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December 18, 2025

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State Officials in the Northeast Discuss Interregional Transmission Plan

Officials from members of the Northeast States Collaborative on Interregional Transmission expounded on the group’s strategic action plan, released in April.

“There are certain basic truths that apply to transmission planning and development today,” Katie Dykes, commissioner of the Connecticut Department of Energy and Environmental Protection, said to an audience of 300 people during a teleconference April 29.

She said the collaborative’s nine states — Connecticut, Delaware, Maine, Maryland, Massachusetts, New Jersey, New York, Rhode Island and Vermont — saw a benefit to working together to ease the complications of transmission development as much as possible. “It’s imperative that we do so, and we’ve certainly made a lot of progress over the past two years.”

Dykes said numerous studies found that interregional transmission connections could help stabilize the grid and drive down energy costs. With tariffs and long-term supply chain uncertainties looming, it’s important that states work together to ease the barriers to interregional transmission development.

“To achieve this, we need to agree on common standards for transmission technologies so that investments across the system are compatible and consistent,” said Dykes, citing the example of an HVDC multi-terminal platform for offshore wind. “Such standardization could lead to more certainty in the supply chain and reduce costs for ratepayers.”

The plan, released by the Brattle Group, recommended the states work with the three grid operators in the Northeast to find interregional “low-hanging fruit” that could be developed. (See Plan Lays out Steps for State-led Interregional Transmission in Northeast.)

“PJM continues to support working with our neighbors on interregional planning,” PJM spokesperson Jeff Shields said in response to RTO Insider.

officials

Objectives for the Northeast States Collaborative on Interregional Transmission in the next year | The Brattle Group

“Transmission planning is an integral part of planning the future power system, as is working collaboratively with the New England states and neighboring regions,” ISO-NE spokesperson Randy Burlingame said. He cited ISO-NE’s Interregional Planning Stakeholder Advisory Committee and a recent request for proposals on interregional transmission. “We look forward to continued collaboration with the states and our counterparts to ensure a reliable grid today and in the future.” (See ISO-NE Releases Longer-term Transmission Planning RFP.)

NYISO declined to comment.

“No process currently exists for a group of states spanning different transmission planning regions to take the steps necessary to identify, evaluate and ultimately agree to share the cost of beneficial interregional transmission projects,” said Joe DeLosa III, a manager and consultant for Brattle.

He presented more specifics on the action items outlined by the plan. In the near term, these include working to standardize transmission technology to permit the delivery of 2,000 MW from offshore wind on 525-kV lines, harmonizing state regulations and procurements, and directing the grid operators to implement interregional planning principals in line with FERC Order 1920. They also include reevaluating the benefits that could be provided by the extant interregional connections.

Over the next few years, the states would expand their efforts via mid-term action items, including reevaluating whether tariffs need updating for interregional transmission and exploring the formation of a buying pool for transmission equipment.

A panel of state officials including John Bernecker, director of the Transmission Center of Excellence at the New York State Energy Research and Development Authority; Kira Lawrence, senior policy adviser for the New Jersey Board of Public Utilities; and Jason Marshall, deputy secretary and special counsel in the Massachusetts Executive Office of Energy and Environmental Affairs, addressed questions from the audience. The panel was moderated by Suzanne Glatz, a consultant and former director of interregional planning for PJM.

“One of the critical activities is breaking down silos that have existed within transmission planning, both across the regions but really, across the ways that the benefits of transmission have been assessed,” Bernecker said. He said transmission typically has been assessed for market efficiency, reliability or for public policy. “In reality, a given transmission project will have benefits across different areas.”

The panel was asked why the plan seemed to have a specific focus on offshore wind given the opposition from the Trump administration.

“While wind power is mentioned, that’s more from the perspective of specific technical barriers that need to be addressed in order to fully integrate those resources in the long term,” Bernecker said. “But that’s not the focus of the plan in its entirety.”

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State Attorneys General Sue Trump for Executive Order Halting Wind Approvals

A group of 18 Democratic state attorneys general filed suit May 5 against President Donald Trump’s executive order that halted wind energy projects’ federal approvals. 

The lawsuit, filed in the U.S. District Court for Massachusetts, seeks an injunction against the order so federal agencies can resume working on projects as the litigation is pending. The complainants include states that were banking on major offshore wind projects that have been interrupted, like New Jersey and New York, as well as many that were impacted by the order’s impact on onshore wind, such as California and New Mexico. 

