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December 13, 2025

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FERC Sides with Market Monitor over MISO in Compensation Dispute

FERC on July 18 rejected a petition from MISO seeking approval to not pay its Independent Market Monitor, Potomac Economics, for monitoring its transmission planning process (EL25-80).

MISO’s petition argued that the IMM’s review of its recent long-range transmission plans exceeds the scope of the Monitor’s authority and has contributed to recent cost overruns compared with the IMM’s contract.

IMM David Patton has argued that MISO’s tariff unambiguously authorizes him to monitor transmission plans, which have clear impacts on the wholesale markets. (See MISO IMM Contends He Should Have Role in Tx Oversight.)

RTO tariffs give rise to and define the scope of an IMM’s authority, and FERC and the courts consistently have found Monitors are limited to the authority laid out for them there and in agreements they sign with grid operators. In interpreting the MISO tariff, FERC had to address whether it unambiguously addresses the issue at hand — and the commission found that it does.

As the order pointed out, section 53.1 of the MISO tariff says the IMM can review any RTO actions that affect any of its markets and services.

“We also find that MISO’s transmission planning is an action that affects its markets and services, and that section 53.1.e unambiguously authorizes the IMM to review and analyze the competitive or other market impacts of MISO’s transmission planning,” FERC said.

FERC said it found no conflict in letting the IMM monitor transmission plans while MISO retains the sole authority to conduct transmission planning. The tariff does not let the IMM engage in transmission planning but simply authorizes him to review its impact on the market.

“We see no conflict between our finding here and the fact that the costs of transmission planning and of market monitoring are recovered under separate schedules to the tariff,” FERC said. “The cost recovery of transmission planning under Schedule 10 of the tariff is not relevant to the instant proceeding.”

FERC also rejected MISO’s argument that siding with Patton would be the same as amending the tariff absent a filing under Section 205 of the Federal Power Act.

And while MISO transmission owners had argued the case could risk the IMM involvement in any business area within the ISO, FERC found the tariff requires that the Monitor watch only issues that “affect the competitiveness, economic efficiency and proper operations of the markets and services.”

FERC also said that because no party had asked it to review any specific activities undertaken by the IMM, it was in no position to determine whether specific activities in the proceeding should have been billed to MISO. The commission encouraged the parties to work collaboratively on resolving such disputes.

‘Recognized and Applauded’

The order drew a pair of concurrences — one from Chair Mark Christie and another from Commissioner David Rosner.

“That transmission planning affects RTO markets is factually undeniable and thus makes this order an easy legal call,” Christie said.

Growing calls for expanding transmission are coming as consumers are facing rising bills, driven in large part by the rising costs of that infrastructure.

“Despite the understandable concern and publicity over capacity market auction results in MISO and PJM over the past year, transmission costs are the single biggest driver of skyrocketing monthly power bills and have been for years,” Christie said. “Transmission costs are driven not by the price of fuels such as natural gas, coal or oil, which change literally hourly and are set in global markets, but by capital expenses (capex), which are a result of intentional planning and intentional policy decisions, in this case by the management of MISO.”

The latest long-range plan comes with a price tag of $21.8 billion along with additional costs such as financing and return on equity that will be passed on to consumers.

“So, to his credit, MISO’s IMM has stepped up and provided a critique of the assumptions and calculations used by MISO to develop and attempt to justify this latest costly tranche of transmission projects,” Christie said. “Since the transmission planning that produced this tranche obviously affects the rates consumers pay, this is exactly what the MISO IMM and any market monitor should do.”

Christie also noted that state regulators and consumer advocates defended the IMM in the proceeding, which he said was in line with his experience with PJM during his time as a Virginia regulator.

“The role of an IMM requires courage and a willingness to put his job on the line by bringing to light uncomfortable (for some) facts and drawing conclusions about those facts that he is prepared to defend forthrightly,” Christie wrote. “The MISO IMM has done so here and he should be recognized and applauded.”

Rosner wrote separately that it’s important that a Monitor and its RTO should have a good working relationship, and ideally MISO and Patton should have settled the dispute on their own.

