The Arizona Corporation Commission has repealed the renewable energy standard for electric utilities in the state, saying it’s time for renewables to “stand on their own two feet.”
Commissioners voted 5-0 on March 4 to end the Renewable Energy Standard and Tariff (REST) rules that were adopted in 2006.
The rules required utilities to obtain a certain percentage of retail electric sales from renewable resources, starting at 1.25% in the first year and growing to 15% in 2025 and beyond.
REST required utilities to acquire part of their renewable energy from distributed resources such as rooftop solar. The distributed resource requirement grew from 5% in 2007 to 30% after 2011, with half of the amount coming from homes.
Utilities were directed to file tariffs to recover costs of their REST programs. Since the rules took effect, utilities have collected about $2.3 billion from customers for commission-approved REST programs, according to a draft order the commission approved.
All three utilities covered by the rules met or exceeded the 14% renewable standard in place for 2024: Arizona Public Service with 16%; Tucson Electric Power with 22.9%; and UniSource Energy Services with 14%.
Commissioners said although the REST rules helped spur the adoption of renewable energy in the state, they are no longer needed.
“It served its purpose. It’s time to move on,” Commissioner Rene Lopez said. “[Renewables] have to basically stand on their own two feet, like every other [power producer] has to.”
Commissioners noted that utilities now must conduct all-source requests for proposals (RFPs), a requirement that wasn’t in place when the REST rules were adopted. Through the RFPs, utilities choose the least-cost option that reliably meets resource needs.
“The idea that the utilities aren’t going to keep prioritizing affordable renewables … is absurd,” Commissioner Kevin Thompson said.
The REST rule repeal has been in the works since early 2024. In August, the commission directed staff to open a rulemaking docket and hold public comment sessions on the matter. (See Arizona Renewable Standard on the Chopping Block.)
Of about 130 written comments filed, most were opposed to the repeal. Another 363 commenters submitted a form letter supporting the repeal, the draft order said.
During the March 4 meeting, speakers asked the commission to strengthen or revitalize the REST rules rather than repeal them.
“Deleting the REST will send a harmful signal to the clean energy industry, discouraging investment, innovation and job creation in Arizona,” said Sandy Bahr, director of the Sierra Club Grand Canyon chapter.
Alex Routhier, a senior policy advisor at Western Resource Advocates, said REST benefits have included insulating ratepayers from fuel cost risk, lowering peak demand costs, reducing pollution and decreasing water needs.
“It is very likely that over the history of the REST rules, the benefits have far outweighed the costs,” Routhier said.
In comments after the meeting, Brian Turner, senior director with Advanced Energy United, said large-scale renewable energy is “thriving” in Arizona. But another goal of the REST rules was to give residents easier access to affordable, flexible energy, helping to reduce electric bills, he said.
“We look forward to working with the commission on developing new policies that help expand these opportunities, support competition in the market, strengthen energy independence, and put low-cost power within reach of hardworking families and businesses across the state,” Turner said in a statement.
Moving quickly to back New Jersey Gov. Mikie Sherrill’s call for a generation capacity increase, the Board of Public Utilities (BPU) approved the state’s first incentivized storage projects and launched new community and grid-scale solar solicitations.
The board voted 5-0 on March 4 to approve three transmission-scale storage projects with a combined capacity of 355 MW as part of the effort to install 2,000 MW of storage capacity by 2030. The projects were the first to emerge from the Garden State Energy Storage Program (GSESP), the state’s first storage incentive initiative.
Sherrill, who took office in January, has prioritized solar and storage capacity. She views it as the quickest way to help address the predicted shortfall in generating capacity, and the related price hikes that raised the average electricity bill by 20% in June 2025.
“This will create our fastest path forward to achieve energy reliability and affordability,” said BPU Commissioner Zenon Christodoulou, who described the state’s position as one of “urgency.”
He noted that when state officials initially conceived of the storage program, it was because of the urgency of climate change.
“That is still an important driving issue,” he said. “But the urgency of needing more electricity, particularly in this region, and having it built in the state of New Jersey is even more pressing right now.”
Affordability vs. Growth
The board also unanimously approved the opening of a second storage solicitation under the same program, authorizing the agency to procure 645 MW of transmission-scale storage, which is larger than 5 MW. Draft application instructions for the solicitation — which supports standalone projects or those connected to solar developments — will be released in April with a bid deadline Aug. 7 and final decision on bids planned for October.
In addition, the board approved three projects totaling 24 MW under the Competitive Solar Incentive (CSI) program, which provides incentives for grid scale projects. And the agency approved the opening of a new solicitation – the state’s fourth — under the program.
Finally, the board authorized the opening of a solicitation that would add up to 3,000 MW of community solar projects.
“States that invest in energy infrastructure today will have lower costs and greater reliability tomorrow — and New Jersey is going to lead the way,” Sherrill said in a statement, referring to the BPU actions. “By investing in battery storage, solar and grid modernization, we’re building an energy system that is ready for the future.”
Investing In the Future
Sherrill, a Democrat and former congresswoman, made the state’s energy difficulties a central element of her campaign and pledged to freeze rates as soon as she took office. On her first day, she signed two executive orders that called for a rapid acceleration of energy source development, especially solar and storage. (See New N.J. Governor Rapidly Confronts Electricity Crisis.)