“This administration is devastating one of our nation’s fastest-growing sources of clean, reliable and affordable energy,” New York Attorney General Letitia James said in a statement. “This arbitrary and unnecessary directive threatens the loss of thousands of good-paying jobs and billions in investments, and it is delaying our transition away from the fossil fuels that harm our health and our planet.” 

The order, which Trump issued on the first day of his new term, categorically halted all federal approvals needed for offshore and onshore wind energy, pending an “amorphous” and “extra-statutory” multiagency review of unknown duration. The order cited past, unspecified legal deficiencies and directed relevant federal agencies to stop issuing new or renewed approvals, rights of way, permits, leases or loans for onshore and offshore wind pending the review. (See Critics Slam Trump’s Freeze on New OSW Leases.) 

Agencies have implemented the executive order, with the Department of the Interior even issuing a stop-work order on Empire Wind 1 off New York, which had begun early construction activities. (See Feds Move to Halt Construction of Empire Wind 1.) 

The federal stoppage has harmed states’ efforts to secure reliable, diversified and affordable sources of energy to meet increasing demand, preventing the economic benefits associated with development and the environmental benefits of more clean energy. 

“The various actions taken by agency defendants to implement the wind directive are arbitrary and capricious under the Administrative Procedure Act,” the lawsuit says. “First, the wind directive was issued with no reasoned explanation for its categorical and indefinite halt of wind energy development. Second, neither the wind directive nor agency defendants have offered any detailed justification to explain the abrupt change in longstanding federal policy supporting the development of wind energy.” 

Numerous laws require federal agencies to consider and issue decisions on applications for wind energy projects, including the Outer Continental Shelf Lands Act, the Clean Water Act, the Clean Air Act, the National Environmental Policy Act and the Endangered Species Act. 

“Under these authorities, agency defendants must comprehensively, but promptly, review, approve, deny or otherwise act on applications to construct and operate wind energy facilities, following specific procedures and standards,” the lawsuit says. 

Previous presidential administrations, including Trump’s first, implemented those laws faithfully and often celebrated the growth in wind energy that resulted. In Trump’s first term, seven offshore wind lease auctions were conducted, multiple leases to offshore wind energy developers were issued, and the administration processed environmental reviews of many projects. 

Agencies already have looked into wind projects’ impact on fisheries, tourism and the environment and found their effects were at least acceptable for projects to move forward. Courts have reviewed some of those projects and come down on the side of the agencies. 

“The wind directive reverses the robust federal support for wind energy that had spanned decades and multiple administrations, does not account for agency defendants’ extensive past federal review of wind development, and conflicts with President Trump and agency defendants’ concurrent promotion of domestic energy production, both as a general matter and specifically in several of our states,” the lawsuit says. 

The order calls on the secretary of the Interior to run the review in consultation with secretaries of the Treasury, Agriculture, Commerce and Energy, and the EPA administrator. 

“Despite the extensive past reviews of wind energy projects by agency defendants — indeed, ignoring the existence of these reviews — the directive orders that the assessment consider anew ‘the environmental impact of onshore and offshore wind projects upon wildlife’ and the ‘economic costs associated with the intermittent generation of electricity,’” the complaint says. 

The directive was one of several Trump issued on his first day in office this January, which also included one addressing an “energy emergency.” (See Trump Will Need More than Executive Orders for US to Meet Rising Power Demand.) 

Other executive actions since then have emphasized the need for more energy, but the wind order goes against all of them, the lawsuit says. 

The order takes a low-cost, clean and abundant energy option off the table at a time when Americans need more affordable electricity, said Environmental Defense Fund Lead Counsel for U.S. Clean Energy Ted Kelly. 

“Instead of tapping into America’s vast wind resources and growing this industry, the administration is blocking energy progress,” Kelly said in a statement. “These attorneys general are right to challenge the Trump administration’s illegal attempts to obstruct wind energy.” 

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SPP Addresses 3rd Load Shed Since March 31

OMAHA, Neb. — SPP staff have told its state regulators and board members that it will do better after three local load sheds since March 31.

The outages affected a combined 54,000 customers in northwestern Louisiana and mostly oil and gas facilities in southeastern New Mexico.

“They’re concerning, and we are committed to analyzing what went wrong and what we need to do to get better,” SPP CEO Lanny Nickell said May 5 during the Regional State Committee’s quarterly meeting.

