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February 27, 2026

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SPP Secures 2 More Commitments for Markets+ in Washington

SPP has secured two new commitments for its day-ahead Markets+, as Grant County Public Utility District and Tacoma Power in Washington state announced their intent to join.

The utilities are slated to begin participating in Markets+ and SPP’s real-time market on Oct. 1, 2028, joining at least seven other entities that have signed agreements, the RTO announced Feb. 27.

“The addition of Grant County PUD and Tacoma Power reflects the continued growth and momentum of Markets+ across the Pacific Northwest,” said Carrie Simpson, SPP vice president of markets. “These utilities recognize the value of a market built on strong governance, reliability and cost savings for their customers. We look forward to our continued partnerships building a market that works for the entire Western Interconnection.”

The two utilities are both parties to a $150 million funding agreement SPP signed in April 2025 with eight Western entities to develop Markets+. However, neither utility had announced when it would join, according to SPP’s announcement. (See SPP Launches Markets+ Phase 2 With $150M Secured.)

Arizona Public Service, Powerex, Public Service Company of Colorado, Salt River Project and Tucson Electric have said they will begin participating in Markets+ when it goes live in October 2027. Grant County PUD and Tacoma Power, together with Puget Sound Energy and Chelan County PUD, are set to join in 2028.

The Bonneville Power Administration announced in May 2025 its intention to pursue participation in Markets+ over CAISO’s Extended Day-Ahead Market, but a group of nonprofits has challenged BPA’s decision in the 9th U.S. Circuit Court of Appeals. (See related story, Nonprofits Tell 9th Circuit BPA’s DAM Decision Poses ‘Imminent’ Harm.)

Grant County PUD serves approximately 56,000 customer meters in Central Washington and operates more than 2,100 MW of hydroelectric generation, according to SPP’s announcement.

Tacoma Power, meanwhile, serves 186,975 customers in Pierce County.

“Grant PUD’s mission is to deliver reliable and affordable energy to our growing customer base,” John Mertlich, the utility’s CEO, said in a statement. “Joining SPP’s Markets+ is a strategic step that strengthens our ability to do so. Additionally, joining Markets+ aligns us with a growing coalition of utilities across the West who are working toward a more reliable, interconnected and economically integrated regional power grid.”

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Energy Availability Tops MRO’s 2026 Risk List

Uncertain energy availability remains an “extreme priority risk” for the Midwest Reliability Organization for the third year in a row as generation growth fails to keep pace with rapidly rising demand, representing the highest level of risk classification in the regional entity’s 2026 Regional Risk Assessment.

Six other risks were classified as high priority in the assessment, released Feb. 23. Extreme and high risks are considered to require “immediate attention for regional awareness and mitigation efforts,” as opposed to medium and low risks, which can be “managed with routine procedures or less intensive monitoring.”

The six high priority risks are nation-state threats; generation outages during extreme cold weather; supply chain compromises; inadequate inverter performance and modeling; malicious insider threats; and material and equipment unavailability. All were a high risk in 2025 except material and equipment unavailability, which moved up from medium to high in the 2026 report. Another seven risks, including loss of essential reliability services, physical attacks, inaccurate facility ratings and various cybersecurity risks, were considered medium priority.

MRO produces the Regional Risk Assessment each year as a supplement to NERC’s Long-Term Reliability Assessment. Risks are identified throughout the previous year from various sources including risk assessments, government intelligence and stakeholder engagement, and ranked by a team comprising subject matter expert volunteers and MRO staff according to potential impact and likelihood of occurrence.

In NERC’s 2025 LTRA, released Jan. 29, the ERO warned that multiple assessment areas — including significant parts of MRO’s footprint — face a high risk of energy shortfalls over the next 10 years, largely because of projected demand growth outstripping planned generation additions. (See NERC Warns of ‘Worsening’ Resource Adequacy Through 2035.)

The regional assessment is consistent with this analysis, citing “accelerating retirements of dispatchable power plants before adequate replacement energy is available, limited transmission capacity and barriers to timely deployment of new infrastructure” in the MRO region to explain why uncertain energy availability earned the highest risk rating. Amplifying the risk is the increasing presence of weather-dependent, hard-to-forecast resources like wind and solar among projected new generation.

The report’s authors moved material and equipment unavailability up in the rankings because of “industry sentiment on lead time extensions and the loss of guaranteed production slots for major grid equipment [like] transformers and circuit breakers.” MRO pointed to reports of utilities “cannibalizing underutilized equipment” to prevent delays to urgent repairs and new construction in more heavily used parts of the grid.

Generation outages during extreme cold weather remain a high priority risk, MRO said, with winter demand growth continuing to outpace summer demand growth and “signaling a fundamental shift toward winter-peaking energy usage.”

However, the RE also assessed the risk as slightly less likely to occur, primarily because of the adoption of NERC’s new cold-weather reliability standards such as EOP-012-3 (Extreme cold weather preparedness and operations), which took effect Oct. 1, 2025. (See FERC Clarifies Cold Weather Standard Approval, Effective Date.)

“There are performance improvements as evidenced by no major events within the MRO region; discovering limits and managing those equipment limits have yielded tangible results,” MRO wrote. “There is a sense of ‘cautious optimism’ with this progress, as reliability concerns remain in the production and delivery of natural gas and whether recent extreme winter storms match conditions seen in benchmark storms.”

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Judge Orders Spill at Northwest Dams to Aid Salmon, Despite Energy Concerns

An Oregon federal judge ordered increased spill levels at eight dams on the Columbia and Snake rivers to protect endangered salmon species, rejecting claims that doing so would impede power generation.