PJM, which provides power to New Jersey and 12 other states, says dramatic price hikes that have impacted ratepayers in its zone are driven mainly by the sudden demands of data centers under development. At the same time, older, mainly fossil fueled generators have shut faster than new facilities have been built, the RTO says. But New Jersey and other states blame PJM for failing to anticipate the demand.
While the initiatives show Sherrill moving rapidly on her agenda, parts of the package had been in the works for awhile. Among them was the 3,000-MW expansion of the community solar program, which her predecessor Gov. Phil Murphy had enacted.
Eric Miller, New Jersey policy director at the Natural Resources Defense Council, called the BPU’s approvals “a critical step to getting more clean energy generation online as fast as possible.”
Capacity Cost Cuts
While New Jersey under Murphy aggressively expanded its solar and wind sector, the state has lagged in storage. The legislature set the 2,000-MW goal in 2018 but missed a target of 600 MW of storage in place by 2021, and the state’s storage capacity still is minimal. (See N.J. Launches Ambitious Energy Storage Incentive Program.)
BPU launched the GSESP in June. The first phase authorizes storage capacity of up 1,000 MW and will pay annual incentives for 15 years, with a second phase to follow. The board order says the agency will hold at least two more solicitations under the first phase.
The board received 11 applications in the first solicitation, and approved three, for a combined capacity of 355 MW. BPU staff said the incentives will cost $27.58 million per year for 15 years, or about $169 million in total once discounted, and will bring the state financial benefits in the long run. The agency estimated the storage projects will reduce capacity costs by $333 million to $420 million.
Storage offers a variety of benefits, of which capacity cost savings, or the money saved by not having to invest in such large generating plants because batteries can help meet peaks, is perhaps the most “significant financial benefit to ratepayers,” according to the board order. Other benefits include “peak shaving, energy arbitrage [and] deferring costly infrastructure upgrades,” the order says.
Assessing Incentive Benefits
Christodoulou, while supporting the storage approvals, expressed skepticism at the accuracy of benefit estimates, saying the savings are “not as conclusive, as the future will show. These are estimates.”
Still, he said, “the urgency of this moment requires us to take some leaps of faith.” He later urged agency officials to plan for future limits on incentives, specifically referring to those paid in the grid solar program.
“We always incentivize new and infant industries, which is critically important,” he said. But he added that “the industry should never be depending on long-term investment tax credits. They need to become like every other mature business in the world, and that is to stand on their own two feet, to gain or lose on their own merits. “
He urged the BPU staff to “accelerate that process to make sure that [project developers] find ways to gain managerial efficiencies, supply chain efficiencies [and] drive prices down.”
Balancing Incentives with Capacity Goals
The BPU for a while has sought to curb incentive payments, a task complicated by the removal over time of federal investment tax credits by the Trump administration.
In the CSI solicitation, the BPU rejected most of the bids because they were too high. Of 18 bids received, only two were eligible for BPU approval; the remainder exceeded the confidential maximum incentive agency staff had calculated was acceptable for the state to pay in the current market conditions.
The agency approved the third successful bid — a 10-MW project submitted by the North Jersey District Supply Commission — through a rule that allows the agency to waive the cap for projects whose bid is within 10% of the maximum. The project will be the largest floating solar generation facility in the state.
The board also voted to reduce the incentive for the community solar program as it opened a solicitation for an additional 3,000 MW of capacity, which Sherrill, like Murphy before her, had called for. The board reduced the incentive offered in the program from $80/MWh to $60/MWh.
“Staff believes that the recommended decrease balances the need to reduce costs for ratepayers with the statutory directive to achieve 3,000 MW of additional community solar registrations over the next four years,” the board order stated.
However, Sawyer Morgan, a BPU research scientist who outlined the plan outlined in the order, said the agency also expects to study the issue further in light of the federal tax credit loss by “soliciting stakeholder feedback and updated economic modeling based on market conditions.”
He added, however, that the process “potentially” could result in a future increase in the incentive.
American Electric Power has named Southwestern Public Service Co.’s Adrian Rodriguez president and COO of AEP Texas, the company announced in a news release.
Rodriguez will join the company March 30 and will report to AEP CEO Bill Fehrman, the company said March 6. He will replace Judith Talavera, who has left the organization, AEP said.
The Columbus, Ohio-based company said the move will align AEP Texas with the company’s strategy on long-term priorities, further strengthen operational performance and strengthen relationships with the state’s important stakeholders.
“As the business continues to evolve, we believe now is the right time to bring in a leader with deep experience in stakeholder engagement and a strong operational focus to align with our long-term priorities in Texas,” Fehrman said in a statement. “We see tremendous upside in AEP Texas and its ability to enable growth in the state through our industry-leading 765-kV transmission capabilities. We are confident this move will help take this operating company to the next level.”
Rodriguez joined SPS, an Xcel Energy subsidiary, in 2022 from Puget Sound Energy. He previously held senior positions with El Paso Electric Co. and has had various roles in private law practice, the federal court system, public policy and the Texas Legislature. He has a bachelor’s degree in economics and government from the University of Texas, a master’s degree in public policy from Harvard University’s Kennedy School of Government and a law degree from Columbia University.