The most recent, and largest, load shed since Nickell became CEO came April 26 near Shreveport, La., in Southwestern Electric Power Co.’s (SWEPCO) service territory. SPP said it identified grid instability in the area and directed SWEPCO to immediately reduce its electricity use by 140 MW, resulting in a six-hour outage for about 30,000 residential customers in Caddo and Bossier Parish.

Bruce Rew, SPP’s senior vice president of operations, told the RSC and stakeholders that temperatures came in higher than forecasted, increasing load. With several generators and transmission lines out for planned maintenance, the grid operator didn’t have enough generation to respond to voltage instability in the area.

Coming as it did three weeks after a similar event, the outage generated numerous headlines in the region:

Foster Campbell, the outspoken Louisiana commissioner who serves northern Louisiana and once ripped SPP for its “Taj Mahal” of a headquarters building, held a press conference in his office April 29. (See Louisiana’s Campbell Expands Beef with SPP.)

Campbell called Nickell and SWEPCO President Brett Mattison and sat them alongside him, where they held court before the regional media for about an hour. One image from the press conference showed Nickell, his head bowed, listening to Campbell as the commissioner looked at the CEO and pointed to a document.

Nickell noted to the RSC that the event occurred during a pleasant spring afternoon.

“What I found is there’s never a good time to take an outage. There’s never a good time to interrupt service,” he said. “It’s important that we never take for granted what we do to keep the lights on.”

Campbell has asked SPP and SWEPCO staff to attend the Public Service Commission’s next meeting and discuss compensation for the outage’s damage. SPP has said it will have representatives at the meeting.

“Let’s see about how we can get together and how much money would be reasonable or fair,” Campbell said during the press conference. “We’re going to work this out and come up with a solution. We gotta figure out how you give these people their money back that lost its revenues while the power was down.”

The RTO has said it will work with SWEPCO to conduct a comprehensive analysis of the event to understand what happened and determine future actions.

“We will consider all possible solutions to issues that threaten real-time and long-term reliability across the region we serve,” SPP said in a statement.

The Shreveport area also went through an emergency outage April 2 after a dangerous storm system swept across the Midwest. More than 24,000 customers were without power for several hours. SWEPCO said it was required by SPP to implement “emergency grid protection outages” to prevent “potentially catastrophic damage” to the grid.

A SWEPCO representative told one of the regional media outlets that emergency outages like the April 2 event are “incredibly rare” and not something that happens regularly.

The third load shed took place March 31 in Southwestern Public Service Co.’s (SPS) eastern New Mexico service territory, which has dealt with slim generation margins recently, Rew said. Several generators were out of service for planned maintenance or forced outages, and when there was a steep drop in wind production during the early morning, the reliability coordinator ordered SPS to drop 122 MW of load.

The outage affected primarily large industrial consumers and lasted less than three hours before offline generation could be deployed.

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FERC Approves $110K Penalties in RF

Two entities managed by Cogentrix Energy will have to pay a collective $110,000 to ReliabilityFirst for violating NERC’s reliability standards, according to a settlement between the regional entity and the utilities approved by FERC (NP25-9). 

NERC filed the settlement with the commission in a notice of penalty March 31, along with a separate spreadsheet notice of penalty containing a settlement between SERC Reliability and Georgia Transmission (GTC), and another settlement between SERC and the Municipal Electric Authority of Georgia (MEAG), both for failing to maintain consistent facility ratings (NP25-10).  

FERC said in a filing April 30 that it would not further review any of the settlements, meaning the penalties for the RF violations will remain intact. Neither of the SERC settlements carried a monetary penalty. 

Communication Issues Between Cogentrix, PJM

RF’s filing involved two gas generating facilities: the 870-MW Hamilton Liberty station in Towanda, Pa., and the 773-MW Essential Power Rock Springs (EPRS) station in Rising Sun, Md. Liberty is registered with NERC as a generator owner and generator operator, while EPRS is registered as a GO, GOP and transmission owner. 

Liberty and EPRS were accused of infringing IRO-001-4 (Reliability coordination — responsibilities) and TOP-001-5 (Transmission operations), respectively. RF said both violations stemmed from “the same manager’s miscommunication [when] both entities were experiencing a phone outage,” and both were self-reported to the RE on Nov. 15, 2021.  

According to the NOP, on Sept. 16, 2021, Liberty was preparing to perform reactive testing for a 453.5-MW unit as required by MOD-025-2 (Verification and data reporting of generator real and reactive power capability and synchronous condenser reactive power capability). The test was approved by Liberty’s reliability coordinator, PJM, except for one portion.  

