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February 23, 2025

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NY PSC OKs Partial Implementation Plan on Energy Storage

New York’s Public Service Commission has approved an implementation plan to push for installation of 200 MW of residential energy storage and 1,500 MW of retail storage (18-E-0130).

These will make up part of the state’s 2030 goal of 6 GW of storage, which is equal to about 20% of the state’s present-day peak load. The remaining 4,300 MW is to come from bulk storage; the PSC continues to review the proposed bulk implementation plan.

The state has a way to go. As of April 2024, there was only about 400 MW of storage operational in New York. Nearly 600 MW was under contract but not yet online, and 300 MW was procured but not under contract. Construction of wind and utility-scale solar also is progressing slowly in New York.

Gov. Kathy Hochul (D) in January 2022 doubled the state’s 2030 storage target from 3 GW to 6 GW. The PSC approved the roadmap for reaching 6 GW in June 2024; the implementation plans will guide procurement efforts and set the stage for financial incentives to be allocated. (See NY Sets Strategy to Reach 6 GW of Energy Storage.)

The implementation plans are living documents, however.

They were prepared by the New York State Energy Research and Development Authority based on the June 2024 roadmap. In its approval Feb. 13, the PSC directed NYSERDA to make some modifications based on stakeholder feedback. Continued refinement may be necessary, the PSC noted, due to changes in market conditions, technology or other factors specific to retail and residential storage.

Fire safety is among those moving targets.

Battery energy storage system (BESS) fires are rare, but those that do occur have been very well publicized, with a noticeable effect on public opinion. This can become a significant hurdle to BESS development in a home-rule state like New York, where local governments have the ability to pause or block development of some energy infrastructure development.

After three unrelated BESS fires in rapid succession in 2023, New York state put together a task force that issued a series of recommendations to limit the likelihood of BESS fires. (See NY Fire Code Updates Recommended for BESS Facilities.) Those recommendations have been forwarded for consideration in the 2025 update of the New York State Uniform Fire Prevention and Building Code.

The PSC wrote in the order: “The commission directs NYSERDA to implement new fire safety requirements as necessary based on updates to the building code for fire safety, regarding energy storage systems.”

A significant buildout of energy storage is necessary if the state is to increase its reliance on intermittent renewables and decrease its use of fossil-fired energy generation, as it hopes.

PSC Chair Rory Christian noted this in a Feb. 13 news release, saying: “Energy storage is crucial as New York works to decarbonize our electric grid, manage increased energy loads, and optimize the integration and use of clean, renewable energy. Today’s decision moves forward our landmark energy storage program.”

The cost to ratepayers is unknown, again because of unknowable future energy market fluctuations.

An analysis performed as the roadmap was prepared in 2024 estimated the cost of subsidies for the 6 GW buildout at $1.3 billion to $2 billion; $200 million already had been allocated as of April 2024.

The analysis further estimated that $2 billion worth of grid upgrades could be avoided if 6 GW of storage capacity were online, and that additional benefits would accrue to society through such things as cleaner air and reduced health care costs.

New York claims its storage goal is the nation’s most ambitious, but that distinction is diminished by the fact that California and Texas already are far beyond the 6 GW the Empire State hopes to achieve by 2030. S&P Global reports that as of the second quarter of 2024, California had 10.3 GW online and Texas had 7.7 GW.

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Brevity Should be Key for Pathways ‘Step 2’ Bill, Supporters Say

The deadline to submit bills for California’s 2025 session is looming, and backers of the West-Wide Governance Pathways Initiative expect legislation without unnecessary fluff that will change CAISO’s governance structure and allow a new regional organization (RO) to oversee the ISO’s Western energy markets.

California backers of the Pathways Initiative’s Step 2 plan have until Feb. 21 to submit a bill for the state legislature’s 2025 session. Under Step 2, which requires statutory changes, Pathways would create a new independent RO to govern rules for CAISO’s Western Energy Imbalance Market and Extended Day-Ahead Market (EDAM).

The Western Energy Markets (WEM) Governing Body and ISO Board of Governors approved Step 1 in August, elevating the Governing Body’s authority over CAISO energy markets. (See CAISO, WEM Boards Approve Pathways ‘Step 1’ Plan.)

The anticipated Step 2 legislation comes as entities weigh whether to join SPP’s Markets+ or EDAM. The two markets have yet to go online, but both are competing for participants.

EDAM’s governance structure has been a concern for stakeholders uncomfortable with markets led by CAISO, whose Board of Governors members are appointed by the California governor. (See Pathways Step 2 Not Good Enough, Markets+ Backers Say.)

Pathways Launch Committee member Brian Turner, director of Advanced Energy United’s regulatory engagement in the West, expects the Step 2 legislation to address those concerns by preserving states’ policy authority. (See Pathways ‘Step 2’ Plan Elicits Praise, Concerns — and Advice.)