Alex Ramirez, vice president of distribution operations for AEP Texas, will serve as interim president and COO until Rodriguez arrives.
U.S. Energy Secretary Chris Wright and the congressman whose district includes the shuttered Indian Point nuclear plant are calling for the restart of the facility.
But no specifics are being offered, and the site’s owner indicates significant financial and political support must be established before such a move could be considered.
The shutdown of the southern New York facility in 2020-2021 removed 2 GW of high-capacity factor generation from the grid in a region where reliability concerns have since come to fore. It followed a lengthy effort by many activists and state officials worried about the aging plant’s safety and its proximity to New York City.
The owner of the Indian Point Energy Center (IPEC) has said it could consider a proposal to restart two of the reactors. But it has made no public move toward any such attempt, and New York’s governor has not supported the concept.
Wright joined U.S. Rep. Mike Lawler (R) in Buchanan on March 6 to call for a rebuild and restart. Their comments focused on the reasons why Indian Point should be reopened, rather than what it might take to accomplish such a feat — five years, $10 billion and likely vast amounts of political cajoling or arm-twisting.
“Across the Northeast, including in New York, Americans are paying some of the highest electricity prices in the country because political leaders blocked critical infrastructure and prematurely shut down power plants that deliver affordable, abundant power,” Wright said in a news release.
“I’m calling for the rebuilding and reopening of Indian Point Energy Center and for an all-of-the-above energy strategy,” said Lawler, whose 17th congressional district may become one of the keys to control of the House of Representatives. “That means supporting nuclear energy, approving critical infrastructure like natural gas pipelines and ensuring communities like Buchanan are not left behind after decades of helping power our state.”
A contingent of opponents was on hand outside the plant during the news conference to argue that, no, it should not be restarted.
Entergy agreed in 2017 to shut down Indian Point in 2021 after a long tussle with activists and state officials. It sold the site to Holtec International, which commenced decommissioning.
Holtec caused a stir in September 2025 when it told POLITICO it was getting numerous inquiries about a restart, and said such an effort could cost $10 billion.
But terms of the closure agreement require that village, town, school, county and state leaders unanimously consent to any attempt at a restart.
Gov. Kathy Hochul (D) has indicated previously she opposes a restart.
Westchester County Executive Ken Jenkins (D) doubled down on that after the March 6 news conference:
“Absolutely not. Let me be clear — because apparently I was not clear enough for Congressman Lawler and the Trump administration: Restarting the Indian Point nuclear power plant is not welcome in Westchester County … Our communities fought long and hard to close this facility, and we are not going to reopen that debate now and not ever.”
In a statement released after the news conference, Holtec suggested someone else would have to front the money and build political support before it would consider a restart: “While it remains possible to re-power IPEC, we understand that the joint proposal requires the political will of a number of local political bodies; should the political will and financial means be available that the state wants to see a repower, we would be willing to work towards that goal; otherwise, we will continue on our path to safely decommission IPEC.”
Holtec is on the brink of pulling off the first-ever restart of a retired nuclear plant — the 800-MW Palisades plant in Michigan, another former Entergy asset that is even older than the two Indian Point reactors in question. Palisades had been targeted to resume operations in late 2025, but the project has run into delays.
Complicated Contemplation
IPEC sits on riverfront land once occupied by an amusement park that catered to daytrippers arriving by tour boat from New York City. Unit 1 was commissioned in 1962, Unit 2 in 1974 and Unit 3 in 1976.
With its proximity to a deep-blue metropolitan area of 20 million people — Times Square, the “Crossroads of the World,” is only 35 miles away — Indian Point was a particularly ripe target for anti-nuclear activists. One of Wright’s future Cabinet colleagues, Robert F. Kennedy Jr., helped whip up emotion in a 2004 documentary about security concerns in a post-9/11 landscape.
The state and activists mounted a long battle against the facility. Entergy — which had purchased the facility from Con Edison and the New York Power Authority — capitulated in 2017 but framed the closure agreement as an economic decision.
Indian Point, it said, was unable to compete with electricity generated with the cheap natural gas being fracked out of shale formations.
Unit 2 shut down in 2020 and Unit 3 in 2021. Unit 1, a 1950s design, had been retired in 1974.
Five years later, any discussion of a restart is complicated by politics and economics:
Lawler is seeking re-election in a battleground district that could help determine control of the House of Representatives; Democrats outnumber Republicans 7-5 among voters registered in the four counties in the district as of Feb. 20, though not every part of each county is included in the district.
New York’s four remaining commercial reactors, all operated by Constellation Energy, have a combined age of more than 200 years but remain a critical part of the power portfolio, providing 21% of the electricity generated in the state and running at a capacity factor above 90%.
New York in January extended a ratepayer-funded subsidy mechanism for those four reactors that has been running in the range of $500 million a year and could cost as much as $33.4 billion more through 2049. (See N.Y. Extends ZEC Nuclear Subsidies to 2049.)
