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February 13, 2026

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NARUC Focuses on Large Loads’ Impact on Reliability and Affordability

WASHINGTON, D.C. – NARUC’s Winter Policy Summit focused on the main issue facing the power industry — how to reliably and affordably interconnect new large load customers.

Its annual meeting in November was held just after the U.S. Department of Energy filed an Advance Notice of Proposed Rulemaking (ANOPR) asking FERC to claim jurisdiction over large loads connecting to the transmission system. That led the state regulator group to issue a resolution seeking to preserve state jurisdiction over customer interconnection. (See Regulators Urge FERC to Honor State Authority over Large Load Interconnections.)

FERC is working its way through voluminous comments with DOE asking for action on the ANOPR by April 30. FERC Chair Laura Swett told state regulators its final action would be guided by the law.

“We are very committed to doing everything that we can within our jurisdiction under the law, but I take that very seriously,” Swett said Feb. 10. “There are some pretty clear lines drawn between federal and state jurisdiction, and some a little bit blurry because these are new issues. But I want you all to know that we are only going to act within the law as it has been designated by the courts.”

States have the important role of siting the generation that is needed to meet rising demand, which means the different levels have to work together to address the challenge, she said.

Swett has been on the job for four months, but plenty has happened in that time, including a major winter storm that stressed, but did not break, the bulk power system.

“My first takeaway is we cannot retire generation without replacing it,” Swett said. “So, because the grid is so tight and supply must meet demand head-to-head, we have to ensure that if we’re going to take large generation offline, then there has to be something to meet that — even maintain the status quo, which we’re already stressing.”

FERC recently approved new rules from PJM to more easily transfer capacity interconnection rights from retiring generators, which Swett said could be a model for the rest of the country. (See FERC Approves PJM CIR Transfer Proposal.)

While the grid is stressed, its operators performed well during the recent storm, avoiding any resource adequacy related outages despite the tight conditions across much of the country, Swett said. The generators that were keeping the lights on at the storm’s peak were 75% dispatchable.

“From where I sit, it’s clear to me that we need more dispatchable generation on a system,” Swett said. “And so not only does that mean not retiring it, but it also probably means building more of it.”

FERC Chair Laura Swett on stage alongside NARUC President Ann Rendahl of the Washington Utilities and Transportation Commission | © RTO Insider 

States have the bulk of the authority to get new generation online, with FERC just able to change wholesale market rules that can ensure new projects get fair returns. But the feds have a bigger role when it comes to the main fuel that new dispatchable plants would burn — natural gas.

“So, FERC can help, I think, by permitting more infrastructure as quickly and efficiently and legally durably as possible,” Swett said. “Because if everyone’s saying they need to build gas plants in order to keep our lights on, and our pipelines in many places of the country are constrained or don’t even exist at all, then it seems to me that FERC has to be looking at ways to ensure that we can get the gas to the generation that we need.”

Speaking earlier at the conference, FERC Commissioner David LaCerte said expanding natural gas infrastructure is one of his priorities.

“The economists at FERC could not be more clear: If we add more natural gas capacity to pipelines, that should drive prices down for the ratepayer,” LaCerte said Feb. 9.

LaCerte said that for every question that comes before him at FERC, he considers its impact on reliability and affordability. But with such major issues in front of the commission, the priorities are more difficult to balance.

In addition to the uncertainty around the ANOPR, major changes are being debated in the stakeholder process in PJM and elsewhere. LaCerte told the state regulators to come up with their own proposals.

“That’s probably the ultimate path to success — is telling the folks at FERC, and folks on the Hill, folks on your RTOs, what works best in your own backyards,” LaCerte said. “It’s very hard to create a rule from Washington, D.C., that has durability and longevity across the entire country. It’s almost impossible.”

While connecting large loads presents daunting challenges, the issue comes with opportunities, said Nick Elliot, policy adviser to the White House Energy Dominance Council.

“One of the things that’s inescapable in the utility side is just how much of the total cost structure is fixed and how little is variable,” Elliot said. “And the key message I’ve got there is like scale — selling more megawatts of a fixed cost system leading to better utilization and deflationary overall to prices.”

As long as the costs and risks are properly allocated, he said, demand from data centers and other large loads can help lower rates for other customers.

“Whether it’s a regulated area or a deregulated area, you need to be trying to develop policies where new large loads are accompanied by new large generation, and you grow the system in a balanced way on the capacity side,” Elliot said. “Large loads need to be paying for the transmission associated with the build. And overall, that is deflationary in terms of a better, more effective utilization of the overall system.”

Indiana Michigan Power has a large load tariff, which are becoming more common across the country. Meanwhile, the Northern Indiana Public Service Co. (NIPSCO) has set up a competitive generation subsidiary, or a “GenCo,” to serve large loads, said Indiana Utility Regulatory Commissioner David Veleta.

“The goal of the GenCo structure is ensure that a new customer bears 100% of the cost and risks of new generation that’s built or purchased by the GenCo, and I think that’s like an optimization of what the large load tariffs do,” Veleta said. “The large load tariffs do a good job, but I think that the GenCo model takes it to the next level, and I think that’s just a better step.”

Arizona Public Service has come up with a formula rate that can be updated every year, so consumers do not get bill shocks after several years of increases hitting at once. In its most recent rate case, it asked regulators to approve a 14% increase for most customers and 45% for data centers, said its Senior Vice President Jose Esparza.

“We don’t have a GenCo model, but what we were offering is what we’re calling a subscription rate,” Esparza said. “Whereas you’ll take a portfolio of resources, the customer will have to put up a certain amount of collateral, agree to pay a 20-year agreement or 15-year agreement, to buy down and depreciate those costs as much as possible.”

Those special contracts are reviewed by the Arizona Corporation Commission, which has pushed APS to ensure that “growth is going to pay for growth” with minimum-take requirements and other terms, he added.

The growth of data centers and other large loads comes with a couple types of risk, said Google’s Head of Energy Market Innovation Briana Kobor.