In its self-report, Liberty explained that Cogentrix’s Energy Management Group (EMG) “was experiencing a [voice-over-IP] phone outage that created additional confusion in the EMG to PJM communications” at the time, requiring the use of multiple cell phones that “were not utilized by PJM as intended by EMG.”  

PJM told the manager of the EMG that because of an ongoing transmission outage, the leading reactive test could not be performed at the maximum MW output. The RTO told the manager that “a lengthier stability study was required prior to performing that portion of the test.”  

However, the EMG told Liberty’s control room operator to start the test without passing along the information about PJM’s lack of approval for one portion. As a result, the operator conducted the test in full. This constituted a violation of IRO-001-4 requirement R2, which requires transmission operators, balancing authorities, distribution providers and GOPs to “comply with [their RCs’] operating instructions unless compliance … cannot be physically implemented or …such actions would violate safety, equipment, regulatory or statutory requirements.” 

Also on Sept. 16, 2021, PJM requested through the EMG that EPRS run Units 3 and 4 for economics. The EMG manager relayed this instruction to the EPRS lead operator, but the operator did not hear the request clearly. Although the operator repeated it back as an instruction to use Unit 4 only, the manager did not correct this misunderstanding.  

As a result, the EPRS operator did not start Unit 3 until called back by the EMG’s real-time desk operator to ask why the unit was not running. At this point, the EPRS operator listened to the recordings and realized he had missed the request for Unit 3 to be started. EPRS contacted PJM to notify the RTO that it had failed to bring Unit 3 online, and PJM canceled the request. 

The failure to convey PJM’s directive violated requirement R5 of TOP-001-5, which, like IRO-001-4, requires TOPs, GOPs and DPs to “comply with each operating instruction issued by” their BAs. RF assessed the TOP-001-5 infringement as a minimal risk to grid reliability. However, the RE assessed the other issue as a serious risk because performing the reactive test without a stability study could have caused the unit to trip, damaging station equipment and further jeopardizing grid reliability. 

To mitigate the miscommunications that led to the lapses, both Liberty and EPRS conducted an extent of condition review of their communications with Cogentrix’s EMG from October 2021 to January 2022 and found no further instances of failure to follow operating instructions. They also developed plans to manage communication with PJM and other plants during future phone outages by the EMG. 

RF assigned a penalty of $85,000 for the IRO-001-4 infringement, and $25,000 for the TOP-001-5 violation. 

Georgia Entities Settle Over Ratings Issues

SERC’s settlement with GTC started with a self-report filed Oct. 12, 2022. The utility indicated it was in violation of FAC-008-5 (Facility ratings). 

While reviewing drawings and equipment logs for its Bolingbroke substation, GTC found that a line elements database maintained by another registered entity did not list the correct jumpers or bus, likely the result of improper record keeping during a conversion from 68 kV to 115 kV in 1999. The utility derated the relevant line, restoring the previous rating several months later when the bus and jumpers were replaced. 

GTC then conducted a walkdown of 699 additional stations, finding 10 incorrect facility ratings that resulted in derates of up to 32%. SERC later conducted an audit in 2023 that found no additional instances of noncompliance. 

The RE assessed the root cause of the infringement as ineffective controls, primarily because of outdated procedures for communicating facility ratings that were not updated to incorporate new technologies. GTC’s mitigation activities — which are expected to be completed Dec. 31, 2025 — include updating its project review checklist to require verifying the actual transmission line ratings, completing an extent of condition review and committing to correct its internal records as necessary. 

SERC discovered MEAG’s violations — also of FAC-008-5 — through a compliance audit. The RE conducted a walkdown of MEAG’s facilities and found that some of the installed equipment was not included in the ratings table provided by the entity for one of its substations. Among the omissions were all the jumpers, along with a conductor and the name plate size of a switch at the facility. 

After the audit, SERC required MEAG to conduct a walkdown assessment of eight additional transmission stations. The utility identified one incorrectly rated element that led to a 10% derate on a 115-kV line. 

In this case, SERC attributed the misratings to a failure to follow internal controls, which meant that all applicable elements were not included in the facility rating database. MEAG committed to update its ratings database and participate in training on proper facility rating change management procedure. The utility also promised to perform walkdowns of all elements applicable to FAC-008, starting in the third quarter of 2024 and with an expected completion date of Dec. 31, 2025. 