New York’s efforts to develop renewable energy continue to fall short, and the four reactors provide more than 40% of the state’s carbon-free electricity. (See N.Y. Reports Minimal Increase in Renewable Power.)
Clean energy advocates are unhappy with Hochul’s steps back from the goals of the state climate law as she attempts to balance environmental and economic concerns in an election year; some Republicans are unhappy she has not moved back further from the climate law. (See NYSERDA Lays Out High Cost of Climate Law Compliance.)
Lawler is hedging his bets on an Indian Point restart — on March 4, he introduced legislation in the House to provide economic relief to communities impacted by nuclear plant closures. He noted that the Buchanan area has lost tax revenue and high-paying jobs with the closure of Indian Point.
The Bonneville Power Administration opened the selection process for the agency’s next administrator via an online job posting, prompting questions about the salary range and the level of input Northwestern lawmakers will have.
The Department of Energy posted the job opening March 2 on USAJobs.gov, a government website for federal job opportunities. The annual salary range is between $199,172 and $228,000 to lead the $4 billion agency responsible for roughly 70% of the Northwest’s high-voltage transmission.
Multiple sources in the Northwest have told RTO Insider DOE seems to be looking for a candidate from outside BPA, breaking from a pattern in which the past four administrators have been selected from the agency’s ranks.
Former BPA Administrator Randy Hardy said DOE appears to intend to launch a competitive process to find its next administrator, which Hardy contended is a step in the right direction.
But finding qualified candidates might prove difficult given the salary offered, Hardy told RTO Insider.
“Anybody with this degree of responsibility should make double or triple that,” Hardy said.
He noted that the salary is dictated by federal guidelines, which is a “big problem in terms of attracting … qualified candidates to run the agency.”
“You’re going to lose a lot of … candidates who would be interested and very competitive, and I don’t know who you’ll get at that lower kind of salary,” he added.
Historically, DOE has consulted with the Northwest congressional delegation to select the next administrator. Hardy said he assumes the agency will continue doing so.
Zabyn Towner, executive director of Northwest Requirements Utilities, likewise said he hopes lawmakers will get their say in who the next administrator should be to ensure the person understands the agency’s mission of serving small and rural customers.
The delegation historically has acted as an “informal board of directors for Bonneville and has had a say in … selecting the individual who serves as the next administrator,” Towner said. “And what we would like to see is that tradition continue.”
However, “I haven’t seen the level of engagement that I was hoping to see from the delegation so far,” Towner said. “It’s early in the process … I can’t comment on what might happen in the future, and hopefully we’ll see more engagement and direction from the delegation like we’ve seen in the past with previous selections.”
Meanwhile, Public Power Council sent a letter to DOE in February, urging the agency to select a candidate who can uphold the principles of BPA.
PPC’s Scott Simms told RTO Insider it appears the job posting included many of the “qualifications and expectations we would hope to see in the next administrator.”
“I think we can definitely see … some of those elements, for instance, upholding statutory obligations of BPA and, of course, statutory obligations for the country in general,” Simms said. He noted also the importance of ensuring the administrator is “looking out for the interests of a wide array of stakeholders, from utilities to interest groups and tribes.”
CAISO’s Western Energy Imbalance Market saw an increase in battery storage capacity and coal use in 2025 compared with 2024, although the total load across the market — which represents about 80% of the load in the West — did not increase over the year.
Battery capacity reached 25,600 MW by the end of 2025, up about 42% from the previous year, CAISO’s Department of Market Monitoring (DMM) said in memo at the joint CAISO Board of Governors and Western Energy Markets Governing Body meeting held March 4.
Most of that battery capacity exists in CAISO’s region — about 17,100 MW — with the rest of the WEIM containing about 8,500 MW.
During evening hours, batteries discharged about 2,500 MW more energy in 2025 than in 2024. This was due in part to a larger amount of solar generation on the system in 2025, which allowed the batteries to charge during the day and discharge at night, DMM said.
Coal-fired output in the WEIM increased by an average of about 800 MW during the hours between about 11 p.m. and 8 a.m. in 2025. In total, coal generated about 17,000 MW/hour in the WEIM over 2025.
The DMM specifically found that transfers out of the Intermountain West region increased during morning and evening non-solar hours in 2025 compared with 2024. This coincided with increased generation from coal resources in the region, DMM said.
Average total system load in the WEIM was the same in 2025 as in 2024 — about 78.3 GW. Load increased in the Pacific Northwest, Intermountain West and Desert Southwest regions but was down about 2% in California to 27.9 GW in 2025. Most of California’s decrease occurred during mid-day solar hours and evening peak net load hours, DMM said.
Although battery and coal usage increased in 2025, natural gas and hydropower resources continued to be WEIM’s primary resources, DMM said. Natural gas hourly generation averaged about 23,110 MW, down about 1,900 MW compared to 2024, while hydropower came in at 22,120 MW, an increase of about 920 MW in 2025.
Big Transmission Lines on Schedule
Three important transmission projects in the WEIM are progressing toward completion, CAISO CEO Elliot Mainzer said in a report at the joint board meeting.