U.S. District Judge Michael H. Simon on Feb. 25 granted a preliminary injunction sought by the states of Oregon and Washington, tribes and environmental groups. The order requires the U.S. Army Corps of Engineers and the Bureau of Reclamation to spill large amounts of water over the dams instead of running it through turbines to protect migrating salmon and steelhead in the Columbia and Snake rivers.

Simon said the salmon species have “dwindled to near extinction levels” as the issue has played out in courts over the decades.

“One of the foundational symbols of the West, a critical recreational, cultural, and economic driver for Western states, and the beating heart and guaranteed resource protected by treaties with several Native American tribes is disappearing from the landscape,” Simon wrote. “And yet the litigation continues in much the same way as it has for 30 years.”

The case, which began in 2001, now concerns an environmental impact statement and a biological opinion from 2020 that the court ordered the federal agencies to prepare for the Federal Columbia River Power System.

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

The case was stayed after former President Joe Biden assumed office and allowed the parties to work out a deal. An agreement was reached in 2023, which included $1 billion toward salmon restoration.

The Biden administration was considering breaching four dams on the Snake River that produce more than 3,000 MW, but it did not make a final decision.

The parties resumed litigation after President Donald Trump upended the deal in June 2025. The Trump administration said the deal would have several negative impacts on energy production, shipping channels and water supply for local farmers. (See Trump Directs Feds to Withdraw from Deal on Snake River Dams and BPA Cuts Payments for Tribes, Salmon Restoration Under Revised Cost Projections.)

In resuming the case, the plaintiffs asked the judge for injunctive relief beginning March 1.

Specifically, they sought a preliminary injunction to address alleged violations of the Endangered Species Act.

They urged the court to order federal defendants to increase spill levels, lower reservoir levels and implement emergency conservation measures for the salmon.

In his Feb. 25 order, Simon granted the motion in part, writing he “declines to impose many of plaintiffs’ requests challenged by the federal defendants as outside of this court’s equitable authority to grant.”

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

“The court is unpersuaded by arguments that spill will create various catastrophic results,” Simon wrote. He added that defendants have presented similar concerns in the past “without them coming to fruition.”

“The majority of the spill has been implemented over the years without such negative repercussions, and the court does not anticipate such calamities will ensue from the current spill order,” Simon wrote.

PPC ‘Disappointed’

Though Simon ordered modifications to spill levels, he granted defendants’ request to keep reservoir levels at the 2025 operating levels and declined to implement a series of nonoperational conservation measures.

“Those limited acknowledgments, however, do not offset the broader impacts this decision could have on the region’s power supply, transmission operations, greenhouse gas emissions, and customer costs,” Public Power Council’s Scott Simms said in a statement.

PPC is the lead defendant-intervenor for public power in the case. The group represents Northwest publicly owned utilities that buy federal hydropower marketed by the Bonneville Power Administration.

“PPC is disappointed that the court adopted a sweeping operational injunction that will materially affect the region’s clean hydropower system and the millions of people who depend on it,” Simms said. “The Columbia River system already operates under some of the most protective fish measures in the nation, and public power utilities have invested billions of dollars over decades to support salmon recovery while producing reliable and affordable electricity.”

A spokesperson for the U.S. Department of Justice declined to comment.

Meanwhile, plaintiffs celebrated the ruling.

“We absolutely can have clean energy and restored salmon runs, and today’s ruling is an important step in the right direction,” Zachariah Baker, NW Energy Coalition’s regional and state policy director, said in a statement. “The ruling helps protect salmon, while the region continues to collaborate on the comprehensive, strategic solutions envisioned in the Resilient Columbia Basin Agreement the administration withdrew from, including how to ensure abundant, affordable and reliable clean energy across the Northwest.”

Simon denied the defendants’ request to stay the case pending appeal.

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Municipal Utility Would Cost City of Tucson $4B, Study Finds

As Tucson, Ariz., weighs whether to take over part of Tucson Electric Power’s electric system to form a municipal utility, a new study said such a move would cost the city more than $4 billion.

The Brattle Group study, commissioned by TEP, found that the additional cost to city residents would average about $290 million per year for the next 20 years under a municipal utility compared to sticking with TEP.

“Municipalization can be lengthy, litigious and costly,” said the paper, by Brattle principals Toby Bishop and Ann Bulkley and associate Adam Wyonzek.

The authors noted that of 68 electric utility municipalizations attempted in the U.S. in the last 25 years, only seven succeeded. And in two of the seven cases, the utilities were later sold back to the original investor-owned utility.

In announcing the new study Feb. 24, TEP CEO Susan Gray said a city takeover of the utility’s system would be “an unrealistic, unaffordable and unnecessary distraction.”

“A forced takeover would jeopardize reliability, slow clean energy development and create roadblocks for economic development initiatives that depend on TEP’s proven ability to deliver power safely, reliably and sustainably,” Gray said in a statement.

TEP serves 457,000 customers in Tucson and surrounding areas. TEP and its parent company, UNS Energy, are subsidiaries of Canada-based Fortis.

The city has been exploring formation of a municipal utility as one potential way to rein in electric rates and meet climate goals. The 25-year franchise agreement between the city and TEP expires in April.

Residents in support of a Tucson municipal utility are upset by rising electric bills and TEP’s backing of new data centers in the area, according to a group called Tucson Democratic Socialists of America. The group said it has collected more than 4,000 signatures on a “public power for Tucson” petition.

“Let’s put it to a vote, TEP. Let Tucson decide on public power,” the group said in a release.

