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January 15, 2026

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FERC Staff Recommends Relicensing of Idaho Power’s Hells Canyon Dams

FERC staff said the commission should relicense three Idaho Power-owned hydroelectric dams that have been operating under annual licenses since 2005, finding the company’s proposed measures, along with staff recommendations, adequately mitigate the environmental impact of the dams.

Commission staff on Jan. 14 issued a draft supplemental environmental impact statement (SEIS) after Idaho Power filed proposed modifications for the 1,222.3-MW Brownlee, Oxbow and Hells Canyon dams, collectively the Hells Canyon Project.

The dams are located along the Snake River in Idaho and Oregon, and occupy about 5,270 acres of federal land, according to the draft SEIS.

“We are pleased to have reached this milestone in the relicensing process for the Hells Canyon Complex, which is an essential part of Idaho Power’s resource portfolio,” Idaho Power spokesman Brad Bowlin told RTO Insider.

The company will provide detailed answers to FERC by March 2, which is the deadline to submit public comment on the draft SEIS.

Idaho Power applied for a new license in 2003 to operate the Hells Canyon Project. The company has operated the dams under annual licenses since the current one expired in 2005, the SEIS states.

FERC issued the final environmental impact statement for Hells Canyon in 2007, but following several new developments, including settlements with key stakeholders, FERC prepared a supplemental environmental review to account for these changes.

Among the recent developments is a 2019 settlement between the company and Oregon and Idaho that resolved disputes over water quality and protections of Chinook salmon and steelhead. Following the settlement, Oregon and Idaho issued 401 certifications for Hells Canyon under the Clean Water Act.

In 2020, Idaho Power filed a supplement to its license application that included new environmental measures proposed under the 2019 settlement.

In 2022, FERC issued a notice of intent to prepare a final SEIS to address the new measures. Following the notice, Idaho Power filed a settlement agreement with the U.S. Forest Service in 2024 related to the company’s use of federal land.

Hells Canyon Dam | Idaho Power

In the Jan. 14 draft SEIS, FERC staff wrote the main concerns with relicensing are the effects on sediment supply and transport, water quantity and quality, aquatic resources, terrestrial and cultural resources, and the adequacy of recreational facilities to meet expected demand over the term of any new license.

FERC staff recommended relicensing the project under most of Idaho Power’s proposed measures and “certain mandatory conditions and recommendations made by state and federal agencies and some staff-recommended modifications to further minimize project-related effects on aquatic and terrestrial resources, threatened and endangered species, recreation resources, and cultural resources,” a news release stated.

The approach recommended by staff includes all conditions in the 401 certifications issued by Oregon and Idaho except for three: implementation of three phosphorus load-reduction programs, implementation of a program that consists of completing habitat restoration projects in the Snake River Basin upstream of the project and implementation of a mercury and methylmercury study.

“Because there is no project nexus associated with these conditions, staff concluded that there would be no project-related benefit to implementing these measures and does not include them in the staff alternative,” the draft SEIS states.

The draft SEIS estimates power generated by Hells Canyon under the staff-recommended approach could “cost $120,748,800, or $21.67/MWh, less than the likely alternative cost of power.”

“We chose the staff alternative as the preferred alternative because: (1) the project would continue to provide a dependable source of electrical energy for the region (5,571,005 MWh annually); (2) the public benefits of the staff alternative would exceed those of the no-action alternative; and (3) the proposed and recommended environmental measures would protect and enhance environmental resources affected by the project,” the draft SEIS states. “The overall benefits of the staff alternative would be worth the cost of the proposed and recommended environmental measures.”

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BPA Prepares Pilot Program to Reduce Balancing Reserves

The Bonneville Power Administration is starting a new pilot program to decrease the balancing reserve capacity it must hold to account for variable resources by connecting new types of generation facilities to its grid.

As part of the New Generation Technology Pilot, BPA will work with generators to “encourage development of technologies and operations” that reduce balancing reserve capacity requirements in the agency’s balancing authority area, BPA staff said at a Jan. 13 workshop to explain the program.

A presentation from the workshop outlined three objectives for the pilot:

    • incentivizing “accurate scheduling and performance”;
    • establishing a “technology inclusive policy” for participation; and
    • fostering collaboration between BPA and generators “to enable novel approaches to lower the amount of capacity needed” to integrate variable generation.

Participating resources could include nuclear power plants or wave energy structures, BPA electric engineer Ross Ponder said during the workshop.

A proposed project will need to meet performance metrics, which will be established based on historical balancing reserve capacity usage and projections, Ponder said. Participation in the pilot will rely on a reduction in station control error (SCE), and BPA will revise a project’s performance expectations if the project increases its SCE, Ponder said.

The pilot program “essentially can be … used to provide a method to reduce generators’ balancing reserves capacity,” Ponder said.

Battery energy storage systems (BESS) and nuclear facilities are two possible resource types eligible for the pilot, Bart McManus, a BPA engineer, said at the workshop.

However, “we are not saying [a project] has to be BESS or nuke,” McManus added. “We are looking for innovative strategies. We don’t run solar plants. We don’t run nuke plants. So if you have something that could work, absolutely bring it to the table and we will talk through it.”