“California’s clean energy policies, greenhouse gas goals, etc., are preserved and not imposed on other states,” Turner told RTO Insider. “Other states can make their own decisions and have them be respected under the governance framework that we outlined.”

Turner added that states participating in EDAM are “not being asked to give up any of its authority or autonomy on its resource and clean energy policy and other public policy goals.”

Ben Otto, energy consultant with NW Energy Coalition, shared Turner’s sentiment, saying that a key innovation of the Pathways proposal “is that moving forward with regional governance for EDAM does not depend on California legislation. Rather, the legislation will enable California entities to participate in the regional market and CAISO to contract as an operator.”

Otto said he expects the bill to be short and enable CAISO to participate in a regional day-ahead market under certain conditions.

“The conditions match the governance structures, public interest protections, and other elements of the Pathways Initiative proposal,” Otto said.

Jan Smutny-Jones, CEO of the Independent Energy Producers Association (IEP) and former board chair at CAISO, similarly said he expects “the legislation to be short and to the point.”

“I expect some language on protecting the public interests and respect for the energy polices of the various states. Hard stop,” Smutny-Jones said. “This is not a new energy policy, but a bill authorizing how the Western transmission system can be more efficiently operated to the benefit of California and Western ratepayers.”

A potential hurdle in the process could be if stakeholders add unrelated energy policies to the bill, said Sara Fitzsimon, policy director at IEP.

“This bill needs to only focus on authorizing the CAISO’s participation in an independent RO. Any other language outside achieving that goal should not be included, as it could cause delays in getting this critical language through the legislature,” Fitzsimon said.

The anticipated bill also comes as California grapples with wildfires and affordability issues, which could potentially cause delays, according to Leah Rubin Shen, managing director of Advanced Energy United’s legislative, political and regulatory engagement in the West.

Though the bill should only enable Step 2, Rubin Shen hopes the conversation around markets doesn’t end with the bill but rather spurs parties in the West to continue to discuss how to “evolve beyond a day-ahead market” by, for example, building an RTO.

“So, to the extent that this is a step forward, we are hopeful that it is a step that is good in its own right, and also a step that maybe has further steps down the road,” Rubin Shen said.

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ERCOT’s Revised CDR Report Met with Doubts

After a two-month delay, ERCOT on Feb. 13 released its semiannual Capacity, Demand and Reserves report, which provides potential future planning reserve margins five years into the future during the high-demand periods of the winter and summer seasons. 

According to the report’s most dire scenarios, the Texas grid operator may not have enough power to meet that peak demand during next year’s summer. However, ERCOT said in a statement that the CDR report is a “snapshot of potential supply resource availability and demand” and is not intended to represent expected real-time operations scenarios. 

The report was delayed so that revisions to its parameters could be made to “better represent the performance of grid resources and the dynamic nature of the ERCOT grid,” the grid operator said. 

ERCOT CEO Pablo Vegas appeared before the Texas Public Utility Commission to roll out the report. He told the commissioners that the state’s “fast-growing” environment, with large loads able to quickly connect to the grid before the infrastructure is ready, has placed “downward pressure on planning reserves.” 

“We see that trend continuing in this CDR as well,” Vegas said. “Some of the changes that we’ve made have accelerated or changed the view of those planning reserve margins shrinking, but … the overall trend of a rapidly growing economy, rapidly growing demand as a result of that … the energy economy is working to keep up with that.” 

The CDR projects PRMs, currently 18.9% for peak load and 10.5% for net peak load (when solar generation drops during the early evening hours when loads are still high), will fall to 8.3% and 21%, respectively, during summer 2027. The 2027/28 winter PRMs also drop into negative territory. 

ERCOT last year projected demand would reach 150 GW by 2030, fueled by data centers, industrial and petroleum production facilities, and cryptocurrency miners. The CDR projects demand to peak at 140 GW in 2029. The grid operator’s current peak is 85.5 GW, set in August 2023. 

“It’s important to note that all scenarios in this report have a certain level of uncertainty that can alter the long-term resource adequacy outcomes, and these forecasts will change over time based on a variety of factors,” ERCOT said in releasing the report. 

Skepticism

The release was met with skepticism by several industry insiders. 

Stoic Energy’s founder, Doug Lewin, jumped on a comment made by Vegas to the PUC that the CDR “doesn’t model what the market would typically do.” 

“Exactly,” Lewin said as he moderated a discussion on his Substack feed. “I think this report is largely worthless. Might be worse than worthless because people panic for no good reason.” 

Pointing to an ERCOT slide with PRMs between 32.4 and 21%, Lewin said it “looks scary, but it’s in no way reflective of the reality of the market. So, what’s the point?” 

The “Texas CDR report is far less important fundamentally than in the past years and is more a political signal in 2025,” Julien Dumoulin-Smith, a financial analyst with investment banking and capital markets firm Jefferies, said in an email to his audience.

“The optics of … -2 to -33% reserve margins likely leads to a political response,” he said, saying those optics likely will lead to efforts to subsidize generation and potentially less support for data centers. 