“We have stranded cost risk — the flip side of that being risk of underbuild, right?” Kobor said. “We need to get the right signal in front of our utilities to empower them to do what they do best, which is long-term, least-cost planning for an efficient system. And then we have cost allocation risk. And I think it’s really important for us to separate those concepts as we think about building the new models that we need to enable large loads to come online.”

While new models like what NIPSCO and APS have done are helpful, a much more common trend among state regulators has been what Google calls the “capacity commitment framework.” It has several pillars: broad applicability based on customer size alone, long-term contracts of 10 to 15 years, significant minimum demand charges, and fair and transparent fees for exits so other ratepayers are protected and capacity can be freed up for a more viable large customer.

“It enables the utility to have clarity as to what the build signal is. If they have long-term contracts with minimum revenue guarantees, they are empowered to go and do the next step, which is figure out what we need to build,” Kobor said. “And then once we’ve figured out what we need to build, only then do we know how much it costs and how we should be allocating those revenues across all customer classes.”

Google is committed to paying its fair share of the costs required to serve its growing fleet of data centers, she added. The tech giant is cautious about getting “too creative” and moving away from the basic shared system model that has served the grid well for a century.

“When we start to bifurcate planning into ‘these are the plants that are serving large loads; these are the plants that are serving everybody else’ — I mean, that’s not how the electricity system works. That’s not how electrons flow,” Kobor said. “And, so, I spent my entire career in regulation and rate design, and I know a lot of people are going to be very well employed for a very long period of time figuring out what the right cost allocation methods are.”

The focus on load growth comes as residential customers especially have seen their bills climb faster than inflation in recent years. One narrative is that data centers are the main culprit for higher prices. But their impact on pricing depends on the region.

“Are they putting measures in place to accommodate that load growth, or are they chasing it?” Electricity Customer Alliance Executive Director Jeff Dennis said. “PJM is in a unique set of circumstances that we can talk about, certainly, where they’re in a position where they’re kind of chasing it.”

But if the supply can catch up to demand, then it can lead to lower prices, especially on a system that needs spending to modernize old transmission and distribution infrastructure.

“They, in some ways, are coming at the right time as we’re in this period of increased distribution spending, increased needs to bolster the transmission grid,” Dennis said.

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Colo. Bill Would Require Renewable Energy for New Data Centers

Colorado lawmakers have introduced a bill that would put guardrails around new data center development, including renewable energy requirements and a ban on shifting the cost of electricity and grid investments to other utility customers.

Senate Bill 26-102 is sponsored by Sen. Cathy Kipp and Rep. Kyle Brown, both Democrats. It was introduced Feb. 11 and referred to the Senate Transportation and Energy Committee.

The bill would apply to new data centers with a peak load of more than 30 MW, or a group of new data centers with a combined peak load of more than 60 MW. Additions to existing data centers also would be covered.

Starting in 2031, data center operators would be required to generate or buy enough renewable energy to meet 100% of their annual electricity consumption. Also, an operator would have an hourly matching requirement, in which energy use is matched with purchased or generated renewable resources hourly.

The Colorado Public Utilities Commission (PUC) would determine whether the hourly matching requirement should be 100% or another percentage that is technically and economically feasible. The percentage would be updated at least every three years.

Before connecting a data center customer or supplying electricity, a utility would be required to get an upfront payment from the operator or sign a long-term contract in which the operator would cover costs of building or procuring generation, transmission and distribution infrastructure to power the data center.

Utilities would be banned from offering economic development rates to large load data centers. They’d be required to offer demand response programs or flexible connection tariffs.

The bill is backed by environmental groups including Western Resource Advocates and the Natural Resources Defense Council (NRDC).

Proponents say the bill would make Colorado a leader in adopting consumer and environmental protections for data center development.

“A strong data center policy with clear consumer and environmental guardrails is essential for Colorado to ensure rapid load growth doesn’t lock in higher emissions for decades or leave ratepayers bearing the costs,” Alana Miller, NRDC’s Colorado policy director for climate and energy, said in a statement.

The groups say data center development is booming in Colorado even without subsidies for data center developers.

Tax Incentive Bill

SB 26-102 follows the introduction of a bill in January that would create an incentive program for data center development.

Under House Bill 26-1030, the incentive program would be run by a newly formed Colorado Data Center Development Authority within the Colorado Office of Economic Development and International Trade.

Data center operators that obtain a certification for their project would be eligible for a 20-year exemption from the state’s sales tax on the purchase and use of qualified data center infrastructure and systems.

Requirements for certification include investing at least $250 million in qualified purchases within five years and creating jobs that pay at least 110% of the county average.

Certified operators must work to ensure the data center will not cause unreasonable cost impacts to other ratepayers in the area and implement water stewardship measures. Backup generators must meet EPA standards or use a low-emission power source.

The bill would allow regulated utilities to submit a targeted resource acquisition proposal to the PUC for meeting emerging large-load customer needs.

At least 37 states offer some type of tax incentives for data centers, a fiscal analysis noted.

The bill is sponsored by three Democrats: Sen. Kyle Mullica, Rep. Monica Duran and Rep. Alex Valdez, whose occupation is listed as renewable energy entrepreneur. The bill has been referred to the House Energy and Environment Committee.

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TVA Cancels Decisions to Close 2 Coal Plants, Cites Growing Demand, Trump Tone

The Tennessee Valley Authority has revoked its previous decision to wind down operations at two of its coal plants, citing upward demand and the Trump administration’s coal-friendly posture.

The TVA Board of Directors voted to rescind retirement dates of both units at the 2.5-GW Cumberland Fossil Plant and all nine units at the 1.3-GW Kingston Fossil Plant at a quarterly board meeting Feb. 11 in Hopkinsville, Ky. The plants, all older than 50 years, are to operate indefinitely.

The new, Trump-appointed board members, Art Graham, Mitch Graves, Jeff Hagood and Randy Jones, joined the unanimous vote.

The board’s resolution directs TVA to fund the plants’ continued operations, apply for all necessary permits and secure fuel contracts for the plants for the foreseeable future.

TVA leadership recommended the extensions to its board prior to the vote.

