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February 12, 2026

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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.

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N.J. Looks to Utilities for Solar Expansion Answers

New Jersey’s Board of Public Utilities is asking the state’s four utilities for thoughts on how to help waive regulations and speed up the connection of distributed energy resources as it seeks to modernize its grid.

A Request For Information seeks written responses from the utilities on five topics the state hopes will illuminate how to enhance the capacity of DERs to help meet a predicted dramatic increase in electricity demand. Utilities must file their responses by March 5.

Several of the questions ask how the utilities are complying with updates to grid modernization rules approved in May 2025 meant to reduce delays in the distribution grid interconnection process and speed up the timeline for projects to come online. (See N.J. BPU Backs New Grid Modernization Rules.)

The RFI also asks utilities to identify opportunities for the BPU to “modify or waive existing regulations in order to improve efficiency and speed of interconnecting new projects.”

Other questions ask how the BPU can improve hosting capacity maps, identity constrained circuits within the company’s service territory and address “other means of supporting development of DERs on constrained circuits.”

“New Jersey has seen a rapid expansion of solar deployment,” the RFI states, in part due to the development of its Community Solar Energy program and the Competitive Solar Incentive program, which seeks to stimulate grid scale solar projects. “This progress, however, is hindered by an electric distribution grid with severe hosting capacity constraints on key circuits.”

ACE: Infrastructure Modernization

The RFI stems from one of two executive orders issued by Gov. Mikie Sherrill (D) on her first day in office, in line with her campaign promise to address the state’s rapidly rising electricity rates. The average electricity bill rose by 20% in June.

Analysts say the price hike stems in part from the state’s generating capacity shortfall due to the rapid closure of aging, mainly fossil fuel generators and the much slower uptake of clean energy resources. New Jersey is an energy importer, and analysts predict a dramatic rise in demand due to energy-intensive data centers, significantly worsening the state’s energy shortfall.

Asked about the governor’s RFI, Atlantic City Electric (ACE), one of the state’s four utilities, and one that has faced criticism for delays in connecting electricity projects, welcomed the “continued engagement with regulators and stakeholders.” (See Solar Developers: New Jersey’s Aging Grid Can’t Accept New Projects.) The other utilities are PSE&G, Central New Jersey Power and Light, and Rockland Electric Co.

“We are committed to modernizing our energy infrastructure to further improve energy service for our customers,” ACE said in response to an inquiry by RTO Insider. The utility noted it’s executing its Powering The Future initiative. That’s a multiyear infrastructure investment plan that will facilitate the “interconnection of approximately 385MW of new solar generation — equivalent to 50,000 average residential solar arrays — enabling more distributed energy resources at a time when demand continues to increase,” the company said. Included in the plan is $33 million to enable “the deployment of additional solar and other DER projects,” of which $20 million would go on solar/DER distribution line improvements, according to the plan.

“We are reviewing the Board of Public Utilities’ request on accelerating DER interconnections and look forward to identifying additional ways to help customers adopt cleaner energy resources,” a statement released by ACE, a subsidiary of Exelon, said. “At the same time, we recognize the strain of high energy costs.”

New Solar Capacity Slows

Sherrill’s executive order (See New N.J. Governor Rapidly Confronts Electricity Crisis.) requires the BPU to accelerate solar generation with a new solicitation for grid-scale solar and an extra 3,000 MW of generation under the Community Solar Program.

The governor’s executive order acknowledges that the excess of demand over supply facing the state is a “significant driver of the electricity crisis,” and identifies solar and storage generation resources as the quickest way to address the problem. New installed capacity has slowed in the past two years, with 307,225 kW added in 2025, about 30% lower than two years earlier. Installed solar resources, which totaled 5.38 GW at the end of 2025, account for about 7% of New Jersey’s electricity generation.

The order adds that solar and storage projects are delayed “often by electric distribution utilities, as they are responsible for reviewing and approving applications from electricity generation facilities to interconnect to the power grid, including applications from renewable energy projects.”

The BPU, seeking to illuminate the reason for connection delays, asks the utilities to identify at least two circuits that “receive high numbers of interconnection application requests (either by total capacity requested or number of applicants), that are either closed or close to being closed due to voltage constraints.”