One meeting participant asked about the current performance and buildout of co-located generation and battery storage in BPA’s region.

“We don’t really have a lot of examples of co-located generation,” BPA engineer Nancy Morales said. “So the status quo is there is minimal impact of co-located resources.”

A meeting participant also said that the pilot has “technically been around for a while, but the last I heard about it … is that nobody had taken Bonneville up on the offer to participate in it.”

“When did this pilot begin and has anyone taken you up on it yet?” the participant added. “Is there anything that is different about it now?”

“We have a few requests to join the [pilot],” Ponder said. “We are currently in the design phase … but we don’t have anyone active yet.”

Ponder added that he expected to hold a few more meetings later in 2026 to discuss the pilot and respond to future questions.

When a generator or load connects to BPA’s grid, BPA must provide balancing reserves at a rate and amount determined by the agency for reliability purposes. BPA can provide balancing reserve capacity to cover a 99.7% planning standard for balancing error events without unreasonably impairing reliability, the agency said in a September 2025 document.

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IESO Reliability Compliance Plan Focuses on CIP, Modeling, IBRs

IESO is targeting six areas of NERC’s reliability standards in its 2026 compliance program, largely continuing a focus on issues it has prioritized since 2023.

The 2026 Market Assessment and Compliance Division (MACD) Reliability Standards Compliance Monitoring Plan will prioritize:

    • Critical Infrastructure Protection (CIP)
    • Inadequate Models Impacting Planning and Operations (MOD/PRC)
    • Gaps in Program Execution (FAC)
    • Automatic Underfrequency Load Shedding (PRC)
    • Inverter-Based Resources (PRC), and
    • Extreme Weather Response (EOP)

MACD says its priorities consider the reliability standards’ applicability to Ontario; the assessed reliability risks and compliance history of each standard; power system infrastructure and demand changes; and emerging threats and vulnerabilities.

“While market participants are required to comply with and be able to demonstrate compliance with all applicable reliability standards at all times, MACD puts a more significant focus on a subset of these market rules and reliability standards that are more explicitly monitored for compliance in a given year,” IESO said.

The MACD conducts scheduled and unscheduled audits, in addition to accepting self-reports and self-certifications.

NERC’s 2025 reliability indicators | NERC

MACD selects the subject of scheduled audits based on “both market participant specific information and Ontario-specific risks.” Subjects are provided at least 90 days’ notice before the start of scheduled audits. MACD also may conduct unscheduled audits “potentially with very little or no notice,” it said.

NERC Concerns

In its 2025 State of Reliability Report, NERC said key performance metrics such as frequency response and misoperation rates continued to improve or remain stable.

It said weather continued to be responsible for the most severe outages in 2024, citing two significant winter storms and five major hurricanes. It noted an improvement in winter performance, with no operator-initiated load sheds, in part due to efforts to improve generator performance during extreme cold.

The report says large data centers pose a “significant near-term reliability challenge” because they are growing faster than generation and transmission infrastructure. It said more accurate models of data centers’ operational characteristics are needed because of their “voltage sensitivity and rapidly changing, often unpredictable, power usage.”

NERC also noted improvements in frequency response in regions with high concentrations of battery energy storage systems, but said some inverter-based resources “continue to unexpectedly reduce output following disturbances that generators have historically been expected to ride through.”

MACD Findings

MACD’s Sanctions and Negotiated Settlements notices include violations of market rules, as well as several cases involving NERC and Northeast Power Coordinating Council reliability standards.

In 2022, IESO reached a $1.67 million settlement with Ontario Power Generation and a $1 million agreement with Hydro One Networks for failing to properly plan a maintenance outage at the Darlington Nuclear Generating Station. IESO alleged that OPG and Hydro One failed to recognize the purpose and limits of electrical protective relay schemes. In one instance, equipment at the Bowmanville Switching Station operated without this scheme for approximately five months without incident, which IESO concluded “gave rise to a significant market and electrical reliability concern with a low probability of occurrence.”

In 2023, it reached a $327,000 settlement with Kirkland Lake Power Corp. and a $12,500 agreement with Iroquois Falls Power Corp. IESO said Kirkland Lake failed to maintain evidence that it maintained its equipment as required and, in another event, incorrectly adjusted the underfrequency trip settings on certain electromechanical relays. Iroquois Falls lacked evidence that it conducted the required annual vegetation inspection of a transmission line in 2018.

GenSet Resource Management agreed in 2023 to pay $500,000 for its failure to comply with dispatch instructions for operating reserves between 2013 and 2019, which IESO said posed a reliability risk.

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Data Centers Can Drive Down Rates, Boost Local Economies

By Nick Myers

Over the past year, as I have zig-zagged across the country meeting with national and state regulators, the national conversation has centered around one single topic: data centers. Conference after conference, panel after panel all seem to focus on the rapid growth of data centers and the challenge of integrating them into the electric grid while maintaining reliability and keeping rates affordable for customers.