Executive Vice President and CFO Tom Rice began by acknowledging President Donald Trump’s Energy Dominance Council; he said without it, TVA “would not be in the position we are today to recommend continuing to operate over 3,000 MW of beautiful, clean coal that will directly support energy resiliency, reliability and low-cost power for the 10 million people we serve.”

TVA in early 2023 decided to retire one Cumberland unit by the end of 2026 and the other by the end of 2028. A little more than a year later, it decided all nine Kingston units were to power down by the end of 2027.

TVA’s aging coal fleet evaluation, conducted in May 2021, concluded that “although no coal-fired units has reached mechanical end of life, a phased plan to retire TVA’s coal fleet by 2035 is aligned with least-cost planning and reduces economic, reliability and environmental risks.”

TVA says in the years since those conclusions, its region is experiencing a dramatic rise in electricity demand that wasn’t expected when it made the call to set retirement dates.

Rice said climbing demand, the Department of Energy’s issuance of an energy emergency and a “change in the regulatory outlook, particularly for coal,” creates the opportunity and the need to revisit the retirement authorizations.

Now, Rice said, keeping the plants online fits with TVA’s least-cost planning mandate and commitment to reliability.

TVA is building a $2.1 billion, 1.4-GW natural gas combined-cycle facility at the Cumberland Fossil Plant site that could be completed as soon as fall 2026. It originally was supposed to replace the coal plant. Until now, TVA had been using Cumberland’s retirement as justification for the new generation.

TVA previously said the coal plants are nearing the “end of their life cycle.” In its 2024 final environmental impact statement on Kingston, TVA wrote that the plant is forced to cycle frequently, which is not how it’s intended to run. It said the on-again-off-again output is “outside the intended design of the plant resulting in increased wear and tear, which presents reliability challenges that are difficult to anticipate and expensive to mitigate.”

In its final environmental impact statement regarding the Cumberland retirement, TVA wrote, “The continued long-term operation of some of TVA coal plants, including the Cumberland Fossil Plant, is contributing to environmental, economic and reliability risks.”

TVA Director Wade White said he applauded TVA leadership for the extension recommendation and reminisced on his western Kentucky hometown’s roots in coal mining.

Wade White | TVA

White said the board and TVA had been working out the coal plants’ fate for months.

“Now that we have a quorum, the board can act,” White said, referring to the installment of the four Trump appointees. For half of 2025 and the beginning of 2026, the TVA Board had just three members after Trump terminated a trio of board members appointed by former President Joe Biden. (See Nonprofits Warn of Potential TVA Privatization Ahead of Board Hearings.)

“Over the past several years, the TVA board has faced pressure to make decisions based on stringent environmental regulations that were targeted to reduce the economic viability of important generation resources like coal,” White said. “Coal, like other energy resources, should be a part of a comprehensive strategy for delivering reliable, resilient and affordable electricity to TVA customers.”

White said the coal continuance tallies with DOE’s recent emergency orders to keep retirement-bound coal plants running in Michigan, Pennsylvania, Washington, Colorado and Indiana.

No Public Input; a ‘Staggering Reversal’

TVA did not take public comments prior to holding the vote.

Environmental nonprofit Appalachian Voices called the decision a “staggering reversal.”

It said the public was left in the dark until the moment the decision was finalized, with the only hint it would extend the plants’ operations found in a pair of supplemental environmental impact statements that were quietly published to the TVA website.

Appalachian Voices said TVA bypassed public input through changes in January to its review process under the National Environmental Policy Act. Previously, major TVA changes in direction like this would have required a public weigh-in.

Environmental groups accused TVA of trying to buoy the coal industry and pander to data centers’ large loads. The Southern Environmental Law Center, Appalachian Voices, Sierra Club and the Center for Biological Diversity released a joint press release condemning TVA’s reversal.

Trey Bussey, a staff attorney at the Southern Environmental Law Center, said TVA’s broken promise is a “bait and switch” that will increase pollution, contribute to climate change, chip away at reliability and raise power bills.

“This is a blatant attempt from TVA to take the public out of ‘public power,’” Bussey said.

The Cumberland and Kingston fossil plants are among Tennessee’s three biggest sources of carbon dioxide pollution.

Cumberland coal plant (left) and Kingston coal plant | TVA

“Regular working people shouldn’t have to pay to keep these expensive, polluting power plants online just because some politicians want to prop up the coal industry, or for TVA to supply power to large industrial customers like data centers,” Bri Knisley, a director at Appalachian Voices, said in a statement. Kingsley said more distributed, clean generation would help improve reliability during adverse weather. She also said data centers should fund their own clean generation.

“TVA already found these coal plants to be uneconomical and unreliable, and that hasn’t changed just because the administration wants to keep coal online,” added Leah McCord, a coordinator at Appalachian Voices. “For TVA to take this action without public input is contrary to the public power model these new board members all recently affirmed.”

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N.Y. Pursues Large Load Interconnection Reform

New York is trying to strike a balance between economic development, grid stability and affordability as potential new large load customers look for electricity.

The Public Service Commission on Feb. 12 initiated a proceeding to address large load interconnection reforms (26-E-0045).

It grows from Gov. Kathy Hochul’s (D) announcement of the Energize NY Development initiative in her Jan. 13 State of the State address, which stipulates that any project causing exceptional power demand must also create exceptional benefits to the state, or else cover the costs it imposes on the grid or supply its own energy.

The PSC order pertains to all large loads but notes data centers often do not promote the same degree of economic development or job creation as other facilities drawing large amounts of electricity.

The PSC is trying to accomplish several things as it crafts a proposed reform:

    • Modernize the interconnection process for all building loads.
    • Improve transparency and predictability related to grid upgrades.
    • Ensure that data centers and similar facilities bear the costs they impose on the electric system.
    • Provide for the continued reliability of the electric system.
    • Develop programs and policies for the interconnection of large loads that consider the objectives of the state’s landmark Climate Leadership and Community Protection Act (CLCPA).
    • Explore ways new large electric loads could lead to downward pressure on rates for all customers.