Dumoulin-Smith said that draft legislation (Senate Bill 6) could be “adverse” for power companies. The bill would require a “minimum transmission fee” based on large users’ peak load; require disclosure of backup generation; require PUC approval for any data center to buy existing thermal generation’s output; and establish a new ancillary service similar to ERCOT’s current emergency response service to “competitively procure demand reductions from large load customers” with 24-hour notice. 

The changes to the CDR include new load forecasts, as directed by House Bill 5066, that come directly from transmission and distribution utilities’ projections of new loads. Previously, ERCOT staff only counted loads with signed connection agreements. 

It now will use effective load-carrying capabilities (ELCCs) to measure renewable resources’ and battery storage’s reliability contributions. The ELCC metric is used in most capacity markets, but ERCOT operates an energy-only construct. 

The CDR also will illustrate both peak and peak net reserve margins and include demand-side resources such as demand response programs. ERCOT said the potential 9.72 GW of thermal generation in the Texas Energy Fund (TEF) did not meet the rules for inclusion in the base CDR scenario. It said additional scenarios did include the full TEF generation portfolio’s potential effect on reserve margins. 

“The new parameters and scenarios in the CDR better represent the performance of grid resources and the dynamic nature of the ERCOT grid,” ERCOT said. 

“The methodology changed significantly and … is extremely suspect. ELCC is a massively flawed metric,” Lewin said, noting “centrally planned, administratively determined capacity values” are necessary in capacity markets, but not in an energy-only market. 

“That’s part of the point of an energy-only market. Markets are far better at determining which resources can meet demand,” Lewin said. “Very hard to get good enough data to determine these things administratively. You’ll always be behind.” 

The CDR, originally released at 9:33 a.m. Feb. 13 in a market notice, was revised twice to reflect corrections to formulas in the “load-resource scenarios” tab that affected TEF scenarios. 

Dumoulin-Smith said “significant math errors” overstated projected supply in 2029 by about 28 GW, a “substantial delta” on an approximate 100-GW base. The initial report had one reserve margin of 22% that was corrected to 3.9% in the second report and uses a “stale” load forecast from summer 2024, he said. 

The analyst said he is “doubtful” many of the TEF projects will be completed without further support. Texas Lt. Gov. Dan Patrick (R), as president of the state Senate, has said he might seek $5 billion in state funds as incentives to build more natural gas power plants; the TEF’s In-ERCOT Generation Loan Program already has been allocated $5 billion for low-interest loans, but the current portfolio will require $5.34 billion in loaned funds. 

ERCOT says future economic growth will provide opportunities to improve PRMs. It says potential short-term solutions include expanding DR capabilities and broadening the firm-fuel supply service program. It also says it could further improve energy storage optimization and work with large loads on flexibility capabilities. 

“ERCOT looks forward to working on short- and long-term solutions with the Texas Legislature, PUC and stakeholders to continue to strengthen the reliability and resiliency of the Texas power grid,” CEO Vegas said. 

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Utilities Pushing for Return to Owning Generation in Pennsylvania

PPL is backing legislation this year that would let utilities in Pennsylvania own generation, which would unwind a key part of the state’s nearly 30-year experience with restructuring.

The utility holding company, which is based in Pennsylvania and owns utilities there, announced its support for utility-owned generation on an earnings call last summer after capacity prices in PJM spiked. (See PPL Backs Utility-owned Generation in Pa. After PJM Capacity Price Spike.)

“In Pennsylvania, specifically, we continue to advocate for a state-focused, no-regrets strategy that addresses impending energy shortfalls and provides the state with additional tools to help protect customers from price volatility and reliability concerns,” PPL CEO Vincent Sorgi said during the company’s year-end earnings call with analysts Feb. 13. “We believe one way to do this is to allow regulated electric utilities to invest in generation resources up to and including owning and operating generation again. This would complement the competitive market by addressing resource adequacy gaps, rather than relying solely on market forces to deliver a solution.”

Sorgi’s remarks came after The Standard-Journal published an op-ed by Christine Martin, president of PPL Electric Utilities, outlining the case for letting utilities back into the generation business without setting up a separate firm that operates generation using only market revenues.

That generated pushback from three former chairs of the Pennsylvania Public Utility Commission — James Cawley (D), Robert Powelson (R) and Glen Thomas (R) — in an op-ed published in The Scranton Times-Tribune, arguing utility-owned generation would gouge consumers. All three have long supported competitive markets, and Thomas is the president of PJM Power Providers, which represents independent power producers who would have to compete with rate-based generation if the change went through.

“PPL’s policy shift ignores the fortunate position that Pennsylvania now enjoys thanks to competitive markets,” the three wrote. “Pennsylvania currently has 70% more power than it needs to meet peak demand. This enviable surplus means Pennsylvania nearly always exports power to neighboring states with generation deficits, no matter how much demand fluctuates.”