“In a situation like this one, which is essentially a contractual dispute, the best outcomes are achieved when the parties reach agreement among themselves — not when the commission is asked to interpret decades-old language,” Rosner said. “When parties ask the commission to answer a ‘yes or no’ question, they forfeit the opportunity to reach a compromise solution that results in better outcomes for everyone involved.”

He also noted that nothing in the order should be read as a requiring an independent transmission monitor, a concept discussed in Order 1920 that the commission could not reach consensus on.

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Large-scale Solar and Wind Hit with One-two Punch

As new solar and wind developments face hurdles due to changes in federal policy, the projects are also encountering growing resistance at the local level, according to speakers at a webinar.

“In most of the United States, it’s very local government — counties or townships — that have the authority to decide whether these large-scale clean energy projects can move forward or not,” said Dahvi Wilson, founder and president of consulting firm Siting Clean. “And increasingly, they are saying no.”

Wilson was one of four panelists at a July 17 webinar on obstacles to energy infrastructure. The event was hosted by Resources for the Future, a nonprofit research institution.

At the heart of the local resistance is the feeling that utility-scale solar and wind projects are transforming rural landscapes, giving them an industrialized feel, Wilson said. But the opposition to projects frequently expands to arguments that “often aren’t legitimate,” Wilson said, such as claims that the projects will have health impacts, hurt property values or are part of the “green new scam.”

Another factor in the growing local resistance is the transmission system’s limited capacity, Wilson said. As a result, clean energy developers are flocking to places where they can get on the grid.

“It leads to a ton of pressure on those places,” she said. “Suddenly, the resistance to this kind of development increases.”

Mapping Restrictions

Panelist Robinson Meyer, founding executive editor of Heatmap News, said that following enactment of the federal budget reconciliation bill, called the One Big Beautiful Bill Act (OBBBA), clean energy adversaries increasingly will focus their efforts at the local level.

“That is where the big fights are coming for slowing down clean energy production,” Meyer said.

Heatmap News surveyed counties across the country and found that 605 counties — accounting for about 17% of the land area of the continental U.S. — restrict solar or wind development in some way. The restrictions might be in the form of an outright ban, development requirements such as setbacks that make it nearly impossible to build, or moratoria that can be slapped on at will.

Wind and solar developers also identified local opposition as a significant barrier to clean energy projects in a January 2024 report by Lawrence Berkeley National Laboratory. (See Reports Detail Causes, Impact of Local Opposition to Renewables.)

Meyer said areas such as the Southwest have had a “relief valve” for building renewable projects on federal land, where county rules don’t apply. But now even that relief valve is under fire from the Trump administration.

Under a new directive from the Department of the Interior, all decisions concerning wind and solar energy facilities must be reviewed by Interior Secretary Doug Burgum, including leases, rights-of-way, construction and operation plans, grants, consultations and biological opinions. Critics called the order a “shadow ban” on clean energy projects. (See Interior Dept. Places Solar, Wind Under Close Review.)

Some states, such as New York and Michigan, are addressing local resistance to solar and wind projects by adopting mechanisms to override the opposition.

So even though the 250-MW Mill Point Solar 1 proposal in Glen, N.Y., has polarized residents, locals are limited in their ability to fight back. (See Rural Town Grapples with N.Y.’s Renewable Energy Vision.)

“State preemptions of these rules can be quite effective,” said Meyer, who noted there are more clean energy projects on the Michigan side of the Michigan-Ohio state line than on the Ohio side.

Tax Credit Clock Ticking

With the enactment of OBBBA, solar and wind developers now face a tight timeline for starting and finishing projects in order to qualify for sunsetting tax credits.

Investment and production tax credits no longer will be available for solar and wind facilities placed in service after Dec. 31, 2027 — unless construction starts by July 6, 2026, in which case the deadline for placing the project in service is extended. The dates are subject to Treasury Department guidance; an update to the guidance is expected by Aug. 18.

The tight tax-credit timeline means  opponents need only to delay a project to derail it, Wilson said.

“They don’t even have to kill the project,” she said. “They have to delay them maybe a year, to knock them out of being qualified.”