I wholeheartedly agree with the Trump administration’s “America’s AI Action Plan” when it states that the United States is in a race to achieve global dominance in artificial intelligence (ai.gov). I agree that our economic competitiveness, technological achievements and national security in the coming years and decades will largely depend on our AI ecosystem.

So, on the one hand, as a state regulator I know that a wave of data centers is coming. For example, in its recently filed rate case, Arizona Public Service (APS) reported that it is contractually committed to serving approximately 3,296 MW of data center load, of which 2,081 MW is from data centers expected to come online by the end of 2028. Further, APS is in conversations with additional data centers representing another 16,908 MW of potential load.

On the other hand, as I travel across Arizona, I consistently hear from residential customers who are understandably concerned that data centers will drive up their rates. Data centers require massive amounts of generation resources and often significant grid upgrades. I understand why residential customers may be concerned. As a regulator, my commitment is to evaluate each new proposal once all the relevant data has been presented and rigorously reviewed.

data center

Nick Myers

The good news is that regulators and utilities are fully aware of the potential cost-shift and subsidization problems data centers pose. A commitment to “growth pays for growth” and properly structuring tariffs and energy supply agreements (ESAs) can ensure that data centers are paying all their costs, even if their projected load does not materialize.

Not only that, many residential customers may be unaware that data centers can also apply downward pressure on the rates of all other customers. Instead of driving up residential rates, data centers may help keep them lower. Also, data centers can provide significant economic benefits to local communities. This means data centers not only help advance national AI priorities, but they can also contribute to the flourishing of local communities where they are located.

Data Centers Can Drive Down Rates

Instead of driving up rates, data centers— with properly structured tariffs or ESAs— can help drive down rates for all other customers, including residential customers. Electric utilities have fixed costs (power plants, distribution and transmission lines, substations and so on) that are spread across a utility’s customer base. As a utility’s customer base grows, these fixed costs are spread across more customers so the average cost per customer goes down.

The same applies when a high-load customer is added to a utility’s grid. Because high-load customers, like data centers, use a lot of electricity, they pay a significant share of those fixed costs. Therefore, under standard ratemaking, adding data centers to a utility’s customer base will reduce upward pressure on rates for all other customers.

Adding data centers to a utility’s grid may also result in added grid efficiencies that benefit all customers. For instance, Tucson Electric Power (TEP) recently explained that adding a 286-MW data center in its service territory will “reduce the overall cost for TEP to serve all its customers” because the data center’s “energy use will help flatten [its] overall system load profile thereby making more efficient use of the grid.” This flattening of its load profile will allow TEP “to operate its generation fleet and energy delivery system in a more optimal manner while spreading its fixed cost over a greater volume of energy.”

In addition to spreading fixed costs and improving asset utilization, data centers also provide long-term, stable demand that may reduce the financial risk of utilities and lower their borrowing costs to the benefit of all customers. In service territories where load is declining or flat, large new customers like a data center may help maintain revenue adequacy without having to raise rates on existing customers.

Data Centers Can Boost Local Economies

Data centers can also provide significant economic benefits to local communities. According to Loudoun County, Va., the data center industry in the county has significantly reduced the tax burden on residential taxpayers. The county’s real property tax rate has dropped from $1.285 per $100 assessed value in 2008 down to $0.805 in 2025. Based on the 2025 average assessed value for a residence in the county, this amounts to real estate tax savings of roughly $3,600 a year.

Closer to home, the Arizona Corporation Commission recently approved an ESA between TEP and a planned data center in Pima County developed by Beale Infrastructure Group, a $3.6 billion capital investment expected to bring in $152 million in tax revenues over 10 years, including $58.5 million to Pima County and $93 million to the state of Arizona. In addition to increased tax revenues that directly benefit local schools, Beale has committed to invest an additional $15 million in the community, with $5 million allocated for STEM and trade school education. The data center will also generate 3,000 construction jobs over the multiyear period and 180 on-site jobs by 2029 with an average annual salary of $64,000.

Conclusion

In the end, the data center conversation should focus on two core realities. First, with properly structured tariffs or ESAs that prevent cost-shifts, data centers can help drive down rates for other customers by spreading fixed utility costs across more load, improving grid efficiency and providing stable, long-term demand that benefits all ratepayers. Second, data centers can serve as powerful engines of local economic growth — expanding tax bases, creating high-quality jobs and attracting significant private investment. With sound regulatory oversight and a clear commitment to ensuring that growth pays for growth, data centers can strengthen both our electric grid and our local communities, while also advancing national priorities.

Nick Myers is chairman of the Arizona Corporation Commission.

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EIA Predicts Sustained Power Growth in 2026 and 2027

The U.S. Energy Information Administration (EIA) is forecasting the highest power demand growth in a quarter century in 2026 and 2027, largely due to the proliferation of data centers.

The predicted 1 and 3% growth in 2026 and 2027 would be the first time since 2007 that power demand has increased four years in a row and would be the largest four-year increase since 2000, EIA said Jan. 13.

EIA’s January 2026 Short-Term Energy Outlook also projects that solar power output will continue its sharp growth, natural gas will provide a slightly smaller percentage of U.S. electricity and coal will resume its decline.

