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December 26, 2025

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NRG Energy Seeks FERC Approval for LS Power Deal

NRG Energy told FERC that its purchase of generation and the CPower subsidiary from LS Power will not impact competition, despite some overlap in assets in New York and PJM. 

The deal announced in May would see NRG buying 13 GW of natural gas-fired power plants from LS along with the demand response aggregator for $12 billion. (See NRG to Buy 13 GW of Generation Capacity from LS Power.) 

NRG is paying for part of the deal with shares that are estimated to represent 11% of its shares at closing, which would exceed the 10% threshold for functional control in FERC’s merger reviews, the company said in the application filed with the commission June 12 (EC25-102). To avoid getting over that threshold, NRG will deliver only enough shares to LS Power’s shareholders to prevent them from owning 10% or more of NRG’s securities. 

The rest of the shares owed will be delivered to an independent trustee administering a voting trust, which is similar to a deal FERC accepted in 2019. The shareholders could direct the trustee’s vote only when or if the new NRG issues stock, liquidates the company, enters bankruptcy, agrees to a merger or a few other deals FERC previously has found are limited enough to render them “non-voting securities,” the application said. 

The deal will double NRG’s capacity, with most of LS Power’s gas generators being sold located in NYISO and PJM, but the application said standard market screens showed no significant increase in market power. 

“The transaction essentially flips the sizes of NRG and LS Power in both New York and PJM, with very little changes in market concentration,” said the market power analysis filed with the application. 

NRG currently owns 1,201 MW of capacity in NYISO and 2,081 MW in PJM, while LS Power has 1,947 MW and 11,552 MW, respectively, in the two markets. After the deal, NRG would have 2,163 MW in NYISO and 9,463 MW in PJM, while LS Power would have 985 MW and 4,170 MW in the two markets, respectively. 

NRG has only a few other assets in the two markets, including a tolling agreement expiring in 2029 for an 895-MW gas plant on Staten Island, and a contract for 175 MW of transmission capacity on the Linden VFT that can ship power between the two markets, which expires in 2028. It also holds 25% of the Bayonne Energy Center in an arrangement that ends in 2027. 

The analysis NRG conducted found the deal will not materially change market concentration in either the NYISO capacity market or the New York City submarket. The analysis found similar results for PJM and its submarkets. 

The transaction would have LS Power retaining control over 985 MW of the Ravenswood plant in New York City under a tolling agreement, with NRG controlling the rest. The Ravenswood deal will help eliminate any competitive impacts on the New York City submarket, the application said. 

In PJM, NRG will wind up with an additional 7,382 MW of additional capacity, but the dynamics of the deal makes the company’s Herfindahl-Hirschman Index score of market concentration actually fall slightly, according to the analysis. 

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Nuclear Conference Opens amid Momentous Times

The American Nuclear Society’s annual conference was well-timed in 2025, as the industry is riding a wave of optimism on a series of recent policy and market moves. 

Panelists in the opening discussions June 16 noted the stark differences today compared to several years ago, when U.S. nuclear plants were being shut down because they were uneconomical to run. 

Speakers also noted the cooperative effort that will be needed to turn this confluence of favorable factors into the increase in nuclear generation that so many of the 1,400-plus conference attendees hope to see. 

ANS Executive Director Craig Piercy summed it up in opening remarks: “We’ve gone from how do we wind down what we have to how fast can we get more? … The challenge now is moving from that intention to that implementation.” 

He cited indications that tax credits critical to making nuclear power economical will remain in place, and he cited President Trump’s May 23 executive orders intended to accelerate and expand development of nuclear generation, in part through streamlining oversight by the Nuclear Regulatory Commission. (See Trump Orders Nuclear Regulatory Acceleration, Streamlining.) 

If any further indication was needed that the 2025 conference came amid a time of momentous change, Trump provided it — firing NRC Commissioner Christopher Hanson, who was appointed by President Biden and formerly chaired the commission. 

Later June 16, ANS said in a news release: “A competent, effective and fully staffed U.S. Nuclear Regulatory Commission is essential to the rapid deployment of new reactors and advanced technologies. The arbitrary removal of commissioners without due cause creates regulatory uncertainty that threatens to delay America’s nuclear energy expansion.” 

