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January 20, 2026

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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 more data centers representing an additional16,908 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.

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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.

“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 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 Power 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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Judge Rules Blue-state Energy Grant Terminations Unlawful

A federal judge has ruled the U.S. Department of Energy acted illegally when it terminated several energy grants because they were based in Democratic-leaning states.

The ruling stems from the controversial cancelation of $7.56 billion worth of Biden-era grants in October 2025. A month later, the city of St. Paul, Minn., and five organizations challenged the cancellation of nine grants earmarked for them.

Judge Amit Mehta in the U.S. District Court for the District of Columbia ruled Jan. 12 that the grant cancellations violated the guarantee of equal protection of laws under the Fifth Amendment of the U.S. Constitution (25-cv-03899).

All 223 projects that were to receive the 321 grants (except one in Canada) are in states Kamala Harris carried in the 2024 presidential election. Moreover, Mehta noted, the defendants admitted that a primary reason for selecting which DOE grants to cancel was whether the grantee was in a “blue state.”

Similar grants in “red states” that Donald Trump carried in the 2024 election were spared from termination, Mehta wrote, and the defendants conceded those grants were comparable to the terminated grants.

The judge specifically cites Grid Resilience and Innovation Partnership and methane emissions monitoring grants that were awarded to both red and blue states but terminated only in blue states.

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The defendants asserted partisan politics does not offend the Equal Protection Clause and compared it to the common practice of federal pork barrel spending.

But that analogy falls flat, Mehta wrote, because members of Congress securing money for their districts is wholly different from an agency taking away congressionally appropriated funds that already have been awarded. Further, pork-barrel spending can rationally be related to a legitimate government interest.

The plaintiffs, Mehta wrote, do not dispute that the defendants proffered a legitimate purpose for this: administering grant programs consistent with the agency’s priorities. The question, he said, is whether the classification the defendants drew is rationally related to the purpose.

Mehta then answered the question: “It is not. Without more [evidence], there is no reason to believe that terminating an award to a recipient located in a state whose citizens tend to vote for Democratic candidates — and, particularly, voted against President Trump — furthers the agency’s energy priorities any more than terminating a similar grant of a recipient in a state whose citizens tend to vote for Republican candidates or voted for President Trump.”

Mehta ruled the termination unlawful and vacated the October termination notices to the seven awards at issue in the litigation. He directed the plaintiffs to indicate by Jan. 16 whether they will seek injunctive relief and/or compensation for attorney’s fees.

In response, a DOE spokesperson said Jan. 13: “We disagree with the judge’s decision and stand by our review process, which evaluated these awards individually and determined they did not meet the standards necessary to justify the continued spending of taxpayer dollars. The American people deserve a government that is accountable and responsible in managing taxpayer funds.”

DOE’s Oct. 2 announcement of the grant terminations indicated many of the grants were awarded during the lame-duck phase of Joe Biden’s presidency but did not indicate where the recipient projects were based: California, Colorado, Connecticut, Delaware, Hawaii, Illinois, Maryland, Massachusetts, Minnesota, New Hampshire, New Jersey, New Mexico, New York, Oregon, Vermont and Washington. (See DOE Terminates $7.56B in Energy Grants for Projects in Blue States.)

All are blue states, but in some cases, the impact of the cancellations would stretch into red states.

St. Paul was joined in the Nov. 10 complaint by Elevate Energy, the Environmental Defense Fund (EDF), the Interstate Renewable Energy Council, Plug In America and Southeast Community Organization as plaintiffs.

EDF was party to four awards totaling $535.5 million. The other five were designated to receive small grants ranging from $1.2 million to $6.9 million. Mehta’s ruling pertains to seven grants totaling $27.6 million.

Named as defendants were DOE, Secretary of Energy Chris Wright, the Office of Management and Budget and its director, Russell Vought.

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PJM OC Briefs: Jan. 8, 2026

Stakeholders Delay Vote on Manual 1 Revisions

PJM’s Operating Committee deferred a vote to endorse revisions to Manual 1: Control Center and Data Exchange Requirements to give more time to review language removing a requirement that actual meter test results should be provided to the RTO. (See “PJM Seeks Quick Fix on Data Communications,” PJM Operating Committee Briefs: Dec. 4, 2025.)

PJM’s Ryan Nice said staff’s thinking in recommending the removal is that meter calibration and test results tend to be conducted by third-party specialists and are better addressed through resources’ interconnection service agreements. Nice said the tests represent a small part of how PJM models and validates resources’ output.

Stakeholders raised concerns that without PJM directly receiving the results of those tests, it would assume the data is accurate unless it is informed of a problem.

The proposed language also reflects NERC reliability standard CIP-012-2 (Cybersecurity – communications between control centers) requiring plans to “mitigate the risks posed by unauthorized disclosure, unauthorized modification and loss of availability of real-time assessment and real-time monitoring data in transit between applicable control centers.”