EIA predicts:

    • Solar generation will increase by more than 20% in both 2026 and 2027, giving it 10% of U.S. power generation by the end of 2027, up from just 5% in 2024.
    • Natural gas generation will be unchanged in 2026 and increase 1% in 2027; this gives it a 39% share of the power supply in both years, down from 40% in 2025 and 42% in 2024.
    • Coal will provide 15% of U.S. power in 2026 and 2027, down from 17% in 2025 and 16% in 2024.
    • Wind power will tick up from 11% to 12% of the power supply.
    • Nuclear and conventional hydropower will hold steady from 2024 to 2027, with nuclear providing 18 or 19% of the nation’s power and hydro 6%.
    • The benchmark Henry Hub price for natural gas will start to increase in 2027 on higher natural gas consumption in the electric power sector and growing demand for LNG exports, with three new export facilities coming online.

“U.S. energy production remains strong, and natural gas output is expected to grow to nearly 109 billion cubic feet per day this year,” EIA Administrator Tristan Abbey said in the news release. “Natural gas supply is critical as we forecast that U.S. liquefied natural gas exports expand and electricity demand rises through 2027, driven largely by increasing demand from large computing facilities, including data centers.”

The increases are a marked change from the early part of this century — EIA reports that U.S. electricity consumption increased by an average of only 0.1% per year from 2005 to 2020.

Other projections from EIA’s January outlook include:

    • Power demand growth is being driven in part by data centers and other commercial users; as a group, they bought 2.4% more electricity in 2025 and are projected to buy 2.4 and 4.3% more in 2026 and 2027.
    • The industrial sector, by contrast, is expected to see 1.6 and 3.4% growth in 2026 and 2027 after 1.7% growth in 2025.
    • Total generation by the electric power sector increased 2.5% in 2025 to nearly 4,300 BkWh; it is expected to increase 1% in 2026 and 3% in 2027.
    • The 4% decrease in natural gas generation and the 13% increase in coal generation seen in 2025 were both due largely to higher natural gas prices.
    • Coal generation will decline 9% in 2026 and be nearly unchanged in 2027; even with deferred coal plant retirements, coal generating capacity is expected to decline by 13 GW — nearly 8% — over the two years.
    • Nuclear power generation will increase 2% in 2026, largely due to the anticipated Palisades nuclear plant restart, but no change is expected in 2027.
    • Wind power generation will increase 6% in both 2026 and 2027, even factoring in the uncertainty facing the offshore wind sector.
    • Solar will hit 171.3 GW of installed capacity in the fourth quarter of 2026, finally surpassing wind (170.7 GW) as the leading U.S. renewable by nameplate capacity and becoming second only to natural gas (495.1 GW) among all forms of power generation.
    • However, solar’s low capacity factor will leave it fifth among the six major types of power generation sources in 2026, providing 8% of U.S. power; only hydropower — 6% — will be lower.
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DOE Official Faces Questions on PJM Resource Adequacy at House Hearing

Democrats used a House Energy and Commerce Subcommittee on Energy hearing on bills to shore up the electricity sector’s physical and cyber security as an opportunity to criticize Trump administration policies affecting resource adequacy in PJM.

“This is an area where the committee has a history of bipartisan success, and we should build on that,” Rep. Kathy Castor (D-Fla.), ranking member of the House Energy and Commerce Committee, said during the Jan. 13 hearing.

“However, we cannot ignore that right now, the greatest threat to grid reliability and security is the president and Republican policies. The arbitrary project cancellations, higher cost and uncertainty have driven the country into an electricity crisis,” she said.

Castor criticized the Trump administration’s December decision to revoke permits for the country’s remaining offshore wind projects, some of which were close to completion. Developers have challenged that decision in court and already won an early victory. (See Judge Again Lifts Revolution Wind Stop-work Order.)

Castor asked Acting Secretary of Energy Alex Fitzsimmons whether he had a role in any of the administration’s orders under Section 202(c) of the Federal Power Act to keep fossil fuel-fired power plants open, to which he said he did as director of Office of Cybersecurity, Energy Security, and Emergency Response.

In response to a follow-up question, Fitzsimmons affirmed that orders to keep open the Eddystone plant in Pennsylvania came in response to a looming shortage of supply in PJM. (See Energy Secretary Wright Issues 3rd Order Keeping Eddystone Open.)

“If you believe there is an energy shortage in PJM, why did you take what the federal court described as an ‘arbitrary and capricious action’ to cancel offshore wind projects that were permitted and ready to go?” Castor asked.

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Fitzsimmons said PJM had asked DOE to issue the 202(c) order and that Eddystone has supported grid reliability since the first such order was issued last May.

“Offshore wind is some of the most expensive energy that exists,” Fitzsimmons said.

Castor responded that canceling projects at the last minute is very expensive as well.

“A business has invested billions of dollars,” Castor said. “They’ve gone through and they’ve gotten permits. They’ve hired a bunch of people, and then at the 11th hour, a president who’s focused on retribution, who the court said ‘acts in an arbitrary and capricious manner,’ comes and takes a hatchet to it, and it’s costing people a lot of money, and they’re angry about it.”