Speaking that morning, Piercy cautioned about the wholesale slash-and-burn approach implied in Trump’s May 23 directive: “We all have to keep an open mind, but we have to get this right. A full reset of regulation at this stage will likely slow things to a crawl. It’s time we put away the meat cleaver and pull out the scalpel, because we need NRC on the road to recovery as soon as possible.” 

The largest U.S. commercial nuclear operator, Constellation Energy, was represented at the conference by Chief Generation Officer Bryan Hanson, who tempered the grandest aspirations for U.S. nuclear with some hard statistics: The United States built about 100 GW of civilian nuclear capacity roughly from 1965 to 1990, then little more than zero since then. Now President Trump wants to reach 400 GW between 2025 and 2050. 

“So the challenge is real,” he said. “The hearts and minds of all of you in the room today have to embrace and accept that challenge that says what they did from 1965 to 1990 was incredibly challenging.” 

What is not so challenging as it appears, Hanson said, is meeting the coming growth of load demand. “I think the forecasts are incredible at best,” he said. And he noted a recent Duke University study showing extensive U.S. grid capacity could be freed up with demand response. (See U.S. Grid Has Flexible ‘Headroom’ for Data Center Demand Growth.) 

NRC Commissioner Matthew Marzano noted this is not the first “nuclear renaissance” declared in recent memory: Construction of new reactors begun in Georgia (Plant Vogtle) in 2009 and South Carolina (V.C. Summer) in 2013 was heralded as such. But Vogtle took more than a decade and more than $30 billion to complete. The V.C. Summer expansion was abandoned after $9 billion was poured into it. 

“I don’t like to use the word, but there was the first ‘renaissance,’ and V.C. Summer was kind of the death knell of that when that project shut down,” he said. “But I think that this moment is different. There is a confluence of factors … that really makes a huge difference in terms of the future. And so we’re very excited. And of course, this administration has very ambitious goals.” 

Marzano said the ADVANCE Act of 2024 is a springboard toward those goals, making the NRC more efficient and effective. 

He spoke of a cultural shift under way within the NRC after the ADVANCE Act but called it a series of small steps that add up to a very big change — a different approach from the one Trump laid out in May. 

Marzano also asked for input on the process: “We won’t be able to see everything. So that’s where our licensees, our applicants, our stakeholders are going to be very important in helping NRC identify where its blind spots are.” 

Much more is on the agenda at the ANS conference as it continues through June 18, including the workforce development and technology evolution the nuclear power industry will need if it is to exploit the growth potential that stands before it now. But that growth set the tone for the introductory discussions. 

Kirsten Laurin-Kovitz, associate laboratory director for nuclear technologies and national security at Argonne National Laboratory, said: “Everything is aligning for nuclear energy, something we haven’t seen since the 1970s. But this isn’t just a comeback story. It is nuclear energy’s moment to truly energize the world.” 

GE Vernova Hitachi Nuclear Energy Chief Commercial Officer Nicole Holmes listed four factors critical to nuclear seizing the moment: 

    • Companies in the nuclear sector like to be the second to go, but somebody actually has to go first. 
    • The industry must dramatically improve its delivery model, and the government needs to offer support for early movers to have assurance of completion amid the risks. 
    • There need to be partnerships, ecosystems and an array of people supporting the vision. 
    • The United States needs to look beyond its own borders. 

The first small modular reactor in North America, for example, is a GE Vernova Hitachi BWRX-300 that Ontario Power Generation will operate near Toronto, and the reactor pressure vessel was made in Italy. 

“We need to cast a global vision,” Holmes said. “We’re not going to do this all in the United States.” 

One obvious example is the leadership that controls and guides this growth, she said, apparently adding one more yellow flag to those raised by other speakers referring to Trump’s changes. 

“Really, we need to continue to be in a leadership position on how we think about regulation and training programs,” she said. “The world is looking to the U.S. a bit to say, ‘How are we doing this?’ And I think not doing a wholesale changeover of what’s been working, just improving, that would be a smart idea for continued collaboration.” 

Constellation’s Hanson was asked when the nation’s largest nuclear operator might expand its fleet with a new build. 

After the spinoff from Exelon in 2022, he said, “New nuclear was nowhere on our strategy. I would say it’s starting to creep up into the strategy now, because that’s what our customers want.” 

