders Spill at Northwest Dams to Aid Salmon, Despite Energy Concerns.)

The order requires the U.S. Army Corps of Engineers and the Bureau of Reclamation to spill large amounts of water over the eight dams to protect migrating salmon and steelhead in the Columbia and Snake rivers instead of running it through turbines.

The long-running case now concerns an environmental impact statement and a biological opinion from 2020 that the court ordered the federal agencies to prepare for the Federal Columbia River Power System.

In challenging the analysis, the plaintiffs alleged the Army Corps’ plan failed to adequately protect salmon.

The parties stayed the case after striking a deal with President Joe Biden, which included, among other things, $1 billion toward salmon restoration. President Donald Trump upended the deal in June 2025, claiming it would negatively impact energy production, shipping channels and water supply for local farmers. (See Trump Directs Feds to Withdraw from Deal on Snake River Dams.)

When the case resumed, plaintiffs sought injunctive relief beginning March 1, urging the court to require federal defendants to increase spill levels, lower reservoir levels and implement emergency conservation measures for the salmon.

In granting the request, Simon said the injunction includes a provision for the federal agencies to adjust spill for emergency power generation and transportation needs. However, he rejected arguments that increasing spill levels could impact power generation, saying the granted relief is “narrowly tailored and essentially maintains the status quo.”

The order would impact eight dams on the lower Snake and lower Columbia rivers: Ice Harbor, Lower Monumental, Little Goose, Lower Granite, Bonneville, The Dalles, John Day and McNary.

In their April 7 motion, the federal agencies contended that under the previous deal, parties agreed to spill levels less than plaintiffs sought in their injunctive relief request.

When Trump assumed the presidency, “Plaintiffs now insist that substantially higher spill — particularly in August, when the agreement allowed reduced spill — is crucial to avoid imminent harm to fish, despite agreeing until 10 months ago that less spill protected the fish just fine,” the federal defendants contended.

Following the plaintiffs’ win, “initial estimates indicated the injunction could impose approximately $140 million/year in increased power costs,” according to Simms.

Commenting on PPC’s appeal, Gowen-Takahashi said she expected the move, adding that “we think the 9th Circuit will agree that we can protect salmon while making sure we have a reliable supply of energy in the Northwest.”

“We’ve heard complaints like this before about reliability and costs when the courts have previously ordered more spill over the dams for salmon,” Gowen-Takahashi said. “But those fears were overblown then, and they are overblown now.”

April 8, 2026April 8, 2026

ISO-NE, PJM Market Monitors Concerned about Vistra Acquisition of Cogentrix

Vistra’s acquisition of Cogentrix Public Utilities would increase market power and could undermine competition in ISO-NE and PJM, market monitors for the RTOs argued in comments filed April 7 (EC26-63).

The ISO-NE Internal Market Monitor urged FERC to require more analysis and consider behavioral conditions to address potential issues, while the PJM Independent Market Monitor said it opposes the transaction in the absence of mitigation measures.

The acquisition would add 1,625 MW to Vistra’s 3,567-MW portfolio in New England, the ISO-NE IMM noted. The combined total would equal about 16% of installed capacity in New England. In PJM, the acquisition would increase Vistra’s portfolio from 14,270 MW to 17,098 MW, the PJM IMM wrote.

“The transaction would result in a material increase in market concentration and structural market power, particularly within the dispatchable generation segment that is crucial to meeting the system’s energy and reserve requirements,” the ISO-NE IMM wrote.

The concentration of ownership would not fail FERC’s competitive analysis screen in either RTO. Vistra wrote in its application that Herfindahl-Hirschman Index (HHI) analyses indicated no screening violations and no potential competitive issues.

HHI threshold analyses are based on the sum of squared market shares of all participants. While FERC has long relied on HHI tests to evaluate market power, both market monitors argued that HHI screening is not adequate.

The ISO-NE IMM wrote that “the HHI and Competitive Analysis Screen do not provide a robust competitive analysis for the impact of the proposed transaction on the ISO-NE markets and the potential for the exercise of market power by the combined applicants.”

The inclusion of small-scale and intermittent resources in the HHI analysis “masks a heavy concentration of resources with sizeable market shares,” the market monitor wrote.

It said its pivotal supplier test and residual supply index metrics indicate the acquisition would create a portfolio that is pivotal “in a substantial share of real-time intervals, including the majority of high-load hours.”

It also wrote that initial analysis indicates the combined portfolio could have “both the ability and the incentive to profitably raise prices,” adding that existing market power mitigation measures may not be adequate to prevent this behavior.

The PJM IMM expressed similar concerns to those included in its recent comments about Talen Energy’s proposed acquisition of 2.5 GW of generation from Energy Capital Partners. (See Monitor Warns Talen Acquisition Will Increase PJM Market Concentration.)

The market monitor wrote that Vistra is a pivotal supplier in PJM’s energy and capacity markets and the acquisition would increase the company’s means and motive to exert market power.

It also reiterated its concerns about a broader concentration of generation ownership in PJM amid “extremely tight” market conditions.

“The current need for new generating capacity in PJM is an opportunity for increased competition and new entry,” Monitoring Analytics wrote. “Instead, ownership of existing generation is being consolidated in a small group of owners.”

New England does not face as tight market conditions, but growing demand, coupled with the region’s struggles to add new capacity, could create resource adequacy issues starting in the mid-2030s. ISO-NE forecasts the region’s reserve margin declining from about 17% in 2026 to 8% in 2034.

The ISO-NE IMM asked FERC to establish a hearing or settlement proceeding to enable more in-depth analysis and consider more requirements to mitigate potential issues.