The Department of the Interior ultimately made the decision to withdraw the permits for offshore wind plants, Fitzsimmons said.

Castor asked to enter into the record a brief from PJM that was filed with a federal court recently to support Dominion Energy’s request to overrule the stop-work order on its Coastal Virginia Offshore Wind (CVOW) project.

“The CVOW project, with a nameplate rating of 2,489 MW, is an integral component of needed new generation that PJM has been relying upon to timely achieve commercial operation,” PJM said in the brief. “The CVOW project’s continued development and ability to produce 2,489 MW for the interstate grid will help mitigate the capacity shortfall PJM is now experiencing, which is projected to continue into the future.”

Extended delay of the project will cause “irreparable harm” to the 67 million Americans served by PJM given its critical need for new generation to achieve commercial operation in the next few years, the RTO added.

Later during the hearing, Fitzsimmons defended the 202(c) orders in more depth, saying they are needed in response to shrinking reserve margins in all the major ISO/RTOs at the same time they need to grow supplies to meet new demand.

“In order to meet the reserve margin requirements that are necessary for future load growth and to win the AI race, we need capacity that gets accredited by the grid operators, and that is dispatchable capacity,” Fitzsimmons said. “So, you can build as much non-dispatchable capacity as you want. It does not obviate the need for more always-on electricity.”

Cyber and Physical Security Legislation

While the minority took the opportunity to conduct an unofficial oversight hearing, the committee also took testimony on several bills, including the SECURE Grid Act from Subcommittee Chair Bob Latta (R-Ohio) and Rep. Doris Matsui (D-Calif.). It would give states funding to study the resilience and security of their electric grids.

Another piece of legislation would extend the operation of the Energy Threat Analysis Center (ETAC), which was set up as a pilot to improve information sharing on security threats to the industry.

“The ETAC Reauthorization Act of 2025 promotes improving operational collaboration between the government and industry securing critical energy infrastructure from cyber threats and protecting information sharing, thereby strengthening the nation’s energy security,” Fitzsimmons said.

In his written testimony, Edison Electric Institute Vice President Scott Aaronson said that one way Congress could help the industry is by limiting its liability when it follows government directions during a security event.

“The government may order utilities to ensure certain areas have power during an emergency for national security purposes,” his testimony said. “Or, conversely, an agency may ask that a utility allow a threat to persist to support an investigation. While utilities stand ready to collaborate with the federal government to address threats and emergency situations, existing law does not provide sufficient legal liability protection for utilities that accommodate such an order.”

Both the American Public Power Association and the National Rural Electric Cooperative Association asked the committee to extend DOE’s Rural and Municipal Utility Cybersecurity Program.

“We operate in resource-constrained rural areas, defending lines and substations that are often remote and difficult to access,” Dairyland Power Cooperative Vice President Nathaniel Melby told the subcommittee. “We operate on thin margins without profit incentives or shareholders. We must balance costly security needs against the financial reality of our members. Every dollar we invest in cyber defense comes directly from our members’ pockets.”

DOE’s program for municipal utilities and co-ops helps the close the “rural resource gap” while building partnerships, collaboration mechanisms and information sharing capacities, he added in testimony made for NRECA.

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D.C. Circuit Vacates FERC Order Requiring PJM to Rerun 2024/25 Capacity Auction

The D.C. Circuit Court of Appeals has vacated FERC’s decision to order PJM to rerun its 2024/25 capacity auction without a tweak to the parameters for the DPL South zone. The court ruled that the commission was not justified in dismissing a complaint from consumer advocates arguing that the PJM auction results were not just and reasonable due to the unresolved flaw in the parameters. (See 3rd Circuit Rejects PJM’s Post-auction Change as Retroactive Ratemaking.)

The court ruled that the commission incorrectly determined that revising the 2024/25 Base Residual Auction (BRA) results would violate the filed-rate doctrine. FERC took that stance in the wake of the 3rd U.S. Circuit Court of Appeals in March 2024 finding it had run afoul of the doctrine by permitting a PJM request to revise the locational deliverability area (LDA) for DPL South in December 2022 after the bidding window had closed but before the results were posted. The RTO said it had identified a “mismatch” in the capacity expected to be available in the region versus what was offered. The DPL South zone encompasses the Delmarva Peninsula. (See PJM Decides Against Posting Indicative Capacity Auction Results.)

PJM intervened to defend FERC’s order, along with the Electric Power Supply Association, PJM Public Power Providers Group, Midwest Generation, Constellation Energy and NRG Business Marketing.

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The court’s Jan. 13 ruling states that the 3rd Circuit had applied only to the request to revise the reliability requirement and did not necessarily bind the commission from revising the BRA results if they are determined to be unjust and unreasonable.

“There may have been a sound basis for FERC to deny relief. But the only reason it articulated — that the 3rd Circuit resolved the matter — was anything but sound. The 3rd Circuit held that the filed-rate doctrine foreclosed FERC’s efforts to modify PJM’s rate-setting process under Section 205 of the (Federal Powers Act). But it never addressed whether the auction result is subject to revision under Section 206. FERC’s conclusion to the contrary was erroneous,” the court wrote.