But Pennsylvania is in PJM, and Cawley noted in an interview that other states in the RTO are falling short on building new generation. That has helped lead to higher prices in the entire market. Pennsylvania has better policies to encourage new generation than neighboring states like New Jersey and Maryland, he added.

“As we say in our op-ed, independent producers will take the risk, and they will meet that demand,” Cawley said.

Martin argued just the opposite in her piece.

“We cannot simply wait for the market to ‘fix’ the issue, especially when that same market is failing to bring new generation capacity online in a timely manner,” Martin wrote. “PJM is working on market reforms, and while these are steps in the right direction, they are unlikely to address the immediate crisis facing Pennsylvania and our region.”

On the earnings call, Sorgi said that the firm expected a bill to be introduced in the legislature this spring or summer that would allow for utilities to own generation. Other options include incentives for utilities to enter into power purchase agreements that go beyond the state’s default service auctions, or a “Baseload Energy Fund” that would be modeled on a program in Texas that paid for natural gas plants outside ERCOT’s market. (See PUC Shortlists 17 Projects for Loans from Texas Energy Fund.)

PPL is not the only utility that does business in Pennsylvania to endorse the idea of utility-owned generation. Exelon CEO Calvin Butler made comments during his own firm’s earnings call the same week endorsing the policy shift, saying the rapid load growth forecasted for the PJM region shows that “complementary” approaches to the market are needed to ensure adequate supply.

“It is clear that states are and should be proactively involved in supply solutions that complement the markets,” Butler said, “not to mention pursuing policies that enable more demand-side solutions. There is no single answer to meeting the levels of load growth that are anticipated. But instead, a variety of solutions across regulated and merchant participants is necessary.”

Cawley served on the PUC for two stints, in 1979-1985 and again in 2005-2015, so he has seen Pennsylvania as a regulated state and a competitive one. He said the change was for the best.

“When I first got into regulation, right after the Three Mile Island accident, there were all these nuclear power plants that were nearing completion, and then we had to decide how much of the cost would be allowed in the rate base,” Cawley said. “It’s an impossible test. Some construction project that’s been going on for 15 years with enormous cost overruns; that’s a game the utilities will win every time.” Utilities are masters at the accounting game; they know how to recover every cost, he added. But deregulation eliminated that. Competition ensures that customers do not bear the risk for massive cost overruns in generation construction, which was commonplace after Three Mile Island, he said.

Both PPL and Exelon used to be in the generation business, but both spun off their competitive firms, with Talen Energy and Constellation Energy as the results, respectively. Now the utilities are using scare tactics to get back into the generation business, but without the risks facing competitive generators, Cawley argued.

“It’s an effort to confuse people, to get legislators afraid that reliability is somehow going to suffer because there won’t be enough added generation,” Cawley said. “Well, that’s certainly nonsense. In Pennsylvania, we have been a net exporter of power for decades, and it’s going to stay that way, at least for another 10 years, even if nothing was built.”

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PJM MRC/MC Preview: Feb. 20, 2025

Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider. 

RTO Insider will cover the discussions and votes. See next week’s newsletter for a full report. 

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

B. Endorse proposed revisions to Manual 13: Emergency Operations to establish new wildfire procedures for the RTO and transmission owners to follow ahead of and during fire conditions that could impact

Issue Tracking: Wildfire Procedure

C. Endorse proposed revisions to Manual 40: Training and Certification Requirements drafted through the document’s periodic review.

Endorsements (9:10-10:10)

  1. Manual 14H: New Service Requests Cycle Process Revisions (9:10-9:30)

PJM’s Jonathan Thompson will review proposed revisions to Manual 14H detailing the site control requirements for projects in the interconnection queue. Voting on the changes has been deferred twice as some developers seek alternative language to revisions they argue would be overly onerous and require them to hold onto land unnecessary for the completion of their projects. PJM has countered that clear rules are needed that can be applied to all projects in the queue. (See “Stakeholders Endorse Quick-fix Revisions to Site Control Manual Requirements,” PJM PC/TEAC Briefs: Dec. 3, 2024.) 

Issue Tracking: Site Control Modification Clarification 

  1. DR Availability Window (9:30-10:10)

PJM’s Pat Bruno is set to review two proposed packages to revise the availability window for demand response (DR) resources and how they are modeled in the RTO’s effective load carrying capability (ELCC) analysis. The proposals would replace the window with modeling output in all hours, shift the winter peak load (WPL) of each resource to be measured at a set hour, and create an average load profile for DR participants to be used in the ELCC analysis. The two packages differ in which year they would apply to, with the main motion starting implementation in the 2027/28 delivery year and the alternate being effective one year earlier. (See “Expanded Demand Response Modeling Endorsed,” PJM MIC Briefs: Feb. 5, 2025.)  