But first, the company will concentrate on existing assets — restart of Unit 1 at the former Three Mile Island and uprates of operating reactors elsewhere. That will add 2 GW of capacity and cost $7 billion to $8 billion. 

“So our dance card is pretty full, when you think about it,” Hanson said. 

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Stakeholder Forum: Storms, Droughts, and Day-Ahead Markets; Now Hydropower’s Moment to Shine

hydro

Marshall Moutenot

Hydropower has been around for a long time. Over its long history, it has become a steady (if not sometimes forgotten) backdrop to the complicated balancing act of providing reliable national energy grids. Dependable, relatively predictable and dispatchable, hydropower now is stepping into a much more dynamic role in energy markets. 

U.S. power markets, in particular, are evolving rapidly. The increased penetration of wind and solar power means energy grids have to balance volatility, price cannibalization and variable resources that may cause imbalance in grid frequencies. And while this has driven battery storage in markets with high levels of wind and solar, such as ERCOT and CAISO, there still is a need for long-duration storage and dispatchable power. 

Increased weather volatility isn’t just grabbing headlines; it’s reshaping how we generate and trade electricity. To meet market needs and new policies like the extended day-ahead market (EDAM) in California, hydropower is taking center stage. Its reliable supply is crucial for dynamic, inter-market energy trading. 

Why Hydro, Why Now?

With the intermittency of wind and solar now a fundamental part of energy markets, and daily (even hourly — nay, even minute-by-minute) fluctuations common, energy traders need precise generation forecasts for dispatchable resources more than ever. Hydropower, with its storage and ability to quickly adjust output, is uniquely suited for this.  

The overlooked challenge in deploying hydropower, as modern energy grids now demand, is that traditional water forecasting methods haven’t kept pace with emerging climatic trends and variability. 

Conventional forecasts often miss short-term variability for a variety of reasons, including sudden snowmelt, basin-specific behaviors, or unexpected storm impacts. This leaves energy traders with uncertainty, putting resource allocation at risk, and driving (sometimes extreme) fluctuations in price as resources either fall short or overload the market. More precise inflow forecasting doesn’t just improve resource adequacy — it enables energy traders to capture value across volatile markets.  

Accurate short- and medium-term projections empower traders to position hydro assets strategically across day-ahead, real-time and ancillary service markets, so they can make timing decisions with higher confidence. Enhanced lead-time visibility enables bidding strategies that respond dynamically to shifting local marginal prices (LMPs), grid congestion and imbalance settlement penalties.    

By reducing forecast error, traders can better anticipate when to hold back water for peak pricing events or dispatch preemptively during surplus periods, improving P&L performance. Forecast granularity also supports more effective hedging, as predictable inflow reduces exposure to weather-driven volume risk. In intertie-heavy markets like CAISO, EDAM or SPP, forecasting upstream hydrology allows traders to arbitrage regional differences in supply-demand balance, particularly during snowmelt or storm-driven volatility. 

AI Forecasting: More Than Just Hype

While the challenge of adapting to a new model of energy trading won’t be solved overnight, the step change in artificial intelligence and machine learning, and their respective deployment into streamlining the energy transition for legacy energy grids, bring significant advantages in lessening the impact of intermittent energy resource and climatic volatility. 

The soon-to-launch Western EDAM will integrate Pacific Northwest hydropower more closely with California’s demanding markets. Accurate, real-time inflow forecasting is quickly shifting from being advantageous to becoming essential. 

Uncertainty at NOAA

NOAA’s public weather data is invaluable. Unfortunately, recent budget cuts introduce uncertainty about its long-term reliability and resilience, in spite of the heroic efforts by those who remain at the agency.  

Crucially, over the longer term, the private sector has the ability to consistently invest in research and development that will further enhance the latest AI forecasting technologies. While we believe a partnership between national forecasting and private solutions is most desirable, reduced funding for public forecasting may see the gap in accuracy between public and private forecasting increase. 

Hydro Steps up

Realizing hydropower’s full potential starts with accurately forecasting water, an essential first step for navigating the intricate constraints and optimization challenges it faces. Traders who embrace advanced forecasting tools will transform water into a strategic asset while generating enhanced returns. 