The SunZia project, a 550-mile line across New Mexico and Arizona, began its commissioning and testing phase, Mainzer said. The line’s 3,650-MW capacity will deliver more than 3,000 MW of wind energy to the region.
The Southwest Intertie Project-North, a 285-mile line across Idaho, Nevada and California, is on track to open in June 2028, Mainzer said. Engineering and procurement are on schedule, with construction contracts signed and right-of-way requirements 99% secured.
The TransWest Express, a 732-mile line across Wyoming and nearby states, is on track to provide 3,000 MW of wind generation capacity by Q4 2031. Construction is currently happening at substations, transmission tower pads and access roads.
NERC has published a new incident review report to draw attention to the growing challenges to maintaining reliability during the “shoulder seasons” of spring and fall by highlighting multiple occasions of unplanned load shedding by two anonymous entities.
Spring and fall have been called “shoulder seasons” because they fall in between summer and winter, which are traditionally peak load periods in most regions, NERC wrote in the Load-Pocket Shoulder Season Challenges document, released March 4. Utilities tend to use these periods for planned maintenance and construction to prepare for the more demanding seasons ahead, taking advantage of the lower expected load levels to take generation and transmission facilities offline.
However, this historic approach has been complicated in recent years by changes in both the generation mix and load behavior. In many areas, once-comfortable reserve margins have shrunk to the point that grid operators must consider more carefully whether to grant equipment outage requests. NERC’s 2024-2025 Winter Reliability Assessment warned that retirements of coal- and natural gas-fired generation in multiple regions could lead to reliability challenges, which the ERO observed in the new report. (See NERC Sees ‘Reasons for Optimism’ as Winter Approaches.)
The report included four incidents of load shedding — two for each entity — out of six experienced across the ERO in shoulder seasons during an unspecified 13-month period. Each incident occurred in a load pocket — a smaller area of concentrated load within a balancing authority’s footprint that typically also contains some generation.
A load pocket will have “varying degrees of transmission lines that connect [it] to the larger grid,” through which energy must be imported to serve the load when the internal generation does not suffice. Depending on the size of the load, entities may create transmission “rings” around the pocket to provide more options for imports.
Multiple Factors in Load Shedding Incidents
The first two incidents were associated with the same entity, identified as “Entity A” in the report. Entity A reported three load-shedding incidents in 2024 and 2025, occurring in the same load pocket, of which the details for two were included in the report.
Each of Entity A’s incidents involved a combination of the following factors:
unavailable generation, either from planned or forced outages, low wind or solar generation output, or emission constraints;
differences between actual and forecast load, attributable in large part to line losses on the transmission system, resulting from increased power flow from reduced internal generation output; and
planned or forced transmission outages.
The first incident occurred in April — the year was unspecified — when a sustained fault on a 345-kV transmission line caused it to be taken out of service. A planned maintenance outage was already underway on another 345-kV line, leading to increased dependence on internal generation.
A wind facility with a nameplate capacity of 4.7 GW output only 100 MW because of low wind speeds, a separate generator failed to start and solar generation ramped down as expected at the end of the day, all as load increased to its daily peak value. With real-time contingency analysis results indicating imminent voltage instability, operators shed about 150 MW of load.
The second incident occurred in March, also in an unidentified year, when a significant unforecast reduction in wind generation led to increased transmission system flows and line losses. Multiple flexible and dispatchable generation resources were offline because of planned and unplanned outages, and a 345-kV line was out of service for maintenance as well. Operators shed 122 MW of load to return the system to stability.
Additional Incidents from 2 Entities
Two load shedding events were reported by the second entity. Both occurred in April 2025, but details were only provided for the one on April 26.
The report linked to a separate analysis by SPP that provided more details on the location of the event — northwest Louisiana — and the utility involved, American Electric Power.
On the day of the incident, about 3 GW of generation within the load pocket was unavailable because of planned maintenance outages. A 345-kV line and DC tie transmission line were also out of service, “significantly reducing the import capacity into the load pocket.” SPP ordered AEP to shed 140 MW of load, cutting power to about 30,000 customers for about six hours.
The last entity, identified in the report as Entity C, reported a single incident in May, when operators were forced to shed 600 MW of load. The load shedding was required because of planned and unplanned generation outages of about 7.6 GW — 74% of internal generation — combined with 1,732 MW of unavailable capacity on a 500-kV line. Temperatures within the pocket were also about 5 degrees Fahrenheit higher than expected, causing “a substantial increase in load.”
From the four incidents, NERC identified several considerations for entities during shoulder seasons. These include planning for a higher level of operating margin and committing additional generation in load pockets in case of variations in generation, load and weather; including demand-side management in mitigation plans for insufficient capacity; and periodically reviewing planned outages as the date approaches to determine whether conditions could warrant postponing them.
Two Arizona utilities received approval to convert coal-fired power plants to run on natural gas, projects they say will enhance grid reliability, reduce emissions and preserve jobs.
The Arizona Corporation Commission voted 5-0 on March 4 to approve an application from Tucson Electric Power to convert units 1 and 2 of Springerville Generating Station to natural gas. In a separate 5-0 vote, the commission approved Salt River Project’s application to convert two units to gas at the Coronado Generating Station. The applications sought modifications to certificates of environmental compatibility (CEC) for the facilities.