The court was not swayed by the commission’s arguments that the 3rd Circuit anticipated the economic effects of its ruling and therefore it could not act in a way that would render the court’s expectations meaningless. The Jan. 13 ruling states that courts are not economic regulators and the 3rd Circuit’s ruling could be interpreted as acknowledging that FERC had multiple paths it could proceed with, not solely requiring it to direct PJM to rerun the auction.

The vacatur did not direct the commission to take any particular action, and it cautions that a reversal of the auction results is not guaranteed.

“We do not mean to suggest that the DPL customers are necessarily entitled to a refund under Section 206(b). We hold only that labeling the relief they seek as “retroactive” should not foreclose the possibility that it is available under Section 206,” the court wrote.

Maryland People’s Counsel David Lapp said the ruling is a step toward reversing a PJM mistake that cost ratepayers $180 million.

“Delmarva Peninsula customers paid the consequences of a mistake PJM made — a mistake that gave generators a windfall, and one that federal regulators failed to fix. The court’s decision significantly advances the possibility that customers will be made whole through refunds,” Lapp said in a statement.

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NERC Report Discusses Crypto Ride-through in Texas

Continued growth of blockchain and crypto mining operations in the Texas Interconnection could “threaten the reliability of the interconnection” through indirect load loss effects, according to a report recently published by NERC.

The Considering Voltage-Sensitive Crypto Load Reductions report, published Jan. 7, is NERC’s first incident review of 2026. The ERO produced the document to highlight the unique characteristics of crypto mining facilities and how they differ from other emerging large electronic loads such as cloud computing and artificial intelligence data centers.

“As these facilities rely heavily on constant-power electronic supplies, cooling equipment and single-phase devices that respond to normally cleared transmission faults, they experience load drops within milliseconds of a voltage sag,” the report’s authors wrote. “Restoration times vary widely depending on equipment configuration and the level of manual intervention required. Understanding these behaviors is essential for assessing grid impacts, interpreting event data, and developing appropriate ride-through expectations and mitigation strategies.”

Between January 2023 and September 2025, ERCOT has experienced 26 large electronic load ride-through events involving one or more crypto facilities with indirect load loss of at least 100 MW, according to the report. The incidents “primarily occurred in central Texas, far west Texas, the Panhandle and the North Zone,” with impacts ranging from 17 to 95% of pre-disturbance consumption.

NERC staff emphasized that the load loss attributed to crypto facilities is indirect, meaning that it arises “from system or grid effects” rather than line outages. The events “verified that crypto facilities exhibit sensitive ride-through behavior, reducing consumption rapidly in response to voltage dips, particularly when single-phase voltage falls below approximately 0.7 p.u. [per unit].”

This behavior deviates from that suggested by the Information Technology Industry Council, which created the ITIC curve to illustrate the “AC voltage limits that most information technology equipment (ITE) can endure without experiencing unexpected shutdowns or malfunctions,” the authors wrote.

According to the ITIC curve, “voltage sags down to 70% of the root mean square nominal voltage are acceptable if the duration does not exceed 0.5 seconds.” Voltage sags below 70% of the RMS nominal voltage can lead to dropout events, which cause equipment to stop functioning. A dropout that lasts longer than one AC cycle enters a “no damage region” where the ITE shuts down.

But “multiple instances of partial loss of load have been observed” in voltage depressions “close to the boundaries of the … ITIC curve at the [point of interconnection]/utility connection,” NERC staff wrote.

The report cited a lightning strike on 138-kV lines that caused a fault affecting two crypto facilities. The first experienced a multiphase voltage depression that “reduced both A-phase and B-phase voltages below 0.7 p.u. for more than 20 milliseconds [with] the reduction in active power for A-phase and B-phase [accounting] for 80% of the total reduction.” Current levels rose to about 160% of pre-fault levels during the disturbance, with the facility requiring almost two hours to return to normal consumption.

At the second facility, only the A-phase was affected, dipping below 0.7 p.u. for more than 20 milliseconds. The reduction in active power for the A-phase accounted for 70% of total reduction, with current increasing to about 150% of pre-fault magnitude, and “load was fully restored in approximately five minutes.”

The report acknowledged that crypto mining facilities can vary widely in their design and equipment, which can affect their behavior during grid events. These differences include the type of overcurrent protection used, transformer configuration between the facility and the utility connection, and cooling systems whose failure can lead to a complete facility shutdown during normally cleared transmission system faults.

NERC’s report suggested “additional analysis, equipment adjustments and operational improvements [in these areas] may be needed” to improve crypto facilities’ ride-through performance and reliability, while observing that some efforts along these lines are already underway. For example, the authors wrote that ERCOT is considering introducing ride-through requirements for cooling systems.

Additional suggested areas of study include variability in restoration times and interconnection requirements for crypto facilities, especially those that are also transitioning toward AI or cloud workloads. The report suggested that such changes could introduce additional variables to load behavior and ride-through characteristics.