The RFI also asks the utilities to “provide a list of circuits with the worst reliability performance based on outage data that should be prioritized for infrastructure upgrades.” And it asks them to “include the metrics, methods and criteria used for selecting the worst-performing circuits.”

The issue of how to improve the ability of DER projects to get connected has been “perennial” in New Jersey and elsewhere, said Paul Patterson, an energy analyst for Glenrock Associates. Central to the issue are questions over whether “resources are being hooked up fast enough, and what’s causing the delays,” he said.

“It’s the context that makes this more significant,” he said. That includes the dramatic price hike stemming from PJM’s capacity auction, and Sherrill’s embrace of utility affordability at the center of her campaign.

“It’s very preliminary. They just seem to be asking for information,” he said of the RFI. “The real question is, what does Sherrill and her administration really come up with in the way of a policy to actually deal with the issue of rising electricity prices?”

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Winter Storm Drives Potential Record for January N.Y. Electricity Costs

The average cost for electricity in NYISO was $201.89/MWh in January, up nearly 53% from January 2025 and possibly the highest ever for the month, the ISO reported in its first market operations report of the year.

“I went back and manually clicked through all the previous January and February monthly market operations reports I could find,” said Shaun Johnson, vice president of market structures for NYISO. “This was the highest.”

Johnson cautioned he could not definitively say whether the prices were the highest for January ever. He said the documents he was able to pull were not comprehensive, and several years were missing market operations reports.

“$137 was the previous high number I was able to find,” he said, pointing to a report from February 2022.

Stakeholders asked whether this meant January’s average was the highest ever when adjusted for inflation. Johnson said he was not prepared to assert that. He said the figures from 2013, during the polar vortex cold snap, were also quite high.

The culprit was the late January winter storm. A graph in the operations report depicting the average daily cost shows a dip below $60/MWh before spiking as high as $840/MWh when the storm hit. The average cost for January 2025 was $132.26/MWh.

Johnson said the storm’s unusually large footprint, and the long duration of extremely low temperatures, contributed to the spike. The storm hit almost the entire East Coast, and demand on all of the Eastern Interconnection was high for an extended period.

The average locational-based marginal price was $192/MWh, up from $107.81/MWh in December 2025 and $127.05/MWh in January 2025. Natural gas prices at NY Transco Zone 6 were $19/MMBtu, up from $6.93/MMBtu in December 2025, showing the strong correlation between gas prices and electricity prices NYISO reported in the aftermath of the storm. (See NYISO: Gas Demand Soared Across Eastern U.S. During Fern.) However, it was a 2.2% decrease from January 2025.

A stakeholder representing Central Hudson Gas and Electric asked whether NYISO would consider also tracking the natural gas prices at Iroquois Zone 2, given that they also went “through the roof” during January. Johnson said he would look into it, but NYISO does not have a source that it can publish numbers from publicly.

Uplift costs were higher in January 2026 compared to the previous month: $1.79/MWh, from $1.11/MWh. Johnson said that he anticipated the Market Monitoring Unit would go into depth on this in its quarterly State of the Market report.

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NIPSCO Insists on MISO Midwest Allocation for Indiana Coal Plant Costs

Northern Indiana Public Service Co. replied to comments on and protests to its request that FERC allow it to recover the costs of continuing to operate the R.M. Schahfer Generating Station from the 11 states in MISO Midwest, insisting that it is the quickest solution (EL26-36).

The utility said waiting for the states to create a cost allocation method through the MISO stakeholder process would unnecessarily delay its requested relief after being forced to keep the plant online past its scheduled retirement by the U.S. Department of Energy.

If approved by FERC, Schahfer would follow in the footsteps of the J.H. Campbell coal plant in Michigan, which is also operating under an emergency order from DOE under Federal Power Act Section 202(c) and was granted a MISO Midwest-wide allocation.

In an early February response, NIPSCO said many of the challenges to its request rest on the lawfulness of the order itself and “amount to an impermissible collateral attack on action taken by the U.S. secretary of energy.”

“The comments and protests raise issues that are outside the scope of this proceeding and impinge on NIPSCO’s constitutional and statutory rights to recover costs,” the utility said.

MISO states had asked FERC to order discussion in the RTO’s stakeholder process to settle on a cost allocation design. (See Regulators: MISO Stakeholders Should Decide Cost-sharing for DOE Coal Plant Orders.) The Organization of MISO States said DOE’s “self-determined energy emergency does not obviate the commission’s obligation to establish just and reasonable rates.”