Beneath those objectives are a set of factors that are complex to address individually, let alone balance as a whole.

New York already has some of the most expensive electricity in the nation, its power generation and transmission infrastructure is aging, portions of the state are an economic backwater in need of new industry, and the CLCPA imposes a series of environmental and social justice considerations that are supposed to factor into decision-making.

The NYISO interconnection queue gained 8.3 GW of new load requests in 2025 and presently contains 11.9 GW attributed to future large load projects. The PSC noted the uncertainty of these numbers due to possible speculative or duplicative requests.

Hochul’s Feb. 12 news release said there were 48 large load projects in the NYISO queue in January and added: “The saturation of these projects in the interconnection queue, without clarity as to which projects will actually proceed to construction, increases uncertainty and complicates electric system planning and investment decisions.”

The PSC said the “beneficiary pays” model it uses when grid upgrades are needed to directly benefit a new customer is in alignment with state Public Service Law. But given the unprecedented load growth being projected, the PSC found it necessary to take steps to protect ratepayers from the costs that would follow.

Separately in New York, not even a week earlier, Democrats in the state Legislature proposed a data center moratorium to give time to better understand the issues involved and draw up policies in response. (See Data Center Moratorium Bill Introduced in N.Y. Legislature.)

Regulators and lawmakers in many other jurisdictions have reached similar conclusions in recent months.

The PSC order notes that approaches elsewhere have included long-term contractual agreements, capacity-based charges, bring-your-own-generation and higher electricity rates.

Some of these are listed as possible approaches in New York, along with flexibility/curtailment requirements, modified cost-sharing and cost-recovery rules, long-term contracts and ratepayer protection charges.

The PSC invited public comments, ordered a technical conference and directed staff at the Department of Public Service to draw up a briefing on the issues involved with large load interconnection.

“New York will continue to lead in attracting new technologies, but we must also grow responsibly, ensuring affordability comes first and those profiting from data growth pay their share,” Hochul said. “To prevent rising costs for everyday consumers, the state will enforce a simple standard: These industries must cover the costs of their expansion as it relates to utilities — just the same way it works for everyday consumers.”

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EMPOWER Keynoter Jenkins Stresses Regulatory Framework to Handle Data Center Demand

The first couple years of the data center boom have brought significant growing pains across the U.S.

Data center development, coupled with electrification and reindustrialization, has driven dramatic growth in load forecasts after years of relatively stagnant demand. Regulators, policymakers and RTO officials have scrambled to respond to this growth and balance the interests of consumers and private developers.

The scale of growth could be massive: Grid Strategies forecasts U.S. electricity demand increasing by 5.7% annually over the next five years, coupled with 3.7% annual growth of peak load. The U.S. Energy Information Administration forecasts more modest growth over the next two years, projecting 1 and 3% growth in 2026 and 2027. (See EIA Predicts Sustained Power Growth in 2026 and 2027.)

While there is significant uncertainty about how much of the currently proposed large loads will materialize, the potential for rapid demand growth has major implications for consumer costs, decarbonization and infrastructure needs.

Data center demand already has contributed to capacity price shocks in PJM and MISO. In 2025, rising demand helped drive a large increase in coal-fired generation, increasing power sector emissions as human-caused climate change nears 1.5 degrees Celsius of warming.

As demand growth accelerates, a strong regulatory framework is essential to preventing consumer and environmental impacts, said Jesse Jenkins, head of the ZERO Lab at Princeton University. Jenkins also recently co-founded Firma Power, a generation development company focused on providing clean, firm power to large load customers. He will be a keynote speaker Feb. 25 at Yes Energy’s EMPOWER 2026 Conference.

Jesse Jenkins | Princeton University

In a recent interview with RTO Insider, he stressed that data center developers must match their demand with new clean supply to prevent consequences for other consumers and the climate.

At the ZERO Lab, Jenkins’ research focuses on modeling future energy systems to help inform resource development and guide policy and long-term planning. Prior to the data center boom, energy system researchers were grappling with the expectation of substantial demand growth due to electrification, he noted.

“That has had us in this mindset of growth in the electricity sector several years before the rest of the market caught up to us with the growth of data centers — which, to be fair, we weren’t anticipating at the scale it is now,” he said. With the addition of data center load growth, “this is a new epoch in the sector, and it’s certainly awakened a lot of people to the challenges of being able to rapidly expand electricity supply.”

The data center development boom has brought a complex mix of challenges and opportunities, Jenkins said. The power sector could see broad benefits from developers willing to be early adopters of emerging technologies like advanced nuclear. But rapid increases in demand also likely will undermine energy affordability in the absence of strong consumer protections.

Unlike load from electrification, data center demand is highly concentrated — some planned developments would require multiple gigawatts of power.

“These are city-scale electricity consumers in one big building,” he said. “That raises very particular challenges around network constraints and network expansion, and the uncertainty of demand growth.”

“You can’t bring 2 GW of demand to the grid without bringing 2 GW of new supply without either prices going up a lot or grid reliability suffering, or maybe both,” Jenkins added, referencing a deal recently announced by Meta to procure power from multiple proposed advanced nuclear plants and 2,176 MW of capacity from two existing nuclear plants in PJM. (See Meta Announces Nuclear Projects with Vistra, TerraPower, Oklo.)

While high prices eventually may induce new supply to come online, he said treating data center developers like any other customer in the market does not appear to be a viable approach.

Price spikes and environmental concerns have led to increasing blowback against data centers across the country. According to one report, $98 billion in U.S. data center projects were blocked or delayed by political opposition in the second quarter of 2025. In New York, Democrats in the legislature are pushing for a three-year moratorium on data center siting and permitting. (See Data Center Moratorium Bill Introduced in N.Y. Legislature.)

Jenkins emphasized the importance of pairing data center developments with an equal amount of accredited new capacity and hourly matched clean energy. This could be accomplished by regulatory requirements or by fast-tracking the regulatory process for data center developments that meet these parameters, he said.

While developers so far have favored a voluntary process over bring-your-own-clean-supply requirements, a well-designed voluntary process could accomplish the same consumer protection objectives, he said.