The Springerville and Coronado stations are about 30 miles apart in Apache County, Ariz.
Of the four coal-fired units at Springerville, TEP owns units 1 and 2, which have a combined capacity of about 800 MW. Unit 1 was slated for retirement in 2027, with Unit 2 to follow in 2032 “due to rising fuel costs, increasing delivery risks, anticipated mine closures, and environmental considerations and regulations,” TEP said previously.
Terry Nay, TEP’s vice president of energy resources, noted that the company did not propose repowering Springerville in its 2023 integrated resource plan (IRP) because “the prospect of a [gas] pipeline was not feasible.”
But since the IRP was filed, “we learned that a pipeline is feasible, making repowering Springerville the most economical choice for replacement gas generation,” Nay told the commission.
In August 2025, TEP and SRP were among Arizona utilities that announced commitment plans for Transwestern Pipeline’s Desert Southwest expansion project. The pipeline will transport natural gas from the Permian Basin in west Texas to Arizona. Construction is expected to be finished in late 2029.
Nay said gas conversion of the Springerville units would cost about $200 million. That would be less expensive than keeping the units running on coal at a cost of about $450 million, building a new combined cycle gas facility, or building new renewables with battery storage.
TEP expects to complete conversion of units 1 and 2 in 2030.
SRP expects the Coronado conversion to be finished in 2029. While the Coronado coal plant has provided baseload generation, SRP plans to use it as a peaking resource after the gas conversion.
“We think that converting to natural gas is a good long-term durable decision that will allow us to operate well into the 2040s, when other technologies will become available,” said Bill McClellan, SRP’s director of resource planning and development.
A new natural gas pipeline lateral is expected to serve Springerville and Coronado. An SRP spokesperson told RTO Insider that SRP has not finalized an agreement for the lateral to serve Coronado.
‘Economic Backbone’
Proponents cited multiple benefits of converting coal-fired units at Springerville and Coronado to gas fuel. The converted gas plants will emit fewer greenhouse gases and other pollutants. Many of the power plant workers will be able to keep their jobs.
“These plants are the economic backbone of our area,” said St. Johns Mayor Spence Udall, who works at the Coronado plant.
Representatives of the Sierra Club and Western Resource Advocates asked the commission to send the applications to the Arizona Power Plant and Transmission Line Siting Committee to better examine potential impacts and evaluate alternatives.
“Regulatory prudence points to the need for a new hearing for a CEC that has not been revisited since 1977,” said Alex Routhier, a senior policy adviser at WRA.
Meghan Grabel, an attorney representing TEP, said the commission is “fully authorized” to rule on the applications. She said going to the line-siting committee for an evidentiary hearing would cost ratepayers hundreds of thousands of dollars. The committee would be required to hold the hearing near Springerville.
“It’s logistically difficult, and it’s expensive,” she said.
Matt Derstine, an attorney representing SRP, said the commission has an evidentiary record in sworn declarations from the utility. The project is not a substantial change, he said, and it would provide a net environmental benefit.
Commission Support
Commission Chair Nick Myers said he saw “absolutely no reason to require another half a million dollars’ worth of studies and process just to do something that’s better than what’s currently happening.”
“This is a great opportunity for us to show the rest of the world what it’s like for government to just get out of the way,” Myers said.
Myers’ comments came before the Springerville vote, but he reiterated them before voting to approve the Coronado conversion.
Commissioner Kevin Thompson said the Coronado power plant supplies about 10% of SRP’s peak demand. The estimated cost to convert Coronado to gas and run it through 2045 would be $1.1 billion, he said, about $300 million less than replacing Coronado with a new natural gas plant for the same time frame.
“These plants are cornerstones of their local communities and, once converted to natural gas, will become a key pillar of long-term grid reliability versus being seasonally operated generating stations,” Thompson said in a statement after the meeting.
Of the remaining two units at Springerville, SRP owns Unit 4. The SRP board of directors in November approved the conversion of the unit to run on natural gas.
Springerville Unit 3 is owned by Tri-State Generation and Transmission Association. It is slated for retirement in 2031.
WASHINGTON — Electricity markets increasingly are in the political spotlight, and that includes attention from the biggest figure in politics over the past decade.
“I’m frequently reminded about how consistently the president talks about co-location,” White House National Energy Dominance Council’s (NEDC) Peter Lake said March 3. “He’ll mention co-location twice a week, which means I hear about it twice a day.”
Sometimes Lake will get a call from the West Wing on a day without any NEDC events because President Donald Trump brought up the concept at a speech on healthcare, Lake told the crowd at EPSA’s Competitive Power Summit. The president’s focus on co-locating generation with large loads shows how focused he is on meeting the data center demand driven by artificial intelligence, a technology he says the U.S. needs to dominate.
“Power is the big constraint on unleashing this generational technology,” Lake said. “And just like the combustion engine or the microprocessor, this is one of those technologies where America cannot afford not to be No. 1.”