Issue Tracking: DR Availability Window 

Members Committee

Endorsements (11:50-12:05)

  1. The MC will consider same-day endorsement of the proposed revisions to the DR availability window. Expedited consideration is being sought to allow PJM staff to begin making the changes for the 2026/27 delivery year if the alternative is endorsed by the MRC. 
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DOE Conditionally Approves Commonwealth LNG to Export

The Department of Energy has approved the first authorization to export liquid natural gas from a new domestic facility since the Biden administration’s pause on new approvals. 

“Today marks one of many steps that DOE will be taking to assure our future as a reliable energy supplier to the world and resume regular order to our regulatory responsibilities over natural gas exports,” Energy Secretary Chris Wright said Dec. 14. 

The Commonwealth LNG facility, which will be built in Cameron Parish, La., is owned by Kimmeridge Texas Gas and will be able to export 1.2 Bcfd once it is built. 

The project won approval from FERC in 2022, but the case was remanded to it by a federal appeals court. FERC is working on a new, supplemental environmental impact statement, and a final order is expected this summer. 

Then-President Joe Biden paused DOE’s approval of additional exports in January 2024 so the department could study their impacts. A court overturned the pause over the summer, and Biden’s DOE approved exports from a facility built in Mexico in August. (See DOE Approves 1st LNG Exports Since Biden Administration’s Pause.) 

The department released the study in late 2024; it said exporting more LNG would lead to higher domestic prices for the sake of shipping gas not to just allies, but China with its massive demand for energy. Since the report, China has put tariffs on U.S. LNG exports in response to President Donald Trump’s imposition of tariffs on it. (See DOE Warns About Further Increases of US LNG Exports.) 

“We expect China’s imposition of tariffs on U.S. LNG to have a limited effect on U.S. LNG exports,” the Energy Information Administration said in its Short-Term Energy Outlook (STEO) for February. “With ample demand for LNG globally, we expect that any LNG not purchased by China would be imported elsewhere.” 

In the conditional order approving the exports, DOE found they are likely to yield economic benefits to the U.S., diversify global LNG supplies, and improve energy security for U.S. allies. 

DOE has approved a total of 46.88 Bcfd in exports of LNG from the Lower 48 states, with 39 final orders and the conditional order for Commonwealth. DOE expects to issue a final order later in 2025. 

EIA expects LNG exports will record highs in 2025, averaging 15 Bcfd, but so will domestic production — hitting almost 105 Bcfd, it said in the STEO. 

The outlook also noted that the very cold January contributed to higher natural gas price forecasts this year, adding 65 cents to the EIA’s 2025 average price forecast, which hit $3.80/MMBtu. 

The Industrial Energy Consumers of America was the only group to protest the application on time, arguing that the additional exports would put upward pressure on domestic natural gas prices, making its members less competitive. 

DOE responded that based on forecasts for high domestic production, the additional exports conditionally approved Feb. 14 would not increase prices in the U.S.  

“With these decisions in hand, subject to a FERC final order, which we expect in July 2025, and DOE final authorization, Commonwealth anticipates reaching a final investment decision in September 2025, with first LNG production expected in Q1 2029,” said Commonwealth CEO Farhad Ahrabi. 

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Board Orders MISO to Get Answers on IMM’s Role in Tx Planning

Board members have directed MISO to seek guidance on the role of the Independent Market Monitor in transmission planning following a year of IMM David Patton criticizing MISO’s nearly $22 billion long-range transmission plan (LRTP) portfolio.  

MISO’s Markets Committee of the Board of Directors voted unanimously on the measure in a special, virtual meeting Feb. 14. The motion from the board instructs MISO’s legal department to reach out to FERC for its perspective on whether the IMM should be scrutinizing the RTO’s transmission planning. It also directs MISO to communicate to the IMM that it will not pay for work related to transmission planning “until further direction from FERC.”  

MISO confirmed it received the committee’s directions. In a statement to RTO Insider, it said it is “working to determine the next steps to effectuate the committee resolution.”  

MISO IMM David Patton was a vocal opponent of the second LRTP portfolio throughout 2024, repeatedly telling planners they were overstating the benefits of the collection of mostly 765-kV lines and deeming the 20-year future assumptions that transmission needs were established upon unrealistic. Patton argued for a downsized portfolio. (See MISO IMM Makes Closing Arguments Against $21.8B Long-range Tx Plan and $21.8B Long-range Tx Plan Goes to Membership Vote; MISO Resolute, IMM Protesting.) 

While many MISO members have said the IMM should not interfere in transmission planning and should concentrate solely on markets, Patton has said he believes planning is within his scope of work because of how planning and markets “interact with one another.” 

The board’s potential IMM funding freeze comes as MISO is gearing up to update the 20-year scenarios it uses as the basis for long-range planning. MISO has planned a first workshop with stakeholders on the futures Feb. 28. The grid operator plans to retool the futures for the remainder of the year and embark on another LRTP portfolio in 2026. (See MISO Pauses Long-range Tx Planning in 2025 to go Back to the Futures.) Patton is likely to disagree with the temporary stop work order, though he ultimately declined to comment on the Markets Committee’s motion.  