“As long as there’s sort of a time to power advantage … it’s still like a competitive requirement to do it, because if you connect slower than your competitors, you’re not going to have much market share,” he said.

Asked about the possibility of FERC asserting jurisdiction over the interconnection of large loads, Jenkins said the idea “makes a lot of sense in theory.”

“I do think there’s a lot of merit to the idea that anything above a certain threshold size that’s connected to transmission voltage should be treated symmetrically to a generator of a similar scale,” he said. “In some ways it could make it more coordinated because you could do simultaneous generation and load interconnection.”

However, he said a lot will depend on implementation, and the change in regulatory approach could create complications for existing efforts to regulate data center loads.

“As with any regulatory change, the question is: Does it blow everything up for a period of time when there’s so much uncertainty about what’s going to happen that it halts all progress as people wait for the process to settle?”

Jenkins’ keynote address, “A Rock & A Hard Place: Challenges and Solutions to Meet the Data Center Demand Crunch,” will be delivered Feb. 25 at Yes Energy’s EMPOWER 2026 conference in Boulder, Colo. To learn more about EMPOWER, visit empower.yesenergy.com.

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ISO-NE Starts Work on Day-ahead Ancillary Services Market Changes

With costs associated with ISO-NE’s new day-ahead ancillary services market far exceeding expectations, the RTO is working to fast-track changes to improve the efficiency of the market in time for next winter.

The DAAS market, launched in March 2025, has seen estimated incremental costs totaling $921 million over its first 11 months, dwarfing the RTO’s initial estimate of about $140 million in annual costs based on data from 2019 to 2021. (See FERC Approves ISO-NE’s Day-Ahead Ancillary Services Initiative.)

David Naughton, executive director of ISO-NE’s Internal Market Monitor, said he shares stakeholders’ concerns about high prices. He attributed the high market costs to a combination of higher-than-expected offer prices, lower-than-expected market participation, and changes to broader market fundamentals including increased power demand and gas prices.

While the DAAS market has brought significant reliability benefits to the region, there are clear tradeoffs between the strength of incentives for reliability and market costs, he said.

To address these concerns, the IMM has proposed market adjustments intended to “improve the cost-effectiveness” of the day-ahead energy market while “maintaining consistency with the core design objectives.” The proposed changes include:

    • an upward adjustment to the strike price formula to reflect the significantly higher short-run marginal costs of most resources participating in the market;
    • a decrease in the forecast energy requirement to reflect the impacts of front-of-meter renewables, which have tended to eschew participation in the day-ahead market; and
    • a potential reduction in the non-performance factor associated with the ten-minute reserve requirement.

The proposed changes are intended to help lower offer prices and induce greater participation in the market, in part by reducing participants’ risk exposure. Without the changes, the tight conditions experienced in the market appear likely to persist long-term, Naughton said.

“If adopted, these changes are expected to place downward pressure on DAAS costs, are narrowly targeted in scope, can be implemented in the near term and present a low risk of unintended consequences,” the IMM wrote in a memo in early February.

At the NEPOOL Markets Committee meeting on Feb. 11, several stakeholders expressed strong support for implementing changes to the DAAS market as quickly as possible, supporting ISO-NE CEO Vamsi Chadalavada’s recent emphasis on the need to be nimble in the face of market issues. (See Prolonged Cold Drove Record Monthly Energy Costs in New England.)

Multiple NEPOOL members also expressed an interest in quantifying the reliability impacts of the DAAS market to better understand these benefits.

Fall Markets Report

Also at the meeting, Dónal O’Sullivan of the IMM discussed the performance of the ISO-NE markets in the fall season.

Total wholesale market costs increased by 28% relative to fall 2024, driven by a 58% increase in gas costs. The region relied heavily on gas-fired resources, which accounted for about 57% of all generation.

The estimated incremental costs of the DAAS market totaled $142 million in the fall, compared to $258 million over the prior six months.

The increased reliance on gas generation was driven by historically low import levels; for the first time in at least 20 years, New England was a net exporter of power over an entire season. Hydro-Québec continues to struggle with the effects of a multiyear drought, and it reduced exports in anticipation of its supply contracts associated with the New England Clean Energy Connect line taking effect. New England’s net imports from the province have rebounded since the project came online in mid-January.

Total demand increased by about 1.7% compared with fall 2024. The IMM attributed this to a change in the average temperature, which decreased by 3 degrees Fahrenheit.

O’Sullivan also provided more detail on the Nov. 23 capacity scarcity event, which occurred during relatively normal system conditions when a 900-MW thermal generator tripped during the evening peak. (See Unexpected Generation Loss Triggers Capacity Deficiency in ISO-NE.)

Pay-for-Performance credits from the event totaled $32.3 million, while the balancing ratio — which determines the responsibilities of each capacity resource relative to its capacity supply obligation — averaged 0.7.

“The best-performing generator types included flexible hydro and fast-start units and other non-fossil fuel units that were generally already online before the event,” O’Sullivan said. “Contracted imports underperformed their obligations, but uncontracted imports provided over 1,400 MW on average and earned over $7 million in credits.”

Long-lead-time oil generators took the biggest hit during the event, accumulating over $10 million in penalties.

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Data Centers Breeze Through PG&E’s Approval Process

California continues to go all in on data center development, with Pacific Gas and Electric playing its role in the last quarter of 2025 by pushing gigawatts of projects through the investor-owned utility’s design and approval process.

From Q3 to Q4 2025, about 2 GW of data center projects moved into PG&E’s final engineering phase. An additional 50 MW began construction during that time.

“We are excited by the opportunity to bring on large loads and deliver savings to our bundled customers,” PG&E CEO Patti Poppe said during the utility’s Feb. 12 earnings call, which covered Q4 and full-year performance. “The good news is that real [data center] load growth in project stages makes [future load] very real. We have lots of confidence about that.”

An example of PG&E aiding data centers is a recent 20-MW project in San Jose owned by Equinix. The Equinix project is part of a joint agreement between the IOU and the City of San Jose to bring data centers on faster, Poppe said.