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NEPOOL Supports Timeline Revisions for ISO-NE Order 2023 Compliance

The NEPOOL Participants Committee on May 1 voted to support an expedited filing adjusting several key dates in ISO-NE’s compliance proposal for FERC Order 2023.

The commission approved ISO-NE’s compliance filing on April 4, but several dates included in the filing no longer are viable (ER24-2009, ER24-2007). (See FERC Approves ISO-NE Order 2023 Interconnection Proposal.)

To preserve the general timeline of its proposal, ISO-NE intends to push back most dates and deadlines in its original filing by about a year. This would enable the RTO to run a group study for late-stage interconnection requests that lack capacity interconnection rights. The group study would precede the main transitional cluster study, which is likely to begin in October.

A proposed revision by RENEW Northeast failed to gain enough support to pass despite support from the NEPOOL Transmission Committee. RENEW proposed to let customers with late-stage interconnection studies continue their system impact studies (SISs) until Aug. 30, arguing this could help these developers avoid restarting their studies. ISO-NE stopped working on all in-progress SISs after FERC approved its compliance proposal. (See ISO-NE Prepares Expedited Filing After Ruling on Order 2023 Compliance.)

Prior to the meeting, NEPOOL Counsel Pat Gerity told members that the Participating Transmission Owners Administrative Committee did not support filing the changes with RENEW’s revision. He wrote that, “because of the shared filing rights that are implicated, the ISO does not believe it will be in a position to file the TC-recommended Section II revisions.”

The revision fell short of the two-thirds threshold required for PC support, with 59% of the committee voting in favor at the meeting on May 1.

The PC also voted to support changes to a pair of definitions in the ISO-NE Financial Assurance Policy and approved minor changes to the operating procedures for transmission outage scheduling and metering and telemetering criteria.

Operations Report

Energy market revenues significantly increased in April compared to the same month last year, ISO-NE COO Vamsi Chadalavada told the PC.

Average day-ahead and real-time hub LMPs increased by more than 65% year-over-year. The revenue increase largely was driven by more-than-doubled natural gas costs.

ISO-NE’s day-ahead ancillary services (DAAS) market, which the RTO launched at the beginning of March, had an average daily total value of about $15 million. Following a significant price spike after the market launch in early March, DAAS prices have remained relatively stable, but they did experience a smaller spike during a period of cold weather and elevated demand in early April.

The system did not experience any emergency conditions but did experience the lowest minimum load in ISO-NE history. (See Growth of BTM Solar Drives Record-low Demand in ISO-NE.)

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Around the Corner: Nobody Does Capacity Quite Like Ontario

Twenty-two years after it went live, Ontario’s independent electric system operator, IESO, has launched its Market Renewal Program (MRP), instituting a nodal day-ahead market that covers more than 900 locations. 

The revision appears to have gone smoothly, with the grid operator now joining the seven U.S. ISOs and RTOs that have day-ahead structures. Given that fact, it’s an opportune time to look at the bigger picture of Ontario’s structure and competitive electricity markets in general. 

DA markets typically are where the largest volumes of electricity are transacted on a location-specific nodal basis, with varying levels of nodal granularity. Under its earlier approach, IESO had operated only a real-time market with a single price, irrespective of location or transmission constraints. 

Generators could schedule their output the day prior, but commitments were not financially binding. Any inefficiencies or price discrepancies, including congestion, were settled through compensatory out-of-market payments, and discrepancies between expected generation and actual real time operations were not subject to penalty.  

Under the new MRP, day-ahead market offers — which create financial obligations to deliver energy the following day — will be scheduled to match forecast demands. Prices will be bound by a floor of -$100/MWh and a ceiling of $2,000/MWh.  

In some ways, it’s surprising the move took so long. Locational day-ahead markets create more market efficiency while also offering grid operators and market participants better foresight into what will happen the following day. They are more deliberately proactive and less reactive to real-time events.  

The move was a big step for IESO and one of the biggest tweaks to its market design in years. And while it increases the overlap in the Venn diagram with other market operators, IESO’s action and market redesign highlights a very curious fact about North America’s restructured markets: Each “deregulated” market embraces the overriding concept of competition but then spikes the drink with its own highly local flavors. 

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Peter Kelly-Detwiler

Editorial pet peeve: It’s not clear why people insist on calling this “deregulation.” With highly complex competitive markets superimposed on regulatory supervision for distribution at the state or provincial level, there are far more — and more complex — rules than ever existed before the advent of competition. And operators keep tweaking them to respond to the latest perceived market shortcoming. 