MISO Director H.B. “Trip” Doggett said board members and MISO made a portion of the Feb. 14 meeting public in an effort to be more transparent about the board’s activities and budget items related to the IMM.   

By the end of 2024, MISO’s IMM budget was about $236,000 over an approximate $8 million allotment. Doggett said board members analyzed the overrun extensively and found it ultimately was linked to rooting out demand response schemes in the markets and work dedicated to taming market-to-market congestion between MISO and SPP after a North Dakota data center taxed a transmission constraint.  

Doggett said the Monitor’s assessments of the LRTP did not contribute to the cost increase. The committee approved the IMM’s 2024 budget, including overage, in full.  

MISO directors agreed it was time for the board to attempt to clear up the IMM’s authority. Director Nancy Lange said it was appropriate to get “clarity on future work related to the LRTP.”   

“I think it’s an important step,” Director Robert Lurie agreed.  

Some MISO members said they were concerned about the optics of the board’s decision.  

WPPI Energy’s Steve Leovy said while it’s fine for the board to want clarification around the IMM’s role, the whole “situation has a bad look to it” because the Monitor disagreed with MISO’s planning assumptions and benefit calculations. Leovy said he wondered if the board would take such action if the IMM had backed the second LRTP portfolio.  

“This has a bit of an appearance of retaliation, in my opinion. … A bit of an attempt to stifle the discussion,” Leovy said.  

North Dakota Public Service Commissioner Jill Kringstad said her state appreciated the IMM’s independent voice during the planning process. WEC Energy Group’s Chris Plante, speaking as a representative of MISO’s transmission-dependent utilities, also said he found the IMM’s perspective helpful, especially as he questioned the RTO’s processes.  

Following the meeting, ITC’s Brian Drumm said the Markets Committee’s unanimous approval to confirm that the IMM’s scope of duties “do not extend to participation in MISO’s transmission expansion planning processes will provide important clarity for MISO and its stakeholders going forward.”  

Drumm pointed out that MISO has said before that it believes recommendations related to transmission planning are outside the scope of the Monitor’s duties. 

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Anti-nuclear Groups Challenge Palisades Reopening

Anti-nuclear groups have united in an attempt to stop Michigan’s Palisades Nuclear Generating Station from being brought back to life.  

The coalition — Beyond Nuclear, Don’t Waste Michigan, Michigan Safe Energy Future, Nuclear Energy Information Service of Chicago and Three Mile Island Alert of Pennsylvania — argued in front of a trio of administrative law judges from the Nuclear Regulatory Commission’s Atomic Safety and Licensing Board Panel that neither the NRC nor owner Holtec is putting enough thought into the restart of the plant.  

Holtec aims to bring Palisades back online in October. (See Holtec Confident on Late 2025 Restart of Palisades Nuclear Plant.)  

To revive Palisades, Holtec needs an exemption on the certifications granted as previous owner Entergy was shutting down the plant. The certifications prohibit operation of the reactor or placement of fuel into the reactor vessel. Additionally, Holtec needs four license amendments that will allow it to refuel the plant and restart operations. The quartet of amendments would alter technical specifications, revise an emergency plan to support the return of operations and update the methodology for studying potential consequences of a main steam line rupture.  

Beyond Nuclear and others entered a request for hearing in Holtec’s exemption and amendment requests (50-255). Oral argument pre-hearings were held virtually Feb. 12.  

Coalition attorney Wally Taylor said restarting a reactor in decommissioning status should require “more than just some paper shuffling, as Holtec and the NRC suggest.” 

Taylor argued that Holtec requires a new operating license, not a license adjustment to reopen Palisades.  

Taylor said Holtec and NRC “cobbled together a plan … to try to accomplish a restart” with licensing exemptions and adjustments because there is no regulatory pathway to restarting a closed and decommissioned nuclear reactor. He said Holtec and NRC’s “ad-hoc, patchwork” method to relicense a closed nuclear plant runs afoul of the Atomic Energy Act.  

According to the coalition, Holtec and the NRC are cherry-picking regulations that will ensure a restart while bypassing a new Updated Final Safety Analysis Report. The group said Holtec has admitted that “current regulations do not specify a particular mechanism for reauthorizing operation of a nuclear power plant after both certifications [regarding decommissioning] are submitted on the docket and before operating license expiration.” 

“Since there is no dedicated regulatory procedure for restarting a closed reactor, the NRC has no authority to approve the license amendments requested by Holtec,” the coalition argued in its October request for hearing.  

The group said Holtec currently holds an operating license that specifies that fuel is permanently removed from the core while no new fuel is introduced in the reactor. Absent a fresh license, the group argued that Palisades shouldn’t be allowed to produce electricity.  