We’re moving beyond an era of simply spinning turbines. Hydropower is now positioned at the forefront of strategic energy trading, proactive market engagement and informed risk management in an increasingly volatile landscape. With enhanced forecasting capabilities, hydropower is confidently embracing this expanded role. 

Marshall Moutenot is CEO of Upstream Tech, a software company that provides services in the land and water management industries. 

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PJM MRC/MC Preview: June 18, 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 (8:30-8:35 a.m.)

B. Endorse proposed revisions to Manual 12: Balancing Operations drafted through the document’s periodic review, updating the operating mode change procedure and requiring the PJM master coordinator to be notified of any change in output for self-scheduled units when NERC tags cannot be processed. The changes also include conforming changes to PJM’s hybrid resource rules. (See “Manual Revisions Endorsed,” PJM Operating Committee Briefs: June 3, 2025.)

C. Endorse proposed revisions to the tariff, Reliability Assurance Agreement and Operating Agreement as endorsed by the Governing Document Enhancement and Clarification Subcommittee. The changes would remove obsolete references and terms, align cross-referenced language and codify the second phase of PJM’s hybrid resource rules.

Endorsements (8:40-9:30 a.m.)

2. Manual 14H: New Service Requests Cycle Process Revisions (8:40-9:05 a.m.)

PJM’s Jonathan Thompson will present proposed revisions to Manual 14H: New Service Requests Cycle Process to rework the RTO’s site control requirements in accordance with a settlement approved by FERC on June 10 (ER25-1544). (See PJM Presents Settlement on Site Control Requirements.)

Issue Tracking: Site Control Modification Clarification

3. Storage Integration (Phase II): Transmission Asset Utilization in Operations (9:05-9:30 a.m.)

PJM’s Dave Anders will present a problem statement and issue charge that would open a stakeholder process to consider establishing rules for deploying battery storage as a transmission asset (SATA). Constellation Energy’s Juliet Anderson will present an alternative issue charge, which differs on identifying the use-case for SATA, when the batteries would operate and identifying and mitigating market impacts. (See “Stakeholders Torn on Further SATA Education,” PJM MRC Briefs: May 21, 2025.)

Members Committee

Endorsements (4:40-5:30 p.m.)

5. CIFP — DOE 202(c) Cost Allocation (4:40-5:30 p.m.)

A. PJM and the Members Committee will review proposals to determine how the cost for Constellation to continue operating its Eddystone Generating Station under a Department of Energy emergency order will be allocated to consumers. Solutions may include a broad cost-allocation paradigm for any future emergency orders.

B. The committee will vote on whether to recommend each proposal to the Board of Managers, with results not shown on any package until full voting is complete.

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SPP Embraces Need for Speed to Meet Change Head-on

Evolutionary, not revolutionary. That’s long been one of SPP’s value propositions. Work with stakeholders to reach consensus, making sure things are done the right way and at the right time. 

No more. 

The “evolutionary, not revolutionary” language was removed from SPP’s five-year strategic plan, Aspire 2026. CEO Lanny Nickell alluded to the concept when he opened a June 13 education session for the grid operator’s state regulators by sharing details on things he characterized as “revolutionary.” 

“The industry is changing at a pace that I’ve not seen in my 33-year career,” Nickell told the Regional State Committee. “That’s not news. It’s what is behind our need to move faster.” 

That and recent executive orders from the administration to strengthen the grid’s reliability and security and to “protect American energy from state overreach,” Nickell said, have only amplified the pressure on the industry. (See Trump Seeks to Keep Coal Plants Open, Attacks State Climate Policies.) 

“We are feeling the pressure. I’m sure you all feel some pressure as well, even within your own states,” he told regulators. “And when the federal government says, ‘We desire to be an energy-dominant nation,’ those words create some risk for us. If we don’t figure out how to do that, if we don’t figure out how to move faster to help our utilities attract loads, they’ll go somewhere else. And if the federal government’s not excited about how that’s happening and they see the RTOs as being resistants and not lubricants, then that’s a risk to us and it’s a risk to our utilities.” 

Topping the list of SPP’s revolutionary items is how best to add large loads to the system, a task facing every RTO or ISO in the U.S. The board of directors in May directed the grid operator’s staff to present their proposal for interconnecting data centers and crypto miners during its August meeting. 