The data center will receive power through PG&E’s Santa Teresa substation, which was renovated to meet the new load. Equinix paid for the necessary substation upgrades, PG&E said in a Jan. 22 release.

“This [project] was an opportunity to demonstrate that PG&E is delivering on our promise to provide fast, reliable power to large energy users,” Poppe said.

One analyst on the call asked if the improved visibility of real data center load will help PG&E have “line-of-sight to higher growth.”

“I would say … yes,” Poppe said. “We had previously said that 1.5 GW of [data center load] would be online by 2030. Now we are saying it’s closer to 1.8 GW [that] would be online by 2030. Obviously that continues to change and evolve as we get more applications, we combine projects and bring things online faster.”

Data center load could lower customer bills, Poppe said.

“For each gigawatt of large load, we see the potential to drive savings of 1% or more on average monthly electric bills,” Poppe said. “To do this, it is actually quite simple: We just need to get the price right.”

“We want a relationship between data centers and customer affordability — [this is] receiving a lot of attention at the national level,” Poppe said.

Everyone should understand the value of the IOU model and how important attracting low-cost, high-quality investment is to spreading the cost for infrastructure for customers over the long haul, Poppe said.

In 2025, PG&E’s capital expenditures were $13.4 billion, with $12.4 billion forecast for 2026, $13.4 billion for 2027 and $15.4 billion for 2028. In addition to these forecast expenditures, PG&E identified opportunities for investment in transmission infrastructure for data centers, the IOU said in its Q4 2025 Form 10-k filing.

“There’s other things … that we’ve got in the hopper to help drive affordability [like] supply cost. There’s a lot that goes into a customer’s bill to help get us to that 0% to 3% [bill increase] range,” Poppe said.

PG&E’s unadjusted earnings came in at just over $3.3 billion for 2025 ($1.50/share), compared with $2.9 billion in 2024 ($1.36/share).

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Consumer Group Says NIPSCO Affordability Crisis Direct Result of Indiana Laws

In multiple Facebook groups, Indiana residents say their gas and electricity bills have skyrocketed — sometimes quadrupling — since the start of winter.

They share bills detailing more than $1,000 in gas and electric expenses, often with hundreds of dollars’ worth of gas delivery charges. They discuss using woodstoves to heat homes, grilling out in the cold, switching to propane and closing vents in little-used rooms.

Small businesses, churches and cat rescue shelters issue fundraising pleas to defray utility costs. Those comments are interspersed with allegations of price gouging, class action lawsuits and appealing directly to President Donald Trump for relief.

But a consumer advocacy group says the affordability crisis dogging Northern Indiana Public Service Co.’s ratepayers is the product of an indulgent state legislature.

Kerwin Olson, executive director of Indiana consumer and environmental advocacy organization Citizens Action Coalition, said the affordability crisis was built on state law that has been too accommodating to utilities for more than a decade. Indiana law is “incredibly pro-utility” and “forces customers to pay for anything and everything,” he said.

“We’ve for a long time been pointing to incredibly favorable legislation that all but mandates the Indiana Utility Regulatory Commission approve these increases,” Olson said in an interview with RTO Insider.

Olson said that even before a July 2025 rate increase for NIPSCO, customers had already been subjected to the largest increases in 20 years.

Indiana’s unaffordability journey can be traced to Indiana Senate Bill 25, enacted in 2011, that granted utilities incentives for already made investments or those they were required to make, shifting all costs of federal mandates to ratepayers — all without a least-cost energy rule, Olson said.

SB 251 was followed by 2013’s Senate Bill 560, which created a tracker that allows recovery of “billons and billions” in infrastructure projects through automatic rate hikes outside of rate cases, he said.

By 2019, the legislature had enacted House Bill 1470, which again involved a tracker to make it easier for Indiana utilities to recover up to 80% of the costs of transmission, distribution and storage system improvements.

“What we’ve seen with Indiana utilities, especially with NIPSCO, is significant, significant capital investment,” Olson said.

State law, including two bills from the House of Representatives in 2023 and 2025, has also rendered the IURC “all but a rubber stamp,” allowing NIPSCO to recover “extraordinary amounts of capital investments” in gas pipelines, transmission and distribution, and clean energy projects after it committed in 2018 to phasing out coal generation.

Olson said that’s on top of ratepayers still covering the costs of older generating assets.

“The challenge is folks are still paying for the old while they’re paying for the new,” he said, adding the Indiana statehouse has never addressed how to deal with stranded costs through securitization or other “creative” means.

Statehouse Scrambles on New Bill

Facing pressure, the House drafted and passed House Bill 1002 in January. The bill would introduce a performance-based ratemaking structure among Indiana utilities, linking their annual revenue and profit to their ability to meet the needs of residential consumers.

Under the plan, utilities would be placed on multiyear plans for rate increases that include “incentives and disincentives in target areas such as service restoration, reliability and affordability.” The bill would also extend grace periods on service cutoffs in the hottest and coldest months and offer levelized billing options to customers.

The bill is before the Indiana Senate for consideration.

Olson said HB 1002 “is sort of a tacit agreement” that the spend-and-receive model isn’t working in Indiana. He said it’s the first indication that Indiana lawmakers could shift to performance-based increases and more predictable bills, and away from trackers that have “pancaked cost upon cost upon cost.”

“We can certainly be doing more than HB 1002,” Olson said. “But for once, we have a bill that is pro-consumer. I’m encouraged with how the conversation is going. I can tell you the statehouse is hearing these folks loud and clear.”

Olson warned that progress would be slow and take time to reach the IURC. Nevertheless, he predicted a paradigm shift in the state to move “away from simply rewarding utilities for spending money.”

In the meantime, Olson sympathizes with residents receiving bills that rival or eclipse mortgage payments.

“It is absolutely outrageous. We saw this coming; we were warning this day was right around the corner. We have been sounding the alarm, not only about the legislature, but also the NIPSCO rate case and in general over the years,” he said. “That’s a shame because people are hurting.”