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N.Y. Governor Envisions 8-GW Nuclear Fleet

New York’s governor is calling for a “Nuclear Reliability Backbone” of more than 8 GW of the emissions-free baseload power as part of an all-of-the-above energy solution.

The plan was among the more than 200 initiatives Kathy Hochul (D) floated Jan. 13 as part of her State of the State Address, the annual forum in which governors present their agenda and priorities for the coming year and its legislative session.

Hochul in 2025 directed the New York Power Authority (NYPA) to develop at least 1 GW of advanced nuclear capacity. Now she is directing the state Department of Public Service (DPS) to facilitate a cost-effective pathway to an additional 4 GW of new nuclear capacity.

“Go big or go home,” Hochul said.

New York’s existing commercial reactor fleet totals only 3.3 GW.

A confluence of factors faces New York and its policymakers: The state’s power portfolio is aging and shrinking as the demands placed on it are expected to grow. NYISO has identified reliability violations developing as soon as mid-2026. But the long-running effort to develop renewable generation is lagging behind schedule and is only going to get more difficult under President Donald Trump.

By turning to nuclear energy, Hochul is betting that the many public- and private-sector efforts underway to reduce the staggering cost and tortoise pace of recent U.S. nuclear development will be successful. Limiting rate increases for residents of a state with some of the highest utility costs in the nation has been a theme for the governor, and she reiterated it in her address.

New York ratepayers already contribute around a half-billion dollars a year to subsidize Constellation Energy’s four reactors.

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Along with technical, regulatory, supply chain and fuel supply hurdles, any U.S. nuclear renaissance will need widespread host-community support.

NYPA has begun laying the groundwork for this.

It said Jan. 7 that eight upstate communities expressed interest in becoming host communities.

But many people and organizations remain opposed to new nuclear development because of the costs and hazards associated with it.

“The proposal for 5 GW of new nuclear capacity is a dangerous misdirection for state energy policy,” Food and Water Watch said. “Nuclear power is a foolishly expensive and antiquated approach to meeting the state’s energy demand needs.”

Public Power NY called it a disastrous plan and doubled down on its call for NYPA to set a higher goal for renewable energy development.

The Alliance for Clean Energy New York suggested the effort to expedite nuclear development be applied as well to renewables: “New Yorkers need affordable electrons now, not in the decade-plus it will take until new nuclear could be operational. Renewables paired with storage are the cheapest way to deliver more electricity for New Yorkers today.”

Advanced Energy United said: “We are optimistic about the governor’s plan to move on a suite of advanced energy solutions that are ready to go now that will keep the lights on while protecting consumers.”

Constellation’s Nine Mile Point nuclear plant in central New York is shown. Gov. Kathy Hochul is proposing a 5-GW expansion of the state’s nuclear fleet. | Constellation Energy Group

The newly formed Future Energy Alliance is squarely in favor. Constellation, which is part of the broad industry-labor-business coalition, said: “Constellation is proud to support this work and to advance the next generation of nuclear technology that can deliver long-term energy stability and broad economic benefits for communities across the state.”

Hochul offered several other ideas relevant to the energy sector in the larger book of proposals that accompanied her Jan. 13 address. Most are directly keyed to affordability and transparency for ratepayers or other consumer-focused measures.

But she also is advancing Excelsior Power, a new initiative that will direct utilities to treat grid flexibility as a key resource and expand incentives to encourage their customers to participate in demand flexibility programs. This is expected to reduce the need for costly system upgrades.

Hochul wants to reduce the infamous red tape that frustrates energy and housing developers and, by the state’s own analysis, causes projects to take up to 56% longer to get from concept to groundbreaking than in peer states. New York has made some progress on this, but delays remain. NYPA and the New York State Energy Research and Development Authority will be directed to update their regulations to speed clean energy development.

Hochul is addressing the human aspect of new nuclear technology with NextGen Nuclear New York, a workforce development effort for the people who will build and operate nuclear plants.

She also is directing the DPS to launch Energize NY Development, an initiative to streamline how large load customers connect to the grid. It will speed up interconnection, she said, and it explicitly will require that projects either cover the costs they create or supply their own energy if they create very large demand without also creating very large job creation or other public benefits.

Other proposals would boost protection of the state grid from cyber threats; adjust rules for aid to school districts to encourage on-site renewable energy development; establish a sales tax exemption for EV charging stations; and expand efforts to encourage agrivoltaics.

But energy was almost a side note in Hochul’s speech, which focused on quality of life, human rights and affordability issues and drew varying levels of applause from the heavily Democratic audience.

2026 may witness an even more intricate balancing act than is normal in Albany: Hochul, who won the deep-blue state by a surprisingly narrow margin in 2022, is facing a primary challenge from the left and a general election challenge from the right, plus skirmishes with the Trump administration along the way.

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Utility Ratemaking Has Become More Complicated

By Kenneth W. Costello

Utility ratemaking comprises three distinct parts: revenue requirements, cost allocation and rate design. Ratemaking is a regulator’s prime function, as it determines how much revenue that utilities should collect from customers, from which customers and how.