These market flavors also defy any attempt by generators, battery operators or demand response aggregators to achieve economies of scale — no, we have created a true Tower of Babel here.  

To illustrate the nature of this multifaceted hydra, let’s take the issue of capacity in a number of markets. Texas has no capacity market, letting energy scarcity prices offer the signals, although operating reserves are in the mix as well. Meanwhile, ISO-NE and PJM hold formal capacity market (FCM) auctions three years in advance — unless the regulatory conversation gets so muddled that they get delayed for years, as has been the case for PJM. 

New York long ago decided the FCM approach was too potentially inefficient and risky, and opted for monthly options with the possibility of transacting seasonal strips. Meanwhile, on the West Coast, California’s ISO tasks the utilities with procuring capacity resources. 

In many markets, capacity represents a noticeable element on the wholesale power bill. Exhibit A is PJM, with its recent eye-watering 2025/26 auction results at just under $270/MW-day, and the just-formalized floor and ceiling prices of $175 to $325/MW-day for the coming two auctions. Exhibit B is MISO’s just released auction results for this summer, coming in devilishly high at just over $666/MW-day and annually between $212 and $217/MW-day. They make PJM look tame by comparison.  

But nobody does capacity quite like Ontario, and that hasn’t changed with its Market Renewal.  

Capacity and the Global Adjustment Charge (GAC)

As in other markets with capacity prices, the GAC — established in 2006 — is intended to cover the cost of building and maintaining supply infrastructure to ensure system resource adequacy. The initial MRP proposal intended to do away with the GAC and replace it with a formal capacity auction. However, pushback from various stakeholders resulted in this plan being abandoned.  

Unlike the role of capacity pricing in other markets, though, the GAC specifically addresses the difference between the total compensation made to certain contracted generators and any offsetting market revenues. As such, there typically has been a strong inverse relationship between wholesale electric energy prices and the GAC. When wholesale energy prices are lower, the GAC is higher, and vice versa. And energy prices historically have been very low, with the result that the GAC typically is the largest single element on the average consumer’s total wholesale power bill, often representing up to 65% or more of the monthly costs.  

Ontario’s GAC will continue under the new program, but its impact and interaction will change slightly. The greatest impact may simply be that it will reflect greater location-specific volatility resulting from a nodal pricing program that specifically integrates the impact of congestion. 

Lower hourly energy prices will result in higher compensatory GACs, and higher prices will result in the opposite. Only time will tell whether capacity costs will decline as a total percentage of the entire wholesale bill. But if the history of many other grid operators is any guide, the rules-tweaking is far from over. Call it whatever you want, but don’t call it “deregulated.” 

Around the Corner columnist Peter Kelly-Detwiler of NorthBridge Energy Partners is an industry expert in the complex interaction between power markets and evolving technologies on both sides of the meter. 

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MISO Petitions 8th Circuit in Dispute with SPP over Data Center-strained Flowgate

MISO is seeking judicial review of two related FERC decisions preventing the RTO from recouping costs or revising a joint procedure with SPP over a shared North Dakota transmission line that has become congested by a new cryptocurrency mining facility.   

The RTO on May 1 filed a petition for review with the 8th U.S. Circuit Court of Appeals over the commission’s previous orders declining a request that SPP refund MISO members or change procedures around the overworked 230-kV Charlie Creek flowgate (ER24-1586, et al).  

The flowgate ran up tens of millions of dollars in congestion costs after the Atlas Power Data Center in Williston, N.D., activated on the SPP side of the line in 2023. MISO and its member Montana-Dakota Utilities maintain that associated market-to-market (M2M) settlements unfairly involved MISO in SPP’s localized issue brought on by 200 MW of poorly planned data center growth.  

FERC in March denied requests by both MISO and Montana-Dakota Utilities for rehearing to obtain refunds from SPP or cancel eligibility for the flowgate’s ongoing M2M coordination. The commission said the Charlie Creek Flowgate passed the RTOs’ flowgate eligibility studies for such coordination. (See FERC Again Declines Changes, Refunds on Crypto-burdened MISO-SPP Flowgate.)  

According to the agreement between the RTOs, MISO must secure SPP’s permission to remove M2M coordination from the flowgate. 