Conflicting Reports

The city commissioned its own study of forming a municipal utility. An April 2025 draft report found that a Tucson municipal utility would be financially feasible, and average residential customers would see their electric bills drop by $241 per year within the first five years. The report was prepared by engineering and consulting firm GDS Associates and law firm Best Best & Krieger.

The Brattle researchers noted several reasons their findings differed from those of GDS Associates. GDS assumed municipal service would start in 2028, which Brattle called unrealistic. Brattle went with a 2032 start date instead, noting that acquisition costs will increase over time as TEP invests more in its system.

GDS estimated it would cost between $1.4 billion and $3.6 billion to buy TEP’s electric system in Tucson; Brattle pegged acquisition-related costs at $4.05 billion. And TEP’s costs to serve Tucson customers would be lower than a municipal utility’s costs over the 20 years examined, Brattle projected.

In another difference between the two studies, GDS assumed TEP’s rates would increase 3.5% per year, based on an inflation rate “calculated during a period when inflation was at its highest in the past 40 years,” Brattle said. By contrast, Brattle estimated future rates through a breakdown of generation, transmission and distribution components.

Data Center Impacts

Brattle also looked at impacts of the Project Blue data center that has been proposed within TEP’s service area — but outside of Tucson. TEP expects the data center to bring in significant revenue that might create rate benefits for other customers.

“[The data center’s] exclusion from the area served by a municipal utility would make municipalization even more financially infeasible,” Brattle said.

A $3.6 billion Phase 1 of Project Blue would consist of 10 data center buildings that could begin operation as soon as 2027. A Phase 2 of data center development could follow.

The Arizona Corporation Commission voted 4-1 in December to approve a 286-MW energy supply agreement between TEP and the Project Blue developer. (See TEP Wins Approval for Data Center Energy Supply Agreement.)

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MISO, SPP CEOs Bet on Improved Interconnection Processes for AI Load

NEW ORLEANS — MISO’s and SPP’s CEOs are confident their interconnection queues will be up to the task of meeting new data center load once their respective special expedited lanes wind down.

SPP CEO Lanny Nickell and MISO CEO John Bear also touched on interregional planning and frustration with NERC predictions and offered advice for Western counterparts on how to resolve adversarial, inter-RTO relationships at the Gulf Coast Power Association’s MISO-SPP conference.

Moderating the dual CEO discussion Feb. 23, Gulf Coast Power Association Executive Director Barbara Clemenhagen asked if the “gobbling up gigawatts” by Meta, Google, Amazon and other tech companies in the RTOs’ footprints could become a positive economic growth story without reliability pitfalls.

“We want the economic growth, but we have to have the reliability,” Nickell said. He said large loads could help reduce others’ rate burdens “if they commit to their share” of costs.

“We need the economic development for sure, and we’re on the path to do it reliably,” Bear said. He said that by the end of 2026, MISO should be caught up with its backlogged generator interconnection queue and have slimmed future cycles to a one-year process. The RTO is simultaneously processing its 2025, 2023 and 2022 project entrants while wrapping up studies on some projects from its 2021 cycle. (See MISO Pushes Interconnection Queue Timelines Back Again.)

However, Nickell said the traditional generator interconnection queue “just doesn’t work.” He said it began to slide into dysfunction when developers started flooding lineups with speculative projects. That led SPP to pursue its Consolidated Planning Process (CPP), which merges transmission planning with its generator interconnection procedures. The new process is awaiting FERC approval.

ERAS to Remain Fleeting

In an interview with RTO Insider following their dialogue, the CEOs pledged that their RTOs’ respective expedited interconnection queues will be one-time processes despite a nearly insatiable demand for new generation.

Nickell said that after SPP collects 10 to 13 GW from its Expedited Resource Adequacy Study (ERAS) process, it plans to use its CPP to ensure more timely queue processing. He also said SPP will rely heavily on artificial intelligence offered by Hitachi and Nvidia to land on faster and smarter upgrade solutions.

On the other hand, Bear said MISO has no plans to embark on anything like the CPP anytime soon. He said when it retires its expedited queue process, the RTO will rely on a svelte, one-year queue process to accept generator interconnections.

MISO shelved an idea to create consolidated transmission planning process in 2023.

The RTO will announce another round of approved expedited generation projects in March, expected to total 6 GW. It will continue announcing rounds of projects quarterly until the end of August 2027, or until it hits a predetermined, 68-project cap.

MISO said 4.7 GW of expedited projects have already struck generator interconnection agreements and are expected online by the end of 2028.

NERC Friction

Both CEOs expressed dissatisfaction with NERC’s 2025 Long-Term Reliability Assessment, which categorized MISO as being at “high risk” and SPP at “elevated risk.”

Bear sent a letter to NERC calling for a more nuanced approach to the assessment and taking issue with the ERO apparently ignoring MISO’s expedited generation process, which he argued would more than eradicate NERC’s predicted 7-GW shortfall beginning in winter 2028/29.

He also said NERC’s conclusion essentially ignored the annual resource adequacy survey the RTO produces in partnership with the Organization of MISO States. The most recent OMS-MISO survey showed the potential for anywhere from a 11.4-GW surplus to a 14.1-GW deficit by the 2030/31 planning year.

“The truth is neither one of us has a long-term problem, and if we do, we’re going to solve it,” Bear said of MISO and SPP. He said MISO “doesn’t need a third party who’s not involved” with day-to-day decisions issuing predictions.

Bear argued that maintaining margins near requirements — the most affordable and lowest-cost route — requires hard work.

Nickell said he agreed that “the whole story isn’t being told,” particularly when it comes to NERC not factoring ERAS projects into SPP’s capacity projections.