With leading tech firms planning to spend hundreds of billions of dollars a year on data centers, AI has brought demand growth. Higher power prices, especially in PJM where the capacity market cleared short again, have attracted Trump’s attention. That led the White House and 13 governors of PJM states to jointly call for a backstop procurement auction to get more supply online for large load customers. (See White House and PJM Governors Call for Backstop Capacity Auction.)
“As a stakeholder group, we would ask you all, sincerely and enthusiastically, to please work with PJM to help reform the regular capacity market and the regular energy market,” Lake said. “The focus, rightly so, is a lot of time on the reliability backstop auction, but we very much intend for that to be one time only.”
Ideally, PJM will hold the backstop auction and two previously scheduled Base Residual Auctions in 2026, and then in 2027 the markets can get back to normal — where existing generation is maintained, new units are incentivized and prices are reasonable, he added.
“We can build enough power supply to meet the demand of AI and maintain affordability,” Lake said. “And this is where the president’s leadership has been truly extraordinary, in cutting the deal with the PJM governors to set up a framework in which we have a clear line of sight on how to build the new baseload and build big power in America again.”
The 13 governors represent PJM states across the political spectrum, but they agreed on the basic framework to address the issues the RTO faces, he added.
“My assumption when I took this job was that if the White House figures out what FERC is, you may not be in this role anymore, and [if] the White House knows what PJM is — oh my gosh, what happened?” FERC Commissioner David Rosner said earlier in the day. “And both are true, and we’re OK.”
The stakeholder process in PJM is messy and complicated. Hearing views from some new parties and the resulting political attention has been fine, Rosner said.
“I think that, at a high level, this is very positive, because it wasn’t so prescriptive,” Rosner said. “They didn’t know all the answers, but they brought people together on some concepts, and … we have to work with everybody in this room to make sure those concepts turn into steel in the ground.”
The only way rising demand can be met is if “the force of capitalism” is unleashed to meet it, which means getting the market design right.
“I know a lot of people like to talk about PJM as a problem, but my sort of opening statement is, PJM, as it currently exists, saves people billions of dollars,” Rosner said. “And we should work on the problems and make it better to meet the moment.”
Political attention on markets can lead to changes. Now that politicians are increasingly focused on affordability, that could lead to some knee-jerk reforms, said Wolfe Research Senior Analyst Steve Fleishman.
“Obviously, they do need to get elected, and they’re focused on that, but it does require a lot of us in the market seeing through a lot of noise, which is not easy,” he added. “It’s hard, hard for our investors, particularly the ones that aren’t in weeds on everything to assess.”
So far, much of the posturing on affordability has been more bark than bite, said Fleishman.
“Now we’re in the middle of everything, and AI and data center focus is the No. 1 thematic,” Fleishman said. “So, this is a real change for us, and I think it puts everybody at a higher level of alert.”
The demand comes at a time when the costs are growing; a new natural gas plant that recently cost $800 million to build now costs $2 billion, he added.
Affordability is a Concern Outside of ISO/RTOs
While PJM dominated the discussion at EPSA given its membership and the RTO’s recent attention from the White House, the entire country is dealing with affordability. NARUC President Anne Rendahl of the Washington Utilities and Transportation Commission said communication helps deal with the issue.
“We talk to the governor’s office,” Rendahl said. “We talk to the legislators. We have a good relationship and try to explain what we do and how we do it. But we need to do a better job with our utilities’ customers.”
Regulators need to explain that utilities not only have fair rates, she said, but rates that are enough to maintain a reliable system. “We can’t just cut the ROE [return on equity], cut the CEO pay — that’s not what we do,” Rendahl said.
If regulators can explain how they balance those sometimes-competing issues to lawmakers and consumers alike, that can help, she said. It also would help if utilities and the broader industry did the same, she added.
In North Carolina, Chris Ayers feels the same political pressure. Ayers is the public staff executive director of the utilities commission.
“I can tell you that I’ve taken more calls from legislators over the last six months than I have probably in the last several years combined in terms of why are rates going up, and are they going to continue to go up?” Ayers said. “What’s driving it, and why? You know, why can’t we do something about this?”
Most of North Carolina is served by Duke Energy with its own balancing authority, but part of the northeast is served by PJM member Dominion Energy.
How will the Market and Policymakers Respond?
Affordability has been a major issue in PJM, but the capacity market started reflecting the data center boom only about 18 months ago. Suppliers need more time to fully respond to that price signal, said Stacy Doré, Vistra Energy’s chief strategy and sustainability officer. Still, some 11 GW of new supply is at various stages of development.
“You do need to see sustained and durable price signals to do merchant generation,” Doré said. “And the minute that we had a high capacity clear, after years of having capacity clears of $30, the government put in price caps. So, I think we have to understand how the market was designed to work and let it work that way.”
While Doré pushed back on some of the most bullish forecasts for load growth due to data centers, the White House NEDC’s Senior Policy Adviser Nick Elliot said PJM has the most bullish case for data center growth in the world. And while, as his colleague Lake pointed out, the White House is focused on meeting that demand — affordability has taken center stage.
“I cannot understate how many times we get questions from the West Wing on affordability,” Elliot said. “It is the single biggest thing that’s flowing through the administration right now on power and on energy generally. I think that is universal. It is across blue states. It’s across red states. You know, it is a really big deal. I don’t think it’s going away.”