The revisions would detail the RTO’s PJMnet system for internal communications, require that members submitting distributed network protocol links provide their own data maps and definitions, and clarify that PJM will not consume or process data not needed for its own purposes, which Nice said is intended to underscore that PJM is not a generic data repeater for its members.

Manual Language to Implement AARs Endorsed

PJM presented a first read on revisions to Manual 3: Transmission Operations and Manual 3A: Energy Management System Model Updates Quality Assurance to conform with FERC Order 881, which requires the implementation of ambient-adjusted line ratings (AARs).

The Manual 3 changes include adding short-term emergency ratings to the Thermal Operating Guidelines, maintenance responsibilities for rating set lookup tables, and an option for transmission owners to resort to AARs or seasonal ratings during a dynamic line rating outage. The manual would set PJM’s transmission facilities rating database as the data source for lines with short-term emergency ratings.

The Manual 3A revisions would add two sets of 5-degree bands to the Transmission Facility Ratings Database for day and night, ranging between -55 degrees and 130 degrees F. The database would be available for all eDART users. Conditional rating tables would be added to cover loss of cooling, directional ratings and proxy stability limits.

Annual Recertification

PJM is planning to include member officers in its notifications around the commencement of the annual recertification process owing to an increase in the number of final warning letters and breach notices sent in 2025.

In response to feedback from stakeholders, the RTO did not include officers in the 2025 recertification process, but found many companies were less responsive. PJM determined that the omission of officers contributed to RTO staff having to make additional efforts to reach out to members.

Members are required to update their sector selection, affiliate disclosure, company information and contact managers by April 17. Market participants are also required to disclose their principals.

By the end of April, market participants should submit an officer certification form, risk management policies and audited financials for 2025.

December Operating Metrics

PJM’s Marcus Smith said load forecast performance was strong across the December 2025 holidays, a point of focus in recent years as the intersection between gas procurement cycles and difficult-to-predict holiday loads has led to strained system conditions.

The average hourly forecast error for the month was 1.78% and the average peak forecast error was 1.57%. Peak loads on several days exceeded the RTO’s 3% error benchmark: Dec. 17 was over-forecast by 3.53% due to high temperatures; Dec. 8 was 3.1% under-forecast due to high cloud coverage; cool temperatures on Dec. 14 led to a 3.31% under-forecast; and the Dec. 20 peak was 3.25% higher than expected due to cold and windy weather.

December saw three spin events, three shared system events, one high system voltage action, three cold weather alerts and 26 post-contingency local load relief warnings. Smith said the month was 5 degrees colder than the average of the past three Decembers and recorded the highest December peak load on Dec. 22.

A spin event Dec. 5 was initiated at 7:30 p.m. and lasted 4 minutes and 25 seconds. There were 2,350 MW of generation assigned and 373 MW of demand response, of which 49% and 69% responded, respectively.

Another event was declared the following day at 5:05 a.m. and lasted 7 minutes and 44 seconds. There were 2,350 MW of generation and 218 MW of DR assigned, with 79% and 91% responding.

The third event fell Dec. 28 at 5:07 p.m. and lasted 9 minutes and 46 seconds. There were 2,012 MW of generation assigned and 642 MW of DR, of which 76% and 89% responded.

The RTO faced below-zero temperatures and high snowfall during a winter storm that passed through the region Dec. 12-16. The peak load during the storm was 136,467 MW at 8:20 a.m. Dec. 15.

PJM’s Paul Dajewski said temperatures were lower than forecast during much of the storm and some generators were dispatched but ran into emissions limits preventing them from operating. Staff considered requesting waivers from those limits under the Federal Power Act Section 202(c).

The storm was the first winter event where gas generators were able to signal fuel supply concerns through an indicator on Markets Gateway, which several resources used to update PJM on their status. Four cause codes were added to eDART to increase the granularity of tracking gas-related outages.

Synchronized Reserve Inquiry

The Independent Market Monitor presented the latest results of its ongoing inquiry into the causes of synchronized reserve underperformance, this time looking at a 2,720-MW deployment Nov. 11. While PJM reported an 83% response rate, the Monitor argued PJM should consider reserves that overperform their assignment, which would increase the response rate to 104%. (See “Monitor Presents Synchronized Reserve Performance Inquiry,” PJM Operating Committee Briefs: Dec. 4, 2025.)

Communications have become a smaller driver as PJM has implemented new protocols for sending dispatch instructions to resources; however, parameters and personnel issues have become more pronounced. The single-largest cause of underperformance was parameter issues, followed by hardware issues and software.

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BPA Tx Planning Overhaul Prompts Concern for Northwest Clean Energy Compliance

Some of the Bonneville Power Administration’s proposals aimed at improving transmission planning processes risk pushing study timelines to the point where the agency’s customers could run afoul of Washington and Oregon’s clean energy targets, stakeholders say.