MISO also unsuccessfully sought for FERC to alter the MISO-SPP interregional coordination process — which manages flowgates — to make it easier for one RTO to revoke M2M status on a line if it doesn’t think the designation can assist with relieving a constraint. FERC decided that while a section of the two RTOs’ interregional coordination process says M2M coordination should be reserved for issues that are regional — rather than local — that requirement is not an explicit prerequisite for a flowgate to hold an M2M designation.  

MISO has claimed that unwarranted M2M coordination has cost its members $38 million in charges to manage congestion on the flowgate, even as its members can offer only less than 1 MW of relief. However, FERC said SPP’s evidence shows that revoking Charlie Creek’s M2M flowgate status might risk the RTO needing to resort to transmission loading relief or load shedding.  

MISO did not return RTO Insider’s request for comment on how much the RTO estimates its members are owed in refunds or whether it believes growing data center load would produce more flowgate issues at its seam with SPP.

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CRES Urges Federal Support for Cleaner Hydrogen

A conservative-leaning energy advocacy group is out with a new report on the value of methane-based hydrogen production paired with carbon capture and storage.

So-called “blue” hydrogen is poised to help expand U.S. energy dominance as the global market for lower-emissions hydrogen takes shape, the authors write, and federal incentives are essential for the nation to remain competitive in the early stages.

The Citizens for Responsible Energy Solutions (CRES) Forum report released May 5 included modeling analysis that projected tens of thousands of new jobs and tens of billions of dollars in economic impact from a robust blue hydrogen sector.

The report comes amid ongoing debate over clean-energy tax credits created under former President Joe Biden, which subsequently were targeted by President Donald Trump but are finding support from some Republican lawmakers who see economic benefits in their districts from those credits.

Among these are the 45V clean hydrogen production tax credit. It and other incentives are “essential” for helping the United States stay competitive in the emerging market, the authors write, as the advanced technology involved carries high upfront costs.

While U.S. industrial decarbonization initiatives no longer enjoy the same level of support as they did under President Biden, the report notes that other major economies continue to ramp up such efforts.

“The U.S. benefits from abundant natural gas resources and technological leadership in CCS, making it uniquely positioned to become a global leader in blue hydrogen production,” the authors write.

Their analysis of data from the International Energy Agency shows that all blue hydrogen projects publicly proposed in the United States would have a combined annual production capacity of 9.8 million metric tons by 2035.

Using multiple scenarios, the report calculates:

    • Construction of those plants nationwide could support 29,000 to 79,000 construction jobs through 2035.
    • Texas and Louisiana would see the largest boost in construction employment.
    • Construction could have an annual economic impact of $6.7 billion to $18.7 billion.
    • Annual operations would support 18,000 direct jobs and 44,000 indirect or induced jobs.
    • The bulk of those permanent jobs again would be in Texas and Louisiana.
    • Operations would support $22.4 billion in economic output.

Production of 9.8 MMT of blue hydrogen also would ripple through the natural gas industry, creating steady demand and supporting nearly 6,800 direct jobs, the report estimates.

The authors note that roughly two thirds of announced blue hydrogen production would be devoted to ammonia, most of it for fertilizer. The remainder might be used mainly for petroleum refining and transportation, with a small amount going to steel production.

“The 45V tax credit is not just an investment in energy; it is an investment in America’s economic strength, industrial leadership and long-term global competitiveness,” the authors write.

Dramatically increasing the production and dramatically decreasing the production cost of clean hydrogen was one of Biden’s high-profile Earthshot initiatives, but the vision was hampered by the slow rollout of details crucial to investment decisions. The 45V tax credit rules were not finalized until two weeks before Trump’s inauguration.

Beyond the economics, there is disagreement over how “clean” various types of hydrogen generation really are, and there was spirited argument between industry lobbyists and environmental advocates over the details of 45V as they were being finalized.

Those details play a critical part in how expensive production is and how impactful it is on the environment.

Hydrogen itself does not create carbon dioxide when burned or run through a fuel cell, but significant amounts of the greenhouse gas can be generated through hydrogen production.

Also, given that hydrogen produces less energy per unit of volume than methane, more hydrogen may be needed for a given application.

Finally, the carbon capture and storage that is integral to blue hydrogen also consumes energy.

There is room for reduction, however — the vast majority of U.S. hydrogen production is “gray,” which essentially is the same as blue hydrogen but without carbon capture.

Environmental advocates press instead for “green” hydrogen — emissions-free hydrogen produced with emissions-free electricity newly built for that purpose. Green at present is much more expensive than gray.