But Nickell said he wasn’t surprised at NERC ratcheting up SPP’s vulnerability meter and said it’s clear that system dynamics are flashing warning signs.

Speedier Stakeholder Process?

GCPA’s Clemenhagen said the RTOs might be fielding “dangerous levels” of data center demand, especially considering that MISO’s reserve margins have fallen from about “24% to potential shortfalls in a short period of time.”

Bear said the most challenging part of the moment is addressing all industry headwinds at once through a rigorous stakeholder process. He said no one includes “speed” and “stakeholder process” in the same sentence, a reality that must change.

“It’s not just the speed of the change; it’s the complexity,” Nickell added. “Load growth has become astounding and never seen before in our careers.”

Nickell said it’s hard to believe that a decade ago, SPP reduced its reserve margin requirement. Now, he said, SPP is exponentially more likely to experience a loss-of-load event and is doing “all we can” to avoid one.

He said he lies awake at night with thoughts of “have we done enough today? Have we done enough this month? Have we done enough this year?” He said load growth is pushing the RTO to rethink everything.

Nickell said the two RTOs must put more ideas through their stakeholder processes faster, but he cautioned that — likening it to running — moving from a recreational 14-minute/mile pace to a demanding seven minutes/mile is risky.

“We need to make sure we don’t run away from stakeholders. They need to be with us. They need to be alongside us as we solve these challenges,” he said.

Bear said market and planning improvements at MISO over the years have been designed by staff and stakeholders who presume they are at a safe place, pin down a solution and “analyze it, analyze it, analyze it, analyze it.” MISO no longer has that kind of time, he said.

“The presumption that we’re in a safe place is false,” Bear said.

However, Bear said, MISO and SPP are not struggling with data centers competing with retail load.

“So, you’re saying we’re not PJM?” Nickell responded.

Emphasis on Interregional Transfers

Neither CEO sees the need anytime soon for a second Joint Targeted Interconnection Queue transmission portfolio, which helps get generation connected at the seams. Instead, they said they plan to focus on broadening interregional transfer capability in the near term.

Bear said MISO and SPP are open to using the seven transmission benefits established in FERC Order 1920 to assess new interregional transmission projects.

“There might be a little bit of smoothing out that we have to do,” Bear said of benefit metrics. Nickell said SPP would emphasize “reliability and resilience.”

Until now, the RTOs have considered only adjusted production costs when evaluating possible interregional projects through their Coordinated System Planning.

Getting Along

Finally, the pair had advice for burgeoning markets in the West.

Bear said MISO and SPP have gone from frosty distrust to planning transmission together and touching base several times as weather events unfurl.

“We had lunch today without food tasters,” Bear joked. “I think there’s trust there, and there’s collaboration.”

“There was a time when SPP and MISO could barely say each other’s names in public,” Clemenhagen kidded.

“There’s not a choice there. If we survive, we survive together. If we fail, we fail together,” Nickell said.

Nickell said a stronger relationship and communication improvements during past winter storms have allowed the grid operators to share their supply more effectively. He said MISO had excess power to hand off to SPP during Winter Storm Uri in early 2021, while SPP had spare power to deliver during Winter Storm Fern in late January 2026.

“Without those seams agreements in place, that power would not have been exported or imported,” Nickell said. “At some point, you have to get comfortable that seams exist.”

Nickell said unlike MISO and SPP’s relationship, the West is still settling into the idea of the existence of more than one market. He advised that collaboration would make them stronger.

“Competition makes us better,” Nickell said. “That realization has to hit first.”

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N.J. Considering Use of RGGI Funds to Curb Rate Hikes

New Jersey is studying whether to use funds from the Regional Greenhouse Gas Initiative to keep down electricity rates and restructure the way utilities are compensated in the state’s effort to reduce the upward pressure on electricity prices.

The New Jersey Department of Environmental Protection in a Feb. 19 release said it had discussed using uncommitted RGGI funds with the Board of Public Utilities and Economic Development Authority. The three agencies together oversee the expenditure of income from the initiative.

The DEP said that in line with an executive order issued by Gov. Mikie Sherrill on Jan. 20, her first day in office, the state would “use available uncommitted and future RGGI proceeds to offset bill increases stemming from the rise in the price of electricity, especially for vulnerable families struggling to make ends meet.” (See New N.J. Governor Rapidly Confronts Electricity Crisis.)

“Similarly, DEP and EDA are actively assessing potential approaches related to energy affordability and generation that align with existing statutory parameters for the use of RGGI funds,” the department said. It noted that allocation of funds “outside of these parameters would require legislative authorization.”

New Jersey has committed $950 million in RGGI funding to clean energy projects, including $88 million in 2025, according to the DEP. It does not say how much was left in uncommitted funds after that expenditure.

The state has in the past prioritized RGGI funds for promoting healthy homes, investing in clean and equitable transportation, promoting carbon capture and reducing the use of refrigerants. Supported projects have included investing in fleets of electric municipal school buses and garbage trucks, and helping put electric vehicle chargers in multiunit dwellings. (See NJ To Accelerate RGGI Fund Expenditures.)

Alternative Utility Business Models

The planned redirection of RGGI funds comes as the state searches for ways to expand its generating capacity and prevent rates from rising under the pressure of a future capacity shortfall.

Analysts say the state and others in PJM are facing an energy shortfall in part because old generators have shut down more rapidly than new sources have come online.

The resulting shortfall has contributed to a spike in electricity costs, which resulted in a 20% increase in the average New Jersey bill in June. But analysts say the biggest part of the hike stems from the rapid arrival of heavy energy-using data centers.