Olson also said for NIPSCO’s service territory, cost spikes caused by data centers haven’t entered the equation.

“Data centers are not the No. 1 reason right now. They will be,” he said. But Olson said the current situation in NIPSCO isn’t induced by data center plans, though they are “absolutely driving up bills.”

In response to the affordability crisis and RTO Insider’s request for comment, NIPSCO has repeatedly advertised its budget billing plan, which spreads the cost of average usage over 12 months. It is meant to provide a consistent monthly statement, except in May, when the utility conducts reviews to adjust for over- or underpayments.

Ahead of winter, NIPSCO warned that heating bills would be 16% higher in the 2025/26 season than in the previous year.

And rates are not done increasing. In March, NIPSCO is slated to roll out the second phase of a two-part hike allowed by the IURC in June 2025. The commission allowed a total 16.75% increase in electric bills to support NIPSCO’s infrastructure projects.

Signs in front of homes in NIPSCO service territory | Amanda Wothke (left) and Des Cain via Facebook

NIPSCO said the rate mark-up will fund more than $2 billion in capital investments to transition its generation to a more “balanced” portfolio and $769.5 million for critical infrastructure upgrades, including replacing aging poles and lines, constructing new substations, and modernizing grid facilities to improve reliability.

Beyond that, the IURC allowed gas rate hikes in 2022, 2023 and 2024 and an electric rate increase in 2023. Before the 2025 rate increases, NIPSCO’s residential customers paid the highest electric bills in Indiana.

The IURC in November 2025 opened an investigation into possible billing discrepancies with customers’ natural gas meters. However, that investigation focuses solely on errors with gas meter readings, not NIPSCO’s exponentially growing gas delivery charges or other billing aspects.

IURC: ‘We Recognize the Burden’

The IURC declined to comment on its ongoing investigation. External Affairs Specialist Ben Gavelek also declined to comment on “any potential commission actions or future investigations.”

The commission is encouraging any customer who has concerns about the accuracy of their bill to call its Consumer Affairs Division, Gavelek said.

The IURC is “an advocate of neither the public nor the utilities” and is “required by statute to make decisions in the public interest to ensure the utilities provide safe and reliable service at just and reasonable rates,” he said.

“With that stated, the commission understands that these are challenging and unprecedented times for many Hoosiers, and we recognize the burden that higher utility bills can have on customers. Keeping this in mind, our role continues to be the careful examination of the evidence in each specific proceeding to ensure utilities are making prudent decisions as they meet their obligation to provide safe and reliable service,” Gavelek said.

However, he added that the Indiana General Assembly determines policy directives and sets the considerations that the commission must follow and weigh in each case. Gavelek said that includes Indiana’s “Five Pillars” statute, which obligates the commission to consider “reliability, resiliency, stability, environmental sustainability and affordability” in ratemaking.

Rep. Ed Soliday (R), chair of the legislature’s Utilities, Energy and Telecommunications Committee, did not comment on RTO Insider’s question on whether past legislation may have had unintended consequences on ratepayers and whether he thinks HB 1002 goes far enough to rectify the issue.

Instead, Soliday and other area Republican representatives’ press office shared a press release from Rep. Alaina Shonkwiler (R), who authored HB 1002.

“Our utility framework has served communities well for many decades, but as technology, policies and generation types advance, we must update our regulatory process to continue to meet ratepayers’ needs,” Shonkwiler said in the late January release. “This legislation moves us to a performance-based system that holds utilities accountable for the outcomes we want — strong reliability, improved resilience and better affordability.”

NIPSCO: Rates Approved by IURC

Acknowledging the outcry, NIPSCO has said higher bills are the result of cold weather, gas prices and infrastructure costs. In January, CEO Vince Parisi told local news stations that unusually low winter temperatures were the driving force behind the bill increases.

“We understand that some customers are seeing higher‑than‑normal winter bills, and we want them to know we hear them. We know this is frustrating, and our priority is to support customers, answer questions and help them stay connected,” NIPSCO said in a statement to RTO Insider.

NIPSCO said its gas delivery charges “support the operation, maintenance and safety of the entire natural gas system, including transmission and distribution mains, service lines, regulator stations and emergency response.” The utility said they increase when more gas is used and pointed out that the charges are approved by the IURC.

The utility did not answer RTO Insider’s question as to whether it is rolling new investments into bills that previously were not recovered.

The utility has not made a post on its Facebook page since Dec. 28, 2025. Before then, the utility often issued inclement weather advisements through posts; the page stayed silent during a late January winter storm. Recent posts have attracted angry comments from customers.

NIPSCO also said rising data center load is not impacting bills.

“Any data center development in our service territory will be served under the NIPSCO Generation LLC structure, a model built specifically to ensure that large, energy-intensive customers do not shift costs onto residents or local businesses,” NIPSCO said.

When NIPSCO decides to evaluate small modular reactors, some of those costs could also get tacked on to ratepayer bills. Senate Bill 424 allows utilities to pass along some of the pre-construction costs to their customers — even if the nuclear generation is never finished.

NIPSCO said it’s internally evaluating SMRs for its integrated resource planning but so far has not had customers pay for development or other associated costs.

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Caution Urged as Regulators Consider NV Energy’s Request to Join EDAM

With CAISO’s Extended Day-Ahead Market to launch May 1, some parties are urging Nevada regulators to wait until initial results are in before deciding whether to grant NV Energy’s request to join EDAM.

“Given that EDAM is scheduled to ‘go live’ in May 2026, we will have a much clearer picture of these risks [of EDAM participation] in one year’s time,” Michael Roberson, utility analyst with the Nevada Bureau of Consumer Protection, said in written testimony. “Both the governance structure and the identities/volume of participants should become much clearer. Most importantly, we will see real cost/benefit data instead of projections.”

NV Energy filed its request to join EDAM in October 2025. The Public Utilities Commission of Nevada (PUCN) set a Feb. 10 deadline for parties to file testimony in the case. A hearing is scheduled for March 10.

NV Energy’s target date for EDAM entry is fall 2028. (See NV Energy Files Request to Join EDAM.) PUCN is expected to issue an order within 135 days of the initial filing.