CRES is a nonprofit seeking to educate Republican lawmakers and the public about conservative solutions to address U.S. energy, economic and environmental security while increasing the nation’s competitive edge. It identifies its goal as lowering global emissions to maintain a clean environment and mitigate the impacts of climate change.

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CalCCA Study Touts Benefits of RA Trading at Hourly Level

The cost of electricity in California could be reduced if energy providers were allowed to trade their resource adequacy products by the hour, a new study by the California Community Choice Association (CalCCA) says. 

Currently, load-serving entities submit annual and monthly RA reports to the California Public Utilities Commission. In the reports, each LSE must demonstrate it has procured 90% of its system RA obligation for the five summer months of the coming compliance year and that it meets 90% of its flexible RA obligation for all 12 months. Under existing regulations, California LSEs are limited to trading RA products that cover an entire month. 

In 2024, CPUC started the first “Slice of Day” (SOD) RA program in the U.S. The program requires each LSE to demonstrate sufficient capacity in all 24 hours on CAISO’s “worst day” in a month, i.e., the day of the month that has the highest forecast peak load. 

However, in the SOD program’s first year, many LSEs had more resources than needed, while other LSEs did not have enough, CalCCA’s paper says. This outcome “suggests there are additional opportunities for trade that are currently unrealized due to regulatory barriers,” it says. It therefore argues for an hourly obligation trading model in order to reduce costs to consumers.  

“This is about fairness and common sense,” CalCCA CEO Beth Vaughan said in a press release. “Let’s stop making energy providers buy more capacity than they need, and let’s stop making Californians foot the bill.” 

CalCAA estimated that average RA prices could decrease by $1/kW-month for every 1-GW demand reduction in the new hourly model. The reduced demand for RA products on the market lowers the price of RA and the cost of meeting RA obligations for all California LSEs. 

Reducing the cost of RA in California has grown in importance in recent years following the rapid increase in RA prices, the paper says. For example, the weighted-average RA price was $2.77/kW-month in 2019 but increased by a factor of nine to $26.26/kW-month in 2024, according to the paper. 

Policymakers should support the development of effective trading mechanisms that go hand in hand with the transition to SOD, CalCCA’s paper says. Otherwise, the SOD program will drive up costs for consumers with no direct benefit to reliability. 

But CalCCA noted that its study is based on simulations and that a “real-world” implementation would require a much more in-depth investigation. 

“Implementing an effective trading mechanism with the SOD program will not be easy,” the paper says. “Trading in the SOD policy environment is six to nine times more complex than that of the legacy monthly RA product and will require a greater volume of trades, more transactions and more trading partners.” 

A key principle of CPUC’s current RA program is balancing addressing hourly energy sufficiency with advancing California’s clean energy, greenhouse gas emissions-reduction and air pollution-reduction goals, spokesperson Terrie Prosper told RTO Insider. With increasing penetration of renewable resources, CPUC sought to construct the SOD framework to better manage reliance on use-limited resources in meeting reliability needs, Prosper said. 

Trading RA obligations at the hourly level would not influence natural gas generation in California, Prosper said. The RA framework — both the previous structure and the SOD — is a planning construct and does not directly determine how much gas generation will be dispatched in the energy markets. 

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FERC Accepts ISO-NE Compliance Filing on Interconnection O&M Costs

FERC on May 2 accepted a compliance filing by ISO-NE and New England transmission owners eliminating interconnection customers’ responsibility to pay for the operations and maintenance costs of network upgrades (ER25-1324).  

The commission ordered an additional filing to address potential issues regarding refunds for O&M costs incurred after its initial ruling in December 2024. (See FERC Sides with New England Developers on Interconnection Complaint.) 

“The compliance filing largely complies with the [commission’s] directive to remove from the tariff any language providing for the assignment of O&M costs for network upgrades to interconnection customers,” FERC wrote. 

The commission also accepted tariff changes broadening the definition of an “interested party” in the New England TOs’ formula rate protocols, which should enable a wider range of groups to participate in proceedings. 

NEPOOL, RENEW Northeast, Advanced Energy United and the Alliance for Climate Transition supported the filing, while the New England Power Generators Association and CPV Towantic expressed concern it inadvertently would limit refunds to payments made after the December order, leaving out advance payments for costs incurred after. 

FERC directed ISO-NE and the TOs to make an additional filing within 30 days “to clarify that network upgrade O&M costs accrued on or after Dec. 19, 2024, will be returned to the interconnection customer, regardless of whether the interconnection customer made advance payments prior to” that date.