Nickell said he thinks staff can beat that deadline. The RTO has scheduled a virtual stakeholder engagement forum on July 1 to explain how it will facilitate the “timely and efficient integration” of large loads. 

SPP has scheduled another education forum July 15 in Little Rock, Ark., to gather feedback on a proposed demand response policy. It said a related tariff revision is being developed and soon will be available for stakeholder input. 

“We’re hoping to not upset the cost-allocation mechanisms that exist today,” Nickell said of the large-load proposal. “We think it makes sense for you all to understand how it can be incorporated within the current cost-allocation concepts because it may be that you all want to do something different, and we need to hear that. We need to know that.” 

More than 30 staffers are working on the effort to quickly add large loads, Nickell said. He said SPP has scouted how others in the industry are handling the problem, noting Southern Co.’s 90-day study process. 

“We need to be able to match or meet that, so that’s the goal,” he said. “The goal is to try to be the best and make sure that we’re helping our states and helping our utilities kind of be that service provider of choice. We’re feeling the heat to move faster.” 

To that end, SPP is working to streamline the cumbersome stakeholder process. Staff plan to bring suggestions for streamlining the process to the Corporate Governance Committee in August. 

“We’ll start socializing those there, and then, of course, we’ll see what we come up with,” Nickell said. 

He cited the recent approval of an expedited resource adequacy study (ERAS) as an example of quickly moving a tariff revision through the various working groups and committees. ERAS, designed to help load-responsible entities meet their resource adequacy requirements that are under pressure from large loads and SPP’s backlogged generator interconnection queue, was readied for a FERC filing in about nine months. (See SPP Board OKs 1-time Study for LREs’ Gen Needs.) 

“So that’s about as fast as we’ve ever done anything,” Nickell said.  

He said SPP faces the need to move “even faster” and to do so in a manner that results in successful FERC filings. Commission filings need to be supported by a majority of members, he said.  

“We have to make sure that we continue to offer a stakeholder process that allows people to provide their input and their voice,” Nickell said. 

He pointed to the demand response project as another example of the need for speed. Under its original plan, the project was scheduled to be completed in the first part of 2026. It now is being moved to the October-November series of governance meetings. 

At the same time, SPP has begun an awareness campaign for Surplus Plus, a suite of initiatives aligning with its corporate goals to accelerate the addition of new generation. The key initiative is priority processing, intended to add incremental capacity quickly at existing facilities, limited to shovel-ready projects. The grid operator says this will strengthen resource adequacy, expedite projects with limited impact, use existing infrastructure efficiently and reduce the impact to the GI queue. 

The RTO held a separate education session June 13 on Surplus Plus projects during the afternoon after Nickell’s comments to the RSC. Like ERAS, Surplus Plus was recommended by the Resource Energy and Adequacy Leadership Team, which has been working quietly in the background since 2023. 

The education sessions continue. The Markets and Operations Policy Committee is meeting virtually June 26 and again June 30 to consider a tariff change to improve the GI study process by introducing a more realistic validation step to reduce the “over-mitigation of group-wide transmission constraints.”

The expedited approval will allow SPP to conclude a 2023 study phase before the July MOPC meeting. 

Revolutionary, not evolutionary. 

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D.C. Circuit Rejects Kimball Wind’s Bid for Substation Reimbursement

The D.C. Circuit Court of Appeals denied Kimball Wind’s petition to overturn a FERC decision rejecting the wind developer’s bid for $5.9 million in reimbursement from the Western Area Power Administration (WAPA) for contributing to a substation expansion in Nebraska. 

Specifically, Kimball filed its petition for reimbursement under Section 211A of the Federal Power Act. But to succeed on its petition, Kimball must show its reimbursement request would result in an order for transmission services, which the company failed to do, according to the June 13 ruling. 

“The key question before us is whether Section 211A authorizes the commission to issue an order directing WAPA to reimburse Kimball Wind for its contribution to the substation expansion,” Circuit Court Judge J. Michelle Childs wrote for the three-judge panel. “We agree with the commission that Kimball Wind does not seek an order for transmission services — the only type of order the commission may issue under Section 211A.” 

In 2016, Kimball entered into an agreement with the Municipal Energy Agency of Nebraska (MEAN) to upgrade an existing wind generation facility. To begin delivering the electricity, Kimball was required to connect to WAPA’s transmission network, according to the opinion. 