The anti-nuclear groups also argue that the NRC is duty-bound to draw up a full environmental impact statement for a Palisades return pursuant to the National Environmental Policy Act. Taylor said NRC staff erred by not ordering one and Holtec erred by not submitting an environmental report.  

NRC staff issued a draft environmental assessment in mid-January that found no significant impacts; the regulatory body doesn’t plan to move to a more intensive environmental impact statement.  

Michael Spencer, attorney for NRC staff, argued the coalition’s petition is inadmissible because the arguments attack existing regulatory frameworks or are outside of the scope of the case.  

Spencer also said the case involves an already constructed plant that safely operated for decades when Entergy voluntarily shut it down before its 2031 license end date. He pointed out that Holtec is attempting to restore a license to a plant that has undergone previous safety and environmental reviews.  

Spencer said the case is “not a forum for broader” debates about a Palisades reopening. He said the groups did not limit their arguments to the procedure and attacked the plant’s restart.  

Stan Blanton, an attorney for Holtec, said the groups inappropriately challenge NRC’s authority to permit a nuclear plant restart. He said Holtec’s plan is to “simply restore Palisades to its pre-decommissioning status.”  

“There’s no question about what regulations need to be followed,” Blanton argued, adding that Palisades has an operating license in effect that is applicable to NRC’s restart authority.   

Blanton said Holtec maintains the restart would not cause a major environmental impact that would require a formal environmental report.  

Blanton agreed with an administrative law judge’s statement that Holtec’s license exemption request can be likened to an officer waving a motorist through a red light.  

But the anti-nuclear groups argued that “Holtec’s legerdemain, to force all of the safety oversight for Palisades through the tiny eyelet” of a code in the federal regulations, “runs into the laws of chemistry and physics.”  

The groups contended that Holtec’s current path to a Palisades resurrection is a violation of 10 CFR 50.59, titled “Changes, tests and experiments,” in the Code of Federal Regulations. They maintained that Holtec should have petitioned the NRC before undertaking significant work at the reactor.  

“Without proper layup and very suspect planning for the reopening of Palisades, this aged, degraded reactor almost inevitably will face unforeseen engineering and operational difficulties, hitherto unrecognized safety issues, and the cussedness that accompanies any obsolescent machine or vehicle,” the coalition warned in its hearing request.  

The anti-nuclear groups’ petition included expert testimony from Arnold Gundersen of Fairewinds Associates, who argued that after Entergy terminated the old Palisades operating license, a permit cannot be reissued to Holtec “without Palisades meeting the new, more stringent safety criteria of the 21st century.”  

Gundersen said since nuclear plants’ design basis assumptions are dramatically different than in the mid-1960s, the NRC must compel Holtec to revisit the plant’s assumptions. Gunderson said worsening climate change likely would create more frequent “unanticipated scenarios” outside of the design bounds. 

Gundersen also said he was concerned about damage from internal vibrations to the plant’s steam generator and Entergy disposing of “indispensable” quality assurance records. He said Holtec was moving at a reckless pace, borrowing a phrase from Union Admiral David Farragut as he commanded his fleet to enter Mobile Bay: “Damn the torpedoes. Full speed ahead.” 

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SPP Secures Funding to Begin Markets+ Phase 2

SPP said Feb. 14 it has received enough commitments to support the funding necessary for Markets+’s second developmental phase, the buildout of market systems that will begin in the second quarter of this year.

The grid operator said it has received signed Phase 2 funding agreements from eight interested participants in its proposed day-ahead service offering, including Arizona Public Service, Bonneville Power Administration, Chelan County (Wash.) Public Utility District (PUD), Grant County (Wash.) PUD, Powerex, Salt River Project, Tacoma Power and Tucson Electric Power.

Powerex, the marketing and trading arm of Vancouver, British Columbia-based BC Hydro, and Chelan PUD announced their Phase 2 funding commitments in January. (See Powerex Commits to Funding, Joining SPP’s Markets+ and Chelan PUD Commits to SPP Markets+ Phase 2 Funding.)

SPP noted in a statement that the entities operate a diverse mix of generating resources and serve more than 216,000,000 MWh in the Western Interconnection’s Desert Southwest, Pacific Northwest and Mountain West regions.

“The continued engagement and support of Markets+ by Western entities has certainly driven this day-ahead market one step closer to reality during this critical time for our industry,” SPP CEO Barbara Sugg said in the statement.

SPP said it will finance the projected $150 million in implementation costs, recovering them through the Markets+ operations. Staff said they have not distributed other funding agreements and do not yet have a full list of Phase 2 participants.

“There may be more coming,” SPP spokesperson Meghan Sever told RTO Insider.

The RTO said it will post exact financial commitments for Phase 2 funding on Feb. 17. Funding obligations will be based on the participants’ load share.

Powerex and BPA were the leading funders of Phase 1, meeting obligated 20.2% and 15.2% shares, respectively, for the phase’s $9.7 million in costs. Powerex was charged $1.96 million and BPA $1.47 million.