Looking to tackle the issue from a different direction, the BPU voted 5-0 to procure a consultant to “examine alternative utility business models as a mechanism to drive down electricity costs for New Jersey customers,” according to an agency release.

“This study will result in a concrete plan to address how the utility business model can better serve customers throughout the state,” BPU President Christine Guhl-Sadovy said.

The consultant will “evaluate a range of potential regulatory reforms, including performance-based ratemaking, which ties utility profits to outcomes like reliability and customer savings rather than simply how much they spend,” according to the BPU. The consultant will also look at “multiyear rate plans, reductions to utility returns on equity, least-cost resource testing and securitization tools.”

“The goal is to identify which combination of changes offers the greatest long-term savings for ratepayers while providing certainty for the industry and encouraging important investments to ensure reliability of the system,” it said.

The resulting study “will focus on the longer-term question of whether the underlying business model itself needs to be changed,” the board said. “The BPU wants to better understand how much of that increase is driven by the way utilities are currently regulated — and what a different approach might mean for customers’ bills in the future.”

‘Broken’ System

In the traditional cost-of-service model, regulators determine utility revenues based on operational expenses and capital investments and grant an agreed return on investments.

However, there has been a growing recognition that changes to the basic cost-of-service model may be needed to accommodate the changes in the energy industry, including state clean energy policies and rapid load growth.

Performance-based regulation includes regulatory approaches such as financial incentives and penalties; performance metrics and scorecards; multiyear rate plans; and revenue decoupling. The aim is to direct utilities toward achieving goals and outcomes not explicitly considered in traditional ratemaking.

Abraham Silverman, a former counsel for the BPU and now assistant research scholar at Johns Hopkins University’s Ralph O’Connor Sustainable Energy Institute, said the BPU’s move shows that Gov. Sherrill is “obviously very serious about tackling the utility business issue.”

“Everyone talks about how broken the existing system of utility regulation is — allowing utilities to earn more the more they spend,” he said. That system “doesn’t work very well and leads to the utility doing the same old things.”

“It’s commonly recognized that we’d all like to see utility spending align with New Jersey’s energy policies,” he said. “That means financially rewarding utilities that implement policy effectively rather than just spend more money.”

New Jersey is one of 17 states that are exploring the use of performance-based regulation, with another 11 that have moved toward implementation or have done so, according to the National Association of Regulatory Utility Commissioners.

Paul Patterson, a utilities sector analyst for Glenrock Associates, said that it can be “politically difficult to implement new regulatory regimes that significantly could hurt the utility industry,” although such efforts are not necessarily negative for the utilities.

One example of a “long regulatory review” that centered on “utility performance and affordability” played out in Connecticut and has yet to be implemented, he said. In that case, the effort by the Public Utilities Regulatory Authority to shift to performance-based regulation stoked controversy.

Eversource Energy and Avangrid decried the effort for hampering their ability to receive a fair return on investments, but PURA said it was simply holding the utilities accountable to existing standards. (See The Rocky Road to Performance-based Regulation in Connecticut.)

The effort eventually stalled because of unrelated issues, Patterson said. In general, the effectiveness of the approach has yet to be determined, he said.

Regulators can potentially, but not necessarily, come up with regimes that “could be a lot more disruptive than what has been implemented in many states to date,” he said, referring to the impact on the business model of utilities. “I think it’s important to see what actually gets implemented, and it’s a little early right now to say what that would be.”

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EPRI Boosts Data Center Load Growth Projection by 60%

A new EPRI report raises projections of data center power demand growth by 60% from a similar report the research organization prepared two years ago.

“Powering Intelligence 2026” estimates data centers could consume as much as 17% of U.S. electricity by 2030 but might consume as little as 9%.

While the low growth estimate still would be a substantial increase over present-day data center power use, it would be far short of some of the high-end projections being offered in this and other analyses.

EPRI said the effort to more narrowly estimate future demand is hampered by the number and gravity of variables at play: what percentage of announced projects actually get built; how quickly they ramp up; what gains are made in energy efficiency; and what constraints the supply chain, labor market and permitting regimes impose.

For this reason, the report offers three possible scenarios rather than one prediction, and it looks only as far as 2030.

The report also urges better collaboration among data center developers, energy suppliers, equipment vendors, policymakers and communities to better execute a period of rapid demand growth — industrial users and electric vehicle operators are expected to place additional stress on the grid at the same time as a wave of data centers comes online.

“As this analysis shows, the scale and speed of data center growth represent a defining moment for the U.S. power system,” EPRI Vice President of Electrification and Sustainable Energy Strategy David Porter said in a Feb. 26 news release announcing the report.

In the 2024 analysis, EPRI projected data centers would consume 4.6 to 9.1% of U.S. electricity generation by 2030.

Largely because of the record levels of development since that was published, the 2026 analysis boosts the estimate to 9 to 17%.

That would be 56 to 132 GW of nominal capacity and peak load of 45 to 94 GW, depending on what percent of the announced data centers are fully operational by 2030. Total power use would be 380 to 790 TWh per year.

The increase in demand is expected to be so rapid, EPRI said, that it may reverse the historic pattern of efficiency improvements offsetting increased quantity of computing.

Another change in the 2026 analysis is the generation technology expected to be added to the grid. The 2024 analysis projected significantly higher wind and solar deployment. The update finds that natural gas may dominate near-term supply changes but warns that manufacturing, siting and permitting bottlenecks may constrain generation and transmission development.

EPRI predicts continued growth in the two largest data center markets (Texas and Virginia) and increased interest in states with lesser existing capacity (New Mexico, Ohio, Pennsylvania) or little capacity (Indiana, Louisiana, Mississippi) due to availability of land and power or friendly permitting.