BPA paused certain planning processes and launched the Grid Access Transformation (GAT) project in 2025 to consider changes following a surge of transmission service requests (TSRs). The most recent transmission study includes 61 GW of new generation, compared with 5.9 GW in 2021, according to the agency. (See BPA Halts Some Tx Planning Processes Amid Surge of Service Requests.)

BPA’s proposal to tackle the queue involves a two-part approach: a transitional phase to get off the pause and a longer-term “future state” that will include more substantial reforms to BPA’s existing transmission processes, such as shifting toward proactive transmission planning (an approach that seeks to forecast transmission needs and prepare the system ahead of time rather than just reacting to customer requests).

During a Jan. 6 meeting, BPA staff and industry representatives discussed options the agency could pursue during its transitional phase to identify customers eligible for transmission service awards to get off pause while the agency continues to plan for the “future state.”

“Depending on the outcome of queue reform, the queue size will be a determining factor in which type(s) of transition analysis can be completed,” according to BPA’s presentation slides. “Additionally, the same team that does this transition analysis is also working to stand up proactive planning and achieve the future state. Essentially, more time dedicated to transition analysis will delay the future state.”

Some of the transition study options BPA has presented could present challenges for Oregon and Washington-based customers, Henry Tilghman, a consultant whose clients include Renewable Northwest and the Northwest & Intermountain Power Producers Coalition, told RTO Insider. (Tilghman spoke on his own behalf, not that of his clients.)

Washington and Oregon passed aggressive clean energy laws in 2019 and 2021, respectively, requiring electric utilities to meet strict greenhouse gas standards by 2030. (See Washington Agencies Adopt New Rules to Implement CETA and Clean Energy, Equity Goals to Reshape Oregon IRP Process.)

Many of the options presented by BPA would push study timelines for transmission service requests beyond the 2030 deadline, according to Tilghman. He noted that some options would result in transmission service awards before 2030, though those options would require smaller study volumes.

Tilghman’s clients have yet to adopt a preferred option, but he said the timeline to complete the transition study could be one factor they would consider in making their choice.

“There are a lot of ways to look at … what the right solution is here,” Tilghman told BPA at the Jan. 6 meeting. “One of them would be to focus on what gets the most new transmission service, even if that’s interim or conditional firm service, into the hands of customers by those 2030 deadlines. … And certainly one way we could go would be to design a program that would facilitate … filling up the transmission grid that will exist in 2030 with transmission service in customers’ hands.”

Seattle City Light’s Michael Watkins echoed Tilghman’s comments, saying the discussions are “about meeting customer needs for transmission for 2030, 2035 and 2040.” He added that “strict regulatory requirements” are forcing the industry “down certain roads.”

BPA must “answer those needs,” Watkins said. “Because the needs are large enough that if Bonneville does not answer those needs, someone else will. And … none of us may like how that happens — both customers and Bonneville. So, we need to come together and meet those needs somehow.”

Proactive planning is the fastest way to create available transmission to serve needs by 2030 and 2035, Watkins added.

“If we really hit the gas, we can do that,” he said. “But if we spend the next 24 to 36 months still trying to slice the existing pie, we’re not going to get there.”

‘Sweet Spot’

The discussion around Washington and Oregon’s clean energy goals was prompted by comments from Randy Hardy, the agency’s administrator from 1991 to 1997.

During the Jan. 6 meeting, Hardy reiterated claims he made to RTO Insider in June 2025, arguing that the states’ respective laws set off a “gold rush’ among developers, eventually leading to today’s situation. (See Industry Sees Challenges as BPA Considers ‘Radical’ Updates to Tx Planning.)

“That’s the nature of the problem,” Hardy said Jan. 6. “It’s not a Bonneville problem. It’s not a customer problem. Its origins are in the state legislative mandates, which have created essentially an unmeetable situation relative to the 2030 deadline and the 65 GW in the queue, which now Bonneville is left holding the bag and having to solve. And that’s what we’re all trying to do.”

In an email, BPA spokesperson Kevin Wingert said when the agency decided to transition to a new process for its large generator interconnection queue to be able to study the “the unprecedented number of gigawatts being requested (there are 61 GW of generation in the current study), we identified 16 GW of late-stage generation projects that were ready to move forward beyond the queue process into execution.”

“We’ve begun the process of integrating that generation at a rate of roughly 1 to 1.5 GW per year,” Wingert wrote. “We anticipate 7.5 GW being integrated by 2030, with the full 16 GW of late-stage projects being integrated by 2035. That 1 to 1.5 GW integration rate is record setting for BPA and represents a basic sweet spot in terms of capacity from workforce, contracting, manufacturing and supply chain elements. We anticipate maintaining that pace for the foreseeable future.”

Wingert added that BPA is “working on reducing our timeline for project delivery down to a five- to six-year window. This work is incremental in nature, but our current goal for full implementation on this effort is 2030 and includes efforts to increase study efficiencies like potential automation or contracting aspects of the work.”