WAPA conducted studies on how to transmit Kimball’s electricity output safely and recommended an expansion of the substation. WAPA estimated the expansion would cost $6.5 million and offered to pay $2.2 million. However, MEAN refused to pay the rest, the opinion stated. 

Kimball’s power purchasing agreement with MEAN required it to deliver energy before the substation was completed. Facing this deadline, Kimball paid approximately $5.9 million and then petitioned FERC for reimbursement, according to Kimball’s petition for review. 

Kimball sought an order requiring either a cash payment from WAPA or a three-party rate-crediting agreement among WAPA, MEAN and Kimball.  

However, FERC found Kimball did not seek an order for transmission services as required for relief under 211A and that Kimball was not WAPA’s transmission service customer, according to the opinion. 

In affirming FERC’s order, the court said requiring WAPA to reimburse Kimball for the costs associated with the substation expansion does not constitute an order “to provide transmission services,” but rather a request to recover construction costs. 

“Kimball Wind acknowledges that the only relief it seeks is ‘the refund of [its] construction costs,”’ Judge Childs wrote in the opinion. “It does not seek a transmission services agreement with WAPA, and it is not currently a party to such an agreement. An order directing WAPA to reimburse Kimball Wind with a cash refund would neither require that WAPA provide transmission services to Kimball Wind nor modify the terms on which WAPA provides transmission services to any other party.” 

Similarly, Kimball’s bid for a three-party rate crediting agreement does not lead to an order for transmission services, the panel wrote. 

“On Kimball Wind’s petition, neither an order for a cash refund nor an order for a three-party rate-credit agreement would ‘require an unregulated transmitting utility to provide transmission services,”’ Judge Childs wrote. “The commission, therefore, correctly concluded that Kimball Wind seeks relief that Section 211A cannot provide.” 

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ERCOT ESRs, Solar Production Lessen AS Costs

Energy storage resources and solar capacity helped reduce ancillary services costs and tight system conditions in the ERCOT market in 2024, Potomac Economics said in its recent State of the Market report for the ISO. 

Potomac, which serves as the grid operator’s Independent Market Monitor, said an “influx” of new supply contributed to fewer tight system conditions. Solar and ESRs added 7.5 GW and 5 GW of new capacity, respectively, it said. 

The IMM specifically pointed to ESRs as helping produce the supply increase that reduced costs. The IMM said normalized ancillary services expense dropped to $0.98/MWh of load from $3.74/MWh in 2023.  

ERCOT contingency reserve service’s (ECRS) average price fell to $9.62/MWh from $76.77/MWh but still contributed almost $1 billion in excess real-time market costs. The monitor said the use of ECRS created artificial scarcity conditions by withholding reserves from the real-time market until manually deployed during the seven months after it was implemented in 2023. It said that resulted in an excess cost of more than $12 billion, a claim ERCOT pushed back against. (See ERCOT Board of Directors Briefs: Dec. 19, 2023.) 

“The continuation of these ECRS deployment practices is a cause for concern,” the IMM said. “Most consumers are not directly exposed to these excess costs in the real-time market, but these pricing outcomes factor into future contracts offered by [electric retailers].” 

Average real-time prices, excluding adders, fell to $32/MWh, down about 52% despite a 14% decline in natural gas prices. The IMM said more than 75% of the sharp decline was a result of less frequent ECRS artificial shortages. 

Day-ahead prices averaged $31/MWh in 2024. 

The monitor said real-time co-optimization (RTC), scheduled to go online in December 2025, will improve the issues it raised over market performance and operational risk. A “critical aspect,” the IMM said, is that RTC’s logic will allow the market to go short on real-time operating reserves, with the shortage’s cost defined by set ancillary service demand curves (ASDCs). 

The IMM continues to recommend that the grid operator reconsider its policies for procuring and deploying ECRS.  