Public Service Co. of Colorado was the only other participant with a share above 10%, being charged 12.3% of Phase 1’s cost, about $1.19 million. PSCo has not yet returned to SPP a financial commitment agreement for the next phase.

Funding shares for all Phase 2 participants have increased due to the withdrawal of some entities from Markets+ development.

The grid operator gave interested Phase 2 financial backers a Feb. 14 deadline to submit executed funding agreements, a two-month extension from its original December target. It said the agreements are vital to meeting the Markets+ launch date of 2027.

FERC approved the Markets+ tariff on Jan. 16. (See SPP Markets+ Tariff Wins FERC Approval.)

BPA Looking at $26.6M Commitment

During Phase 2, stakeholders and SPP staff will work together to develop the systems needed to operate the market and conduct market trials and parallel operations.

BPA spokesperson Doug Johnson told RTO Insider the agency’s “initial commitment could be up to $26.6 million depending on the final number of Phase 2 funding participants.” The federal agency said it still plans a March release of its draft day-ahead market policy. It will issue a final decision in May.

BPA and SPP have differed over whether the Phase 2 funding is an actual commitment to join Markets+. In a December letter, a group of U.S. senators referenced an SPP statement that asserted, “[implementation] activities cannot begin until prospective market participants execute Phase 2 funding agreements, essentially committing to join Markets+.” (See BPA Has not Made ‘Business Case’ for Markets+, NW Senators Say.)

In response, BPA Administrator John Hairston rebuffed the assertion, saying “Phase 2 funding is not a commitment to joining Markets+; it is a commitment to continue funding development of the market.”

Hairston also noted that BPA will provide $25,000 toward the West-Wide Governance Pathways Initiative’s effort to bring independent governance to CAISO’s markets, SPP’s competitor in the West. (See In Letter to Senators, BPA Tempers Markets+ Leaning.)

SPP has maintained it simply wants to give Western entities a choice in markets. Its COO, Antoine Lucas, told RTO Insider during an October interview that the debate over day-ahead markets appears to be focused on pressuring entities into a market selection, “rather than work directly with those Western entities to truly understand what their issues and concerns are, and also work to try and accommodate them and address those issues so they want to choose to be within that market.” (See SPP Sees Bias in Brattle Western Market Studies, Exec Says.)

The RTO included comments in its news release from several Phase 2 participants who expressed their support of Markets+.

Chelan PUD’s Janet Jaspers said SPP’s market “offers consensus-driven, stakeholder-led governance” and an “equitable market design” that leverages the Western Resource Adequacy Program.

“We look forward to bringing the benefits of Markets+ participation to our customers and the western region,” Salt River Project’s Josh Robertson added.

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Tacoma Power to Join SPP’s Markets+

Tacoma Power has signed an agreement to join SPP’s Markets+, making the Washington utility the second Pacific Northwest entity to commit to participating in the market in the past month.

The Feb. 13 announcement comes as little surprise, given that Tacoma has been among the Western entities contributing to the series of “issue alerts” published since last summer favorably comparing Markets+ with CAISO’s Extended Day-Ahead Market. (See Pathways Step 2 Not Good Enough, Markets+ Backers Say.)

The municipal utility also has been counted among the majority of the Bonneville Power Administration’s base of publicly owned utility “preference” customers urging the federal power marketing administration to sign on to the SPP effort.

“A diverse group of electric utilities came together with a common goal: to build an energy market that will benefit our customers by optimizing how utilities in the West buy and sell electricity,” Chris Robinson, Tacoma Power’s general manager, said in a statement. “We’ve accomplished this with a durable and independent governance structure that will provide the right value for hydropower and will ensure the benefits continue flowing to our customers far into the future.”

Tacoma’s Public Utility Board approved the utility’s commitment to Markets+ last November, according to the statement.

“Tacoma Power will continue to participate in ongoing market development over the next two years. This will create the systems that will enable Markets+ to operate while Tacoma and other utilities complete the internal onboarding steps necessary to integrate market operations,” the utility said.

According to a spreadsheet posted to SPP’s website last October, Tacoma would be responsible for a 1.7% share of the funding for the Phase 2 implementation phase of Markets+, equating to more than $4.8 million.

Tacoma Power serves more than 180,000 electric customers in the city of Tacoma and nearby communities, as well providing power to the U.S. military’s Joint Base Lewis-McChord. The utility owns about 643 MW of hydroelectric generation, which account for more than 80% of its nearly carbon-free resource mix. It also operates 2,386 miles of transmission and distribution lines.

The utility’s announcement follows a similar one by Powerex, the largest Markets+ funder, which in January said it had committed to joining and paying its share of Phase 2 funding. (See Powerex Commits to Funding, Joining SPP’s Markets+.)

Last month, Chelan County Public Utility District, another publicly owned utility in Washington, committed to funding Phase 2 but said it still had not decided to join the market. (See Chelan PUD Commits to SPP Markets+ Phase 2 Funding.)