Virginia is the only state where data centers now consume more than 20% of electricity, but seven other states could surpass 20% by 2030 under the medium-growth scenario modeled in the report: Arizona, Iowa, Indiana, Nebraska, Nevada, Oregon and Wyoming.

None, however, would catch up to Virginia, where data centers might account for 39 to 57% of in-state electricity use in 2030.

The report is based on state-level data on operational capacity, construction in progress and announced plans.

EPRI repeatedly flags the difficulty of estimating load growth because of the confidentiality in which some details are cloaked and because of the speculative nature of many projects that are publicly disclosed, as well as the fundamental uncertainty about the future evolution of artificial intelligence.

EPRI offers some of its own collaborative initiatives — DCFlex, GET SET, Mercury, Distributed Data Centers — as steps toward better managing the planning and preparation for data center growth.

It also suggests that growth projections be updated regularly and that growth modeling be calibrated to data center load profiles and use patterns as more of these data points become available.

The report concludes, as have many other observers and analysts, that demand flexibility on the part of Big Tech would be impactful.

“Through EPRI’s DCFlex initiative, we’re working across the power and digital ecosystems to make data centers more flexible and better integrated with the electricity system,” Porter said. “Collaboration will be key to ensuring reliable and affordable energy for all.”

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Indiana Commission Opens Affordability Inquiry into Utilities

The Indiana Utility Regulatory Commission opened an investigative inquiry into the state’s major utilities in response to increasingly steep residential electric and gas bills.

IURC Chair Andy Zay, who has been on the job for six weeks, promised a “transparent and public discussion” on affordability and rising rates. He said the “environment we’re living under” is a product of rate cases that were decided three to four years ago and whose full impact is now being felt.

“I think affordability is defined every … month by Hoosiers when they receive that bill,” Zay said during a Feb. 25 press conference.

The IURC will hold a hearing March 24, with representatives of all five major utilities in the state called to appear. They are asked to present on energy affordability, bill transparency and how they could bring down mounting costs in the near term.

Zay said the IURC is going to proceed as quickly as it can. He said he plans to personally meet with ratepayers while collecting information in the field. The inquiry could morph into a formal investigation with a case number, Zay said, and could also set off a re-examination of existing law.

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

“There may be legislative concerns that come out of this inquiry,” Zay said. “As you know, we do not make policy here at the commission. We’re the implementors of policies.”

However, Zay said, he wants ratepayers to know that “we have their back” to help ensure there are enough energy resources for economic growth at the most affordable rates possible.

Including Zay, the IURC comprises three new commissioners, appointed by Gov. Mike Braun in December 2025. Zay is a former state senator.

Indiana’s major regulated investor-owned utilities include AES Indiana, CenterPoint Energy, Duke Energy Indiana, Indiana Michigan Power and Northern Indiana Public Service Co. Of those, NIPSCO has raised rates most dramatically in recent years. (See Consumer Group Says NIPSCO Affordability Crisis Direct Result of Indiana Laws.)

The IURC’s 2025 Electricity Residential Bill Survey found the average NIPSCO customer using 1,000 kWh in July shouldered an over-90% increase in their bill from 2016 to 2025. The U.S. Energy Information Administration also reported that NIPSCO in 2024 charged the second-highest residential customer rate among all electric utilities that reported data. NIPSCO’s rate is about 30% higher than Indiana’s median residential rate.

A day before the inquiry announcement, IMP announced it would file a rate decrease with the IURC this summer. The utility said it could lower base electric rates because of higher revenue from an influx of large load customers, including Google’s data center in Fort Wayne.

Zay said the press conference was unprecedented because the commission is “not typically an outward-facing agency” and it is not the agency’s “style … to get involved in these issues.”

However, he said the commission’s Consumer Affairs Division has received a “volume” of complaints, as well as correspondence from state representatives.

Zay said the commission took a few months to decide how to address fast-rising rates because it was examining what role it could play in short-term solutions. He said until now, most of the IURC’s work is reactionary based on the cases that come before it.

“It’s time for us to participate in two ways: one, be reflective of decisions we’ve made in the past and change the tone or create a tone of how we’re going to look at cases going forward, and two, [decide] what we can do in the short term,” Zay said.

He cautioned that the commission is challenged not only by affordability concerns, but also by reliability, resilience and environmental considerations.

“Those are difficult to define in a financial sense. And that’s in no way to excuse or dodge anything,” he said.

Former Commissioner Praises Probe

Regulatory Assistance Project principal Sarah Freeman, who exited the IURC in October 2025 after nine years as a commissioner, said the inquiry is an “important step in making energy regulation — and thus affordability concerns — more open, accessible and accountable to the public.”

“Energy regulation and ratemaking are getting the public attention they’ve always deserved, but the reason why is deeply unfortunate,” Freeman said in a statement to RTO Insider. “Every Hoosier deserves to be able to afford life’s necessities, and it’s unacceptable that anyone has to make impossible choices like whether to heat their home or feed their family.”

Freeman commended the IURC for hearing concerns and acting on them. She said the recent passage of Indiana’s House Bill 1002 — which would link rates to performance benchmarks like affordability and reliability — provides “an opportunity for the commission to really dig deep and figure out how to make reliable energy cheaper for Hoosiers.”

But Indiana consumer and environmental advocacy organization Citizens Action Coalition has said laws the state enacted in 2023 and 2025 have rendered the IURC powerless to do anything but endorse rate hikes.

Freeman did not comment on whether she was unable to rein in rate increases because of state law.