It also recommended: 

    • That the ASDCs be reformulated based on the marginal reliability value of each product and that ERCOT incorporate a stochastic (using a random probability distribution) risk methodology for setting target levels for operating reserves. The IMM said embedding this tradeoff in the real-time market-clearing logic will address many of the issues it identified with ECRS deployment. 
    • That policymakers move away from the four-coincident peak (4CP) method — which calculates each consumer’s 4CP transmission tariff rate for the following year based on their load ratio share during the previous summer’s highest systemwide demand 15-minute intervals — and implement a transmission cost-allocation framework that more accurately reflects cost causation. 
    • An uncertainty reserve product provided by resources that can start in two hours or less when reliability is threatened. 
    • A multi-interval, real-time market process that can look ahead and optimize across several intervals. 
    • That ERCOT prioritizes development of market solutions that ensure resource adequacy, given projected load growth and the development lag between price signals and new generators’ commercial operations date. 
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FERC Clarifies SEEM Ruling, Denies Rehearing

In a response to opponents of the Southeast Energy Exchange Market, FERC on June 13 clarified the legal standard it relied on in its March 14 order directing SEEM members to update the market agreement (ER21-1111).  

In doing so, the commission also dismissed the opponents’ alternative request for rehearing of the order, arguing it was moot given FERC’s clarification, and improper under the D.C. Circuit Court of Appeals’ 2020 ruling in Allegheny Defense Project v. FERC that rehearing requests could not be granted “for the limited purpose of further consideration.” 

The SEEM opponents, a group of 13 organizations including the Sierra Club and the Southern Alliance for Clean Energy filing jointly as the ad hoc Public Interest Organizations (PIOs), filed their request April 14, the same day SEEM’s members responded to the March 14 order. (See SEEM Opponents Urge FERC for Clarification.) FERC’s order mandated updates to the market agreement to clarify its territorial requirements and outline whether pseudo-ties could be used to satisfy them. 

The PIOs claimed one part of the order — in which FERC said SEEM’s open access transmission tariff is “consistent with or superior to the pro forma OATT” based on the commission’s comparability standard — was inconsistent with precedent.  

According to the PIOs, the comparability standard as first described in 1994 meant that an OATT “should offer third parties access on the same or comparable basis, and under the same or comparable terms and conditions, as the transmission provider’s uses of its system.” However, in the March 14 order, FERC said the standard “requires that comparable service be provided to comparable customers.”  

Because the phrase “comparable customers” never has been used in reference to the comparability standard, the PIOs argued the commission effectively invented a new definition to apply to SEEM. 

FERC denied it had redefined the standard but agreed it would be “appropriate” to clarify its reasoning. The commission said it was guided by Order 888’s articulation of the comparability standard, which said that “under a non-discriminatory open access tariff, a transmission provider must not only treat similarly situated customers similarly but also provide third parties with comparable service to what they provide themselves.” 

“To the extent that … the March 2025 order can be read otherwise, we clarify that these are the standards the commission applied in reviewing SEEM,” FERC said.  

The commission went on to “confirm that … SEEM affirmatively meets the comparability requirements because it offers comparable service to SEEM members … and participants, both of which must take service under the same terms and conditions.” 

FERC said the question before it in the proceeding was whether all “similarly situated entities” that wanted to participate in SEEM were treated similarly, and that the territorial requirements do not amount to dissimilar treatment because entities outside the SEEM territory “are not similarly situated” to those inside. 

Commissioners concluded the clarification of its language “does not impact the outcome of the March 2025 order,” which SEEM members addressed in their April 14 filing. (See SEEM Members File Market Agreement Update.) 

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NYISO Stakeholders Propose Capacity Retention Market

Central Hudson, Con Edison, National Grid and the Natural Resources Defense Council have co-submitted a proposal to the NYISO project prioritization process asking that the ISO consider developing a capacity market based around retaining existing resources.  

The project proposal says the market is intended to operate within a framework where generator entry to the New York market is driven by state government procurements. Various stakeholders have contended in prior working group meetings that the capacity market as currently designed ignores this and as a result no longer functions to incentivize new entry. (See NYISO Stakeholders Debate Purpose of Capacity Market.) 

“Given the dominant role of the state, we think it would be prudent to consider the merits of, and efficiencies that we might gain, by focusing the capacity market on the cost of retention today,” said Ekene Umeike, speaking on behalf of Con Edison. 

During his presentation, Umeike said the project would replace the elements of the capacity market structure review that are considering a bifurcated market. Such a market could implement price discrimination between new and old capacity.  