As part of its request, NV Energy asked the commission to approve its participation in EDAM as prudent.

Roberson said PUCN should deny that request. A prudency determination now, while it’s not known if projected benefits of EDAM participation will materialize, would shift risk to ratepayers, he said.

Positive WEIM Experience

Factors in NV Energy’s choice of EDAM — rather than SPP’s competing day-ahead market, Markets+ — include its positive experience with CAISO’s Western Energy Imbalance Market (WEIM), the company said in its filing. NV Energy accrued $931 million in benefits from the time it joined WEIM in 2015 through the third quarter of 2025.

NV Energy also pointed to better transmission connectivity within the anticipated EDAM market footprint compared to that of Markets+.

A Brattle Group study, updated in October, projected that NV Energy would save $93.1 million a year by joining EDAM, compared to participating in WEIM alone. In contrast, joining Markets+ would increase annual costs by an estimated $7.3 million.

David Chairez of DSC Utility Consulting recommended that the PUCN wait to see whether benefits modeled for the electric utilities joining EDAM in 2026 and 2027 materialize before making a prudency finding for NV Energy to join EDAM. Chairez filed testimony on behalf of Boyd Gaming Corp., Caesars Enterprise Services, MGM Resorts International, Nevada Gold Mines, Southern Nevada Water Authority, Station Casinos and Venetian Las Vegas Gaming.

The PUCN should also wait to see what changes are made to NV Energy’s open access transmission tariff (OATT), Chairez said.

“The commission cannot decide on prudence without reviewing those proposed changes to understand the effects they will have on Nevada customers,” he said.

Another unknown is how much participants might end up paying in resource sufficiency evaluation (RSE) penalties, Chairez said. The RSE is intended to make sure each balancing authority can meet its own obligations before making transfers with other EDAM participants.

Participation Timeline

EDAM is expected to launch on May 1 with participation from PacifiCorp. Initially, the day-ahead market will identify efficient resource commitments and energy transfers among the PacifiCorp West, PacifiCorp East and CAISO balancing areas, a CAISO spokesperson said. Portland General Electric plans to join EDAM in fall 2026.

The Los Angeles Department of Water and Power, Public Service Company of New Mexico, Turlock Irrigation District and Balancing Authority of Northern California are planning their entry in 2027, followed by Imperial Irrigation District in 2028.

Carolyn Berry, a partner with Bates White Economic Consulting, filed testimony on behalf of Google, recommending that the PUCN approve NV Energy’s request to join EDAM. (See Western Market Seams Complicate Data Center, Clean Energy Investments, Panelists Say.)

Berry said EDAM would give NV Energy access to a highly diverse — and complementary — resource mix, including low-cost solar from California and wind resources from the Pacific Northwest. And NV Energy can leverage its experience with WEIM to reduce implementation risk and uncertainty “compared to joining an entirely new market construct,” she said.

Regulatory operations staff at the PUCN recommended several conditions for commission approval of NV Energy’s EDAM request.

Those include ordering the company to develop a commission-approved method for quantifying annual production cost savings from EDAM participation; and filing progress reports on revisions to the OATT. Another recommendation is that NV Energy’s shareholders should bear the cost of any RSE surcharges.

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Imports ‘Key Vulnerability’ to California Energy Security, CEC Report Says

California’s reliance on a large amount of imported electricity and fossil fuels is a potential weakness in the state’s energy security portfolio, a California Energy Commission staff report finds.

About 30% of the state’s electricity, 90% of its natural gas and 75% of its petroleum are imported, resulting in a potential “key vulnerability to the state’s overall energy health,” according to the agency’s California Energy Security Plan (CESP), which staff presented at a Feb. 11 CEC business meeting.

The CESP examined the state’s energy use and infrastructure and outlined state government agencies’ responsibilities in preventing and mitigating energy disruptions.

California imports more electricity than any other state and is the third largest consumer of electricity in the country.

Natural gas-fired power plants provide most of the state’s electricity capacity — 39,689 MW, or 45% of capacity. But about 90% of the state’s gas supplies are from out-of-state production basins, which are often thousands of miles away, the report says.

California is vulnerable also to spikes in electricity demand and downstream disruptions, which have been occurring more frequently in recent years, the report says.

During grid emergencies, CAISO might decide to reduce power exports and increase power imports. Energy shortages can affect any state resident but often affect vulnerable people most significantly.

Most of the state’s energy assets and infrastructure are owned and operated by private entities. This means that the state’s energy security plan relies on a free-market approach to control energy distribution and supply, the report says.

At the Feb. 11 meeting, CEC Vice Chair Siva Gunda asked if the agency should be considering other areas of concern not listed in the security plan.

Generative artificial intelligence is one of those areas, said Justin Cochran, senior nuclear policy adviser and emergency coordinator at the CEC.

“[Generative AI] is a developing concern still, though some of the concern has ramped down as build-out of generative AI is slowing or encountering barriers on both the deployment and technology side,” he said.

Another security concern: drones.

“I think the conflict in Ukraine has really expanded upon or shown the capability of drones, so that is a developing concern,” Cochran said.

Earthquakes are the natural hazard of highest concern, the report found. California has more than 200 faults that are potentially hazardous, while more than 70% of residents live within 30 miles of a fault where high ground shaking could occur in the next 50 years.

The next two most concerning hazards are wildfires and floods. In 2022, wildfires in the state killed nine people while destroying 772 structures and damaging 104 more.

The report also updated the state’s strategy for responding to a state emergency. One of the CEC’s roles in such an emergency is to develop and maintain the fuels set-aside program, which can be used during and after an earthquake, for example, the report says.

At the meeting, the CEC also approved a nearly $5.7 million grant for Monterey County to install 390 EV chargers and four solar photovoltaic systems at municipal facilities. Despite the increased availability of EVs and charging infrastructure, local governments in California continue to face barriers to scaling up municipal fleet decarbonization, translating into a need for significant state investment to increase the pace of EV adoption, the CEC’s award notice said.