A Reckoning for Past Laws?

Indiana House Democrats released a joint statement welcoming the inquiry; they also said blame can be attributed to legislation passed over the past 15 years.

“The truth is, legislation passed by the Statehouse Republican supermajority is why Hoosiers are facing massive spikes in their utility bills today. An investigation without an honest assessment of these policies will be incomplete,” they said.

Democrats said the existing unaffordability crisis originated in 2013 with Senate Enrolled Act 560, which created a charge that allowed utilities to recover 80% of the costs of system improvements without having to establish a rate case. They also cited subsequent laws that ended Indiana’s energy efficiency program, terminated net metering, stuck customers with coal ash cleanup costs, allowed construction work in progress (CWIP) recovery and shut out transmission-building competition through a right of first refusal for incumbent utilities.

Nearly a month before the IURC’s announcement, a group of 16 House Republicans sent a letter to Zay detailing “a significant rise in the number of emails, phone calls and letters from our constituents regarding their NIPSCO bills.”

They said NIPSCO’s rate statistics in particular are “concerning” and requested an investigation into whether “rates have become unreasonable or unjustly discriminatory.”

The Republicans asked the IURC to get to the bottom of what investments and operational expenses of the last decade have led to the increases, compare rates among other state utilities and those in peer states and identify steps to curb rising energy rates.

“We want to thank all who have reached out to us about the hardships that they have faced due to these high NIPSCO bills, and we will continue to advocate that Indiana’s regulatory framework properly balances the five pillars of energy policy: affordability, reliability, resiliency, stability and environmental sustainability,” they wrote.

They did not address whether past laws that allowed automatic charges and trackers influenced the predicament.

Meanwhile, in neighboring Illinois, lawmakers have introduced the Utility Transparency Act (HB4781/SB3497), which could prohibit utilities from passing on certain internal costs to customers, including corporate and legal fees, advertising, trade group membership dues and insurance to protect shareholders. It represents the state’s tactic to counter its own spate of electric and gas bills that have recently doubled.

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APS Would See Greater Savings in EDAM, Analysis Finds

Arizona Public Service would save $110 million/year by joining CAISO’s Extended Day-Ahead Market (EDAM) rather than SPP’s Markets+, a new analysis has found, even if other Arizona utilities remained with Markets+.

The analysis by Aurora Energy Research for the Environmental Defense Fund, released Feb. 9, looked at day-ahead market participation by APS, Tucson Electric Power and Salt River Project. All three, along with Unisource Energy Services, announced their plans to join Markets+ in November 2024.

TEP would save an estimated $8.1 million/year by joining EDAM even with APS and SRP participating in Markets+, Aurora’s analysis said. In contrast, SRP would see a cost increase of $4 million/year or more by joining EDAM instead of Markets+.

The annual figures are averages for 2027 to 2040. Aurora based its market footprints on commitments made to join either EDAM or Markets+, and in some cases which direction an entity seems to be leaning. Included in the EDAM footprint are NV Energy, which is awaiting state regulatory approval for its EDAM choice; Idaho Power, which is deemed a likely EDAM participant; and Seattle City Light, which has expressed interest in EDAM.

The analysis assumes the Western Area Lower Colorado (WALC) balancing authority area remains uncommitted to either day-ahead market. WALC — which spans parts of Arizona, California and Nevada — is run by the Western Area Power Administration’s Desert Southwest Region, which in March 2024 pulled out of the second phase of Markets+ development after determining it would see few benefits from joining a day-ahead market. (See WAPA DSW Cites Lack of Benefits in Markets+ Withdrawal.)

Aurora also looked at an Arizona-wide scenario in which APS, TEP, SRP and WALC participated in EDAM. In that case, the entities would save $115 million/year on average compared to APS, TEP and SRP joining Markets+ and WALC staying uncommitted.

“Choosing a West-wide market is one critical step in managing affordability and strengthening grid resilience,” Alex Routhier, senior policy adviser with Western Resource Advocates, said in a statement. “Utilities must evaluate all available options and choose the market that will deliver the greatest cost savings and reliability benefits to Arizonans.”

Governance Questions

EDF said EDAM “is poised to be the largest and most resource-diverse market in the region.” Following the passage of California Assembly Bill 825 in 2025, EDAM will be governed by a new independent Regional Organization for Western Energy — a step that might alleviate some concerns about independent governance — and CAISO will operate the market itself.

But Nick Myers, chair of the Arizona Corporation Commission, said he still has issues with EDAM.

“Should EDAM decide to address the governance and resource adequacy issues in a manner that is acceptable to others, which means providing a level playing field for all states, then I can envision a scenario where we could re-evaluate” the utilities’ participation in Markets+, Myers said in a statement to RTO Insider. “But until that time, Arizona is unlikely to choose a market that disproportionately favors California interests to the detriment of Arizona customers.”

Myers said he had not yet fully reviewed the Aurora report. He noted that Arizona utilities have their own studies showing that customers could benefit from either market.

In announcing its plans to join Markets+, SRP said it was drawn to its governance structure, which promotes independence, transparency, inclusivity and stakeholder-driven decision-making. (See 4 Arizona Utilities Commit to Joining Markets+.)

Resource adequacy was another factor in the utilities’ decision. SPP will require Markets+ participants to join the Western Power Pool’s Western Resource Adequacy Program.

APS said it did not participate in the Aurora study. Instead, the company performed “a rigorous evaluation of all market options,” factoring in reliability, affordability, customer protections and governance.

“The analysis indicates that Markets+ provides the greatest long-term value for our customers,” APS said through a spokeswoman. “We continue to be excited about customer benefits as we prepare to participate in Markets+ in late 2027.”