The hyperscalers have an “insatiable demand” for power, and Elliot said he was unsure where the new capacity to quench that would come from.
“Something has to give to fix the supply side,” Elliot said. “Otherwise, this is my impression, it’s going to become a re-regulated market, because universally, you got a whole bunch of Democratic governors and some Republican governors to sit down with Donald Trump to agree that we need to add more supply. If you want more of a signal that there’s unified political opinion — maybe that should be it.”
Van Welie: Keep Political Interventions Temporary
New England has comparatively anemic demand for data centers, but it has its own issues with reliability. Recently retired ISO-NE CEO Gordon van Welie said he thinks states need to reassert themselves in resource adequacy to ensure reliability going forward.
“I think that will drive lots of good behaviors,” van Welie said. “The market, I think, has worked really well to attract hundreds of billions of dollars’ worth of private investment. But if you look at what’s happened in recent years, there’s lots of frictions in the system that are impeding the ability of the market to respond.”
It makes sense for load to be responsible for resource adequacy, he said, and the states represent mass market customers (with restructured jurisdictions having large customers served by retail marketers).
“Whether you achieve that through bilateral arrangements, or setting up power authorities, or asking your utility to build stuff — in the end, accountability has to rest with the states,” van Welie said. “And I think then that drives positive behaviors around siting and permitting, because once you feel accountable, you’ll do something about it.”
While states need to take some ownership of resource adequacy, eliminating the markets and the “enormous” efficiencies they have unlocked through centralized dispatch would be foolish, he added.
“There’s an imperative to try to contain pricing — that is going to require a whole bunch of workarounds … outside of the market in order to get the result,” van Welie said. “And my point here would be, ‘OK, that’s what we’ve got to do for a while — let’s make sure that it’s temporary.’ And so, the thing that most heartened me earlier today was Peter Lake saying, this is temporary.”
Energy officials in Idaho, Utah and Wyoming have called on the West-Wide Governance Pathways Initiative to ensure that states with members in the Regional Organization for Western Energy have full access to data and market information, saying failure to do so risks infringing on states’ rights and undermining public confidence.
The Idaho Governor’s Office of Energy and Mineral Resources, Utah Office of Energy Development and Wyoming Energy Authority submitted joint comments on the ROWE’s draft bylaws in a Feb. 10 letter to the Pathways Initiative. The letter first appeared on the Western Interstate Energy Board’s website Feb. 23.
The ROWE is the product of the Pathways Initiative’s multiyear effort to develop an independent governance structure for CAISO’s Western Energy Imbalance Market and Extended Day-Ahead Market.
In their comments, the states contended the ROWE’s bylaws must ensure members have access to data and market information “to assist states in better understanding how the existing and evolving market design would impact state energy policies and economic priorities.”
Being able to analyze market data, independent of CAISO, which will still operate the markets, is “critical” for states’ ability to assess how efficient the market is and whether it is working in favor of their constituents, the letter said.
The states noted that some data “may be commercially sensitive,” saying the bylaws should “explicitly allow state entities to enter into confidentiality agreements to responsibly access and analyze this critical information.”
“Additionally, to strengthen oversight and build state-level expertise, we strongly encourage the allowance of third-party consultants to assist states in monitoring and interpreting market activities, provided they, too, are bound by confidentiality agreements,” the states wrote. “This access is critical given the seemingly unilateral ability of the board to determine confidential information and how it is accessed.”
Ensuring fair data access would improve market engagement while also ensuring that decisions within ROWE “reflect the diversity of state interests and the shared goals of transparency and reliability across the Western Interconnection,” the states argued.
“The commitment to data transparency and access should be explicitly stated in the bylaws,” according to the letter.
ROWE has been touted as an independent organization, run by stakeholders from a variety of sectors with the goal of ensuring states still have power to control their own energy policies.
But to ensure independence and build trust among stakeholders, ROWE must build a framework for “data access, evaluation and reporting that is fully independent of the market operator, the internal market monitor and other market experts,” Idaho, Utah and Wyoming wrote in their letter to Pathways.
This, they argued, “would promote confidence that market decisions are fair, unbiased, don’t infringe on state energy policy and are aligned with the public interest.”
It will be “extremely difficult” for states to set their own energy policies without stronger commitments in the bylaws. Under the existing structure, the ROWE board would control much of its own procedures with limited oversight and no “mandatory engagement or procedural consequences,” according to the letter.
“Without strengthened provisions, there is a serious risk that market design and governance principles will infringe on state energy policy priorities, erode transparency and undermine public trust,” according to the letter. “All western states, including our three states, have unique and widely varying policy priorities and economic development goals that must be protected. We emphasize the importance of ensuring that state energy policies are on equal footing, are fully respected and equitably treated in the Western Market operated by … [CAISO].”
Kathleen Staks, ROWE’s interim president, said in an email to RTO Insider that the organization appreciates the comments. (See Pathways’ ROWE Selects Interim Leaders.)
“As we have done with all of the comments we’ve received through the Pathways Initiative process, we are evaluating how we can address those comments through the ROWE implementation work,” Staks added.