“The proposal recognizes that the implementation of a retention-only capacity market would require the development of separate mechanisms for market entry,” Umeike said. “While other capacity market programs have been proposed, in our view, none of them appear likely to address the fundamental concern of customers facing higher costs without a commensurate improvement in reliability.” 

Several stakeholders asked for clarification on the project and how it fits into the current project prioritization process. One stakeholder asked that Con Edison and the other co-sponsors of the proposal come to the ICAP working group to discuss elements of the project and its description before asking stakeholders to vote on it.  

Project Prioritization Continues

NYISO has included 48 “market projects” in the project prioritization process. Of those, 25 focus on changes to the energy market, 10 to the capacity market and seven to new resources. The remainder focus on planning and transmission congestion contracts markets.  

NYISO staff added several new projects to the pool of potential candidates for focus in 2026, including designing a market mechanism for bifurcated capacity markets and the net congestion rent assignment study proposed by the MMU. (See MMU, FTI Argue for Maintaining Uniform Pricing in NYISO Capacity Market and NYISO Monitor Proposes Changing Congestion Rent Assignments.) 

A list of project descriptions can be found here. Project costs and descriptions still are in draft form and will be finalized by June 30. After that, NYISO will distribute surveys to stakeholders for project scoring. These surveys are due July 15 and survey results will be discussed July 30. 

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MISO 2025 Transmission Planning Cycle Rises to $13B

MINNEAPOLIS — MISO’s 2025 Transmission Expansion Plan (MTEP 25) has amassed another $2 billion in investment since early spring, bringing its total to $13 billion.

MISO said the $13.1-billion, 444-project portfolio still is driven mainly by growing load. In spring, the RTO pinned the collection at 434 projects and $11 billion. (See Load Growth Drives Early MTEP 25 to $11B.) MTEP 25 is considered preliminary until late fall; MISO revealed the latest MTEP 25 tallies at a June 10 System Planning Committee meeting of the MISO Board of Directors.

This year’s MTEP is loaded with a record-high 37 expedited project requests valued at $4.36 billion.

Executive Director of Transmission Planning Laura Rauch said six of MTEP 25’s top 10 most expensive projects originated from expedited project requests. MISO’s top 10 projects account for 43% of MTEP 25 spending.

The grid operator said 76% of MTEP 25 projects are due to be in service within three years. MISO said MTEP 25’s project totals contain more than 1,900 miles in transmission lines.

Rauch said the traditional and expedited projects are set to serve about 8.7 GW in new load across the footprint.

During a June 2 East Subregional Planning meeting, MISO’s Scott Goodwin said requests for MISO to expedite MTEP processing of some transmission projects have “exponentially exploded” since 2022, when the RTO fielded only 16.

MISO hopes to pivot to a bimonthly processing approach for the growing number of transmission projects submitted by members for expedited treatment.

Going forward, MISO plans to open an every-other-month acceptance window for expedited project requests. It has said the new cadence should be less cumbersome on staff than MISO’s existing ad-hoc approach.

Currently, MISO evaluates requests as they’re received for transmission projects that cannot wait until end-of-the-year approval through the annual MTEP. MISO originally hoped to roll out a quarterly expedited process but was met with stakeholder resistance. (See MISO Starting from Scratch on New Schedule for Reviewing Expedited Tx Projects.)

MISO plans to study smaller expedited projects in batches while larger, complicated projects will get individual assessments. It said it hoped to debut a 30-day study turnaround for the more straightforward projects.

The grid operator also said it will schedule a single, monthly Technical Study Task Force meeting to discuss expedited projects instead of holding piecemeal, short task force meetings every time a request pops up.

Some stakeholders have asked MISO to consider a load interconnection queue like its generator interconnection queue because of the snowballing expedited requests.

MISO has experienced a runaway volume of expedited requests in recent years as load growth surges. While it used to process an average of six expedited requests annually, since 2021, it has experienced upward of 30 requests. The projects themselves are becoming larger and more complex.

MTEP 25’s expedited investment eclipses MTEP 24’s $896 million worth of expedited requests and MTEP 23’s $684 million.

MISO is set to hold a round of subregional planning meetings to review a more finalized MTEP 25 in September. MTEP 25 goes before the MISO Board of Directors for approval in early December.