The ratemaking process is complex and interactive, striving to satisfy or appease groups with diverse goals, interests and agendas. It also entails addressing the several objectives underlying ratemaking, each of which has a distinct effect on the public interest.

Most utility regulators subscribe to what regulatory observers call the “balancing act” of regulation. In an ideal world, regulators attempt to balance the interests of the different stakeholders with the overall goal of promoting the general good. This objective complies with the premise behind the public-interest theory of regulation. While ratemaking plays an integral role in achieving the “balancing act,” this action has become increasingly difficult for regulators as they have to cope with new interests.

Examples abound in which a particular rate mechanism advances some regulatory objectives while hindering others. The reality is that all rate mechanisms have mixed effects on the public interest. The premise is that when a rate mechanism impedes some regulatory objective it diminishes the public interest, while improving the public interest when it advances an objective. This speaks to the trade-offs regulators must make when deciding on different rate mechanisms.

Ken Costello

One example is real-time pricing in which the trade-off is between economic efficiency and price stability. A second example is price caps in which the regulator must weigh the benefits of pricing flexibility and increased incentives for productive efficiency against profit variability, which could lead to “excessive” utility profits. These conflicts inevitably require regulators to make value judgments on the overall desirability of a rate mechanism for the general public.

A third example is cost trackers or riders, in which a trade-off exists between timely utility recovery of costs and robust incentives. Trackers and riders allow utilities to recover their costs more quickly and with more certainty, lowering their financial risk; but they also can create incentive problems when: (1) regulators fail to adequately scrutinize those costs, and (2) cost recovery methods differ across different utility functional areas.

A Risk of Drifting Away from Core Objectives

Today, clean energy, low-income and climate advocates add to the interests that regulators must appease. If regulators try to satisfy more interests, driven by politics or for other reasons, one must ask: Do they therefore risk drifting away from their resolve to achieve core objectives, especially advancing the well-being of utility customers? After all, the raison d’etre for public utility regulation is to protect customers from “monopoly” utilities.

What are these other responsibilities that regulators have to take on? The landscape confronting utility regulators requires them to address a wider array of social issues that historically were under the purview of the other branches of government or left to the marketplace.

Their ratemaking duties include consideration of affordability for low-income households, the accommodation and even the subsidization of new technologies that compete with utilities’ core business, decarbonization of utilities’ generation portfolio, and the subsidization of utilities’ customers to use less electricity and switch to other electricity sources (e.g., rooftop solar).

No other private business comes to mind in which society compels private firms to tackle such a wide array of social issues. It is legitimate to ask whether utility regulation has expanded its domain far beyond its original mandate and what is socially optimal.

What Happens When Ratemaking Goes Astray

Faulty ratemaking can lead to adverse outcomes, like undue price discrimination, inequity, poor incentives for innovation, economic inefficiencies like uneconomic bypass, misallocation of business risk between customers and shareholders, and financially stressed utilities.

Concerning uneconomic bypass, faulty ratemaking can lead to customers choosing providers that have lower prices but higher costs. A regulated utility with an unregulated affiliate might have an incentive to subsidize the affiliate by shifting some of the affiliate’s costs to its core customers (e.g., residential customers).

Good ratemaking always has been a big challenge for regulators. It demands both sound analytics and judgment by regulators. Regulators must weigh or prioritize those objectives underlying ratemaking and measure (if possible) the effect of a rate mechanism on each one, as well as on the overall public interest. Assigning weights requires judgment by regulators, while examining the effect demands data and other unbiased information. Although ratemaking is both an art and a science (some compare it to sausage making), it should start with a strong foundation that includes specified objectives and underlying economic principles, like cost causation.

Utility Regulators Know How to Adapt

Developments in the electric industry have required regulators to re-examine their current, longstanding ratemaking practices. Previous experiences show that utility regulators do adapt, although gradually, to a changed economic, technological and political environment by throwing their support to new rate designs and ratemaking mechanisms.

One example is the restructuring of the U.S. electric industry, starting in the 1970s, triggered by the discontent of consumer groups (especially industrial customers) from continuous rising electricity rates along with the problems encountered by utilities in getting the regulators to approve pass-throughs of costs, even those prudently incurred but second-guessed because of unexpected circumstances.

Utilities could not incorporate these costs (to a large extent beyond their control) into their rates fast enough to keep their earnings from falling to a critical level. Regulators eventually allowed fuel adjustment clauses (and, to a lesser extent, future test years) to reduce regulatory lag and avert more serious financial difficulties. Regulators also revisited existing rate structures (e.g., declining block rates) to determine whether they satisfied new objectives, like the advancement of energy efficiency and the reduction of carbon emissions.

As its central duty, utility regulation should make well-informed decisions driven toward the public interest. It should strive for balance and fairness. Good regulation weighs legitimate interests and makes decisions based on facts.  Regulation decisions should not unduly favor any one interest group over the public interest; they should coincide with the law and the evidentiary record. This idea is especially critical today where good ratemaking has become more important, but harder to achieve.

Kenneth W. Costello is a regulatory economist and independent consultant who resides in Santa Fe, N.M. 

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