In mid-2025, DOE began issuing emergency orders under Section 202(c) to keep power plants in Pennsylvania, Michigan, Indiana, Colorado and Washington online past their scheduled retirement dates. OMS said a cost allocation design should be formed with input from the states affected, especially because DOE is likely to continue ordering other retiring thermal units to stay online.

But NIPSCO said rate recovery issues are FERC’s domain, not a MISO stakeholder process matter. It argued that there is no harm in allowing a regionwide cost allocation because it has not yet sought to recover the costs of keeping the coal plant available. It said interested parties would be free to review and contest it when it does, regardless of allocation.

“Establishing a mechanism now does not prejudice any party’s rights,” NIPSCO said.

The utility also said it is “incurring significant capital, operating and maintenance costs to comply with these directives.” It said delays would undermine its “ability to recover costs it is legally obligated to incur.”

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Nickell: RSC ‘Best-in-class’ Among Grid Operators

LITTLE ROCK, Ark. — SPP CEO Lanny Nickell says the grid operator’s Regional State Committee, composed of regulators from its (current) 14-state footprint, offers a structure others might follow.

“I believe that the SPP RSC model is unique, and I think it’s the best-in-class among the RTO world,” Nickell told the committee’s members during its February meeting. “It’s based on shared responsibility, transparency, and it’s something that I value very much. Our staff and our board remain committed to strengthening our relationships with you and supporting your work every step.”

Nickell pointed to recent discussions he has had with legislators as he tours the service territory to raise awareness. He said in a recent visit with the Kansas legislature, he learned how the Kansas Corporation Commission’s Andrew French and his staff have explained the value SPP brings.

“These conversations have reaffirmed for me just how important our RSC partnerships are,” Nickell said.

The RSC was created in 2004 to provide regulatory input on “regional importance related to the development and operation of bulk electric transmission.” In approving the group’s creation, FERC recognized the need for a mechanism that facilitates regional consensus on critical issues related to transmission planning and operation.

The commission also made the RSC the first organization of state regulators from multiple states to be expressly granted authorities in a FERC-jurisdictional grid operator. The commissioners exercise this authority by determining whether and to what extent participation funding will be used for transmission improvements and whether license plate or postage-stamp rates will be used for the regional access charge.

The RSC has grown to 13 members with the recent addition of Montana commissioner Randall Pinocci. The membership will increase again with the RTO’s expansion into the Western Interconnection in April.

Two future members, Wyoming’s Mike Robinson and Arizona’s Nick Myers, watched from the sidelines. A third, Colorado’s Eric Blank, called in.

The committee also welcomed two new members in the Louisiana Public Service Commission’s Eric Skrmetta and the New Mexico Public Regulation Commission’s Greg Nibert. Skrmetta replaces Mike Francis, and Nibert takes over for Patrick O’Connell, who chaired the RSC in 2025.

Economic Consultant Approved

The RSC approved the selection of Bates White Economic Consulting to provide expertise in transmission cost allocation and evaluating its benefits.

The D.C.-based firm, chosen by the committee’s leadership from five respondents to a request for proposals, will be tasked with providing information and education, analyzing cost-allocation options for the SPP RTO region, a facilitate discussion among the committee’s members and its Cost Allocation Working Group.

“I feel this is an indication of the increased focus on cost allocation by the RSC,” Texas’ Kathleen Jackson told her fellow commissioners during their February open meeting, noting the consultant is a first in “recent times.”

The commissioners also agreed to sunset the Improved Resource Availability Task Force, which was formed in the aftermath of 2021’s Winter Storm Uri. The group carried out recommendations from SPP’s post-storm report, ensuring generators have reliable fuel and the grid operator improves how it plans for and manages resource availability.

The task force handed off its leftover items to the Resource and Energy Adequacy Leadership Team when the latter was formed in 2023.

“The issues have been challenging, but I think the REAL Team has really stood up, stepped up and developed much-needed policies that strengthen reliability across the entire footprint,” Nickell said. “Some of the favorable outcomes from [January’s winter storm] were a result of a lot of the work that the REAL Team did … and all the stakeholders that played a role along the way.”