Costs and Savings

If APS joined EDAM while TEP and SRP stayed with Markets+, APS’ production costs would increase because of the need for more thermal generation in response to decreased thermal imports from SRP, according to the report. But bilateral trading costs would fall as overall import volumes decrease and access to renewables grows in the wider EDAM footprint.

APS’ congestion and wheeling revenues would increase because of greater use of transmission capacity from trade with PacifiCorp East and Public Service Company of New Mexico (PNM).

TEP’s savings from joining EDAM rather than Markets+ are in part from a $25 million decrease in production costs, as baseload thermal generation declines because of reduced exports to Markets+ balancing areas, the report says. Those savings would be partially offset by decreases in congestion and wheeling revenues. Export revenues would fall as TEP’s trading footprint shrinks. Under EDAM, TEP would trade more with PNM and less with APS and SRP.

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Nonprofits Tell 9th Circuit BPA’s DAM Decision Poses ‘Imminent’ Harm

The consequences of the Bonneville Power Administration’s decision to join SPP’s Markets+ could hit the Northwest sooner rather than later even though the agency has yet to formally join the market, a group of nonprofits suing it over the choice told the 9th U.S. Circuit Court of Appeals.

The group wrote in a reply brief that the potential injuries arising from BPA’s day-ahead market choice are “imminent,” urging the court to reject agency’s argument that the suit is too hypothetical for standing. The brief is dated Feb. 20 but appeared on the docket Feb. 23.

As the NW Energy Coalition “has emphasized, Bonneville is now implementing numerous steps to ‘go live’ in Markets+ in October 2028,” the group wrote. “Every additional step towards that date without vacate and a remand order will make a fair and candid look at alternatives less likely. The court has everything it needs to vacate the DAM policy and [Record of Decision] and remand for preparation of an” environmental impact statement.

Represented by Earthjustice, the organizations suing BPA include NWEC, Idaho Conservation League, Montana Environmental Information Center, Oregon Citizens’ Utility Board and the Sierra Club.

On May 9, BPA issued its decision to join Markets+ over CAISO’s Extended Day-Ahead Market (EDAM). The announcement came after a lengthy debate over which day-ahead market would provide the most benefits to BPA and its customers. (See BPA Chooses Markets+ over EDAM.)

The plaintiffs filed their claims July 10, alleging the agency failed to factor in environmental impacts and financial considerations in violation of the National Environmental Policy Act, the Pacific Northwest Electric Power Planning and Conservation Act, and the Administrative Procedure Act. (See BPA Sued in 9th Circuit over Day-ahead Market Decision.)

BPA has yet to officially join Markets+, but it plans to do so in October 2028.

In a Dec. 19 answering brief, the agency argued the plaintiffs lack standing because the alleged injuries rest on its participation in Markets+, which has yet to happen.

Even if the court finds the group has standing, the claims under the Northwest Power Act and NEPA fail under precedent established in the 9th Circuit, BPA argued.

BPA’s decision “is a quintessential example of the agency evaluating what is in its sound business interest,” according to the agency. It said the suit is an attempt at getting the court to “second-guess that determination.”

“Although they disagree with BPA’s conclusions, BPA considered the relevant factors and articulated a rational connection between the facts found and the choice made,” it contended.

In the Feb. 20 brief, the plaintiffs called BPA’s injury assessment “incorrect.” They noted that when BPA announced its day-ahead market choice, it also announced it intends to exit CAISO’s Western Energy Imbalance Market (WEIM).

“Leaving the WEIM will result in immediate cost and reliability harms to NWEC,” the Feb. 20 brief states.

BPA’s failure to consider the environmental impacts of its choice further demonstrates the immediate risk of harm, the plaintiffs claimed. It focused only on the economic impacts of extreme weather and the necessity of building out transmission lines and generation resources, which all “have environmental consequences that Bonneville never disclosed or considered,” they argued.

Though BPA claims the DAM policy and ROD are just preliminary steps and do not trigger the need for an environmental analysis, it has committed $40 million to Markets+, demonstrating there “is nothing tentative about this choice,” the plaintiffs argued.

“While a formal contract to join has not yet been signed, the policy and ROD set in motion multiple concrete steps that are designed to culminate in a contract to join Markets+ two years from now,” according to the brief. “These steps include negotiating specific contracts, initiating necessary rate cases and amending standards.”

BPA has argued that its day-ahead market process was conducted with significant stakeholder input, noting in its final market decision that other electric utilities weighing which market to join have done so “without public process or transparency.”

Production cost studies found that participation in EDAM under certain scenarios could deliver the agency up to $106 million in greater benefits than Markets+. However, the agency has contended those failed to factor in other key issues, like governance.

“BPA rationally opted for Markets+,” the agency argued in the Dec. 19 answer. “It presented less risk in meeting BPA’s core statutory function of economical service to its customers. Moreover, Markets+ proved superior in several important evaluation criteria, which, from early in the process, BPA emphasized would be important considerations.”

Trade organizations have filed motions to intervene in the suit in support of BPA, including the Public Power Council, Alliance of Western Energy Consumers, Pacific Northwest Generating Cooperative and Northwest Requirements Utilities. (See BPA Supported by Trade Orgs in Suit over Day-ahead Market Decision.)

They, along with SPP itself, highlighted Markets+’s governance approach and “overall design.”

The trade organizations filed a brief Jan. 23 saying, “BPA’s decision to pursue Markets+ was not arbitrary or capricious, as BPA considered relevant quantitative and qualitative factors and rationally applied those factors in reaching its decision.”