Webinar panelist Rich Powell, CEO of the Clean Energy Buyers Association, said there could be a rush for developers to “commence construction” of solar or wind projects to meet the tax credit deadline. That might entail starting work on a new transformer or road, or meeting a spending threshold by buying solar panels, turbines or batteries.

“Which is painful from the buyer’s perspective, because that’s going to mean prices go up for all of these things … as people sort of rush to do that,” Powell said.

Panelist Allison Clements, a former FERC commissioner and now a partner at ASG, a consultant to the data center, cloud and real estate development industries, called the administration’s actions “economically irrational.”

“I couldn’t have guessed in my most creative moment some of these things they’re doing to slow things down. [Saying] ‘I really hate this color of electron versus that color of electron,’” Clements said.

But Clements said given the “durable demand” expected over the next five to seven years due in part to computing needs and electrification, she still expects projects to proceed.

“Things will just be increasingly messy but continue to go forward,” she said.

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NERC Task Force Members Share Standards Modernization Progress

NERC is seeking comments from industry stakeholders on potential changes to the ERO’s standards development process found in an upcoming white paper, members of the task force that wrote the document said in a webinar July 21.

The draft white paper is a key product of NERC’s Modernization of Standards Processes and Procedures Task Force (MSPPTF), launched by the ERO’s Board of Trustees at its February meeting. (See “Task Force to Examine Standards Process,” NERC Leaders Highlight Canada-US Collaboration.) It will be released July 22, with a public comment period to open the same day and close Aug. 27.

NERC’s board decided to stand up the task force after growing concern that the ERO’s standards process was too deliberative to keep pace with the rapidly changing reliability risk landscape. The board’s use of its authority in 2024 under Section 321 of NERC’s Rules of Procedure to accelerate the pace of two standards projects that seemed unlikely to meet a FERC deadline brought more attention to these issues.

“The industry is at an inflection point due to the rapid evolution in reliability risks, such as plant retirement, more variable generation and … extraordinary load growth,” MSPPTF Chair Greg Ford, CEO of Georgia System Operations, told webinar attendees. “While previous incremental enhancements have marginally improved our efficiency, the task force believes that a more transformational change to the NERC standard development process will certainly improve NERC’s ability to address these risks in a timely manner.”

Ford said that NERC’s data showed the development of a standard takes on average about three years, with about 20% of that time spent developing an initial standard authorization request (SAR) into a final version that a standard development team can work on. The next stage of development, going from the SAR to submitting a first draft standard for industry ballot, takes about 50% of development time on average, and the remainder is spent refining the draft standard based on industry feedback until it meets final approval.

Recognizing these stages, the white paper’s authors divided their proposed changes by the phase of development to which they apply. The initiation phase begins when a request to develop a standard is submitted and ends when the request is approved to begin drafting; standard development begins when the request is approved and ends when a first draft is proposed; and balloting begins when a proposed standard is ready for industry to vote and ends when the standard is either approved or returned to drafting.

Two of the white paper’s proposals will pertain to the initiation stage, Southern’s Todd Lucas said, calling them “options that we can use as a starting point … and get to a draft recommendation later this fall based on the input we get.”

Both options are intended to address the fact that “there are multiple ways [today] for a [SAR] to get initiated” by establishing a single process to identify and vet candidates for development. The first would involve a biannual review process, involving an open submission period and industry conference focused on prioritizing submissions. The other would be to centralize all submissions through NERC’s Reliability and Security Technical Committee.

Another three proposals, introduced by Ford, apply to the development phase, with the goal of getting “off the blank page … much sooner.” One way to do this, Ford said, is to use artificial intelligence more extensively, at least for low- or medium-priority projects, in tandem with a standing body of subject matter experts maintained by NERC.

“Not every standard that goes through this process may need a drafting team,” Ford said. “We can run [low- and medium-priority] projects through this process using subject matter experts, as well as this AI tool. We’ll run that through comment periods from the industry, we will convene technical conferences throughout this stage so that we can keep industry in tune … and we’ll be able to put together a package that we can communicate and get comments from the industry.”

An alternative to this proposal is to outsource standards drafting to a third-party contractor. In this scenario NERC still would oversee the contracting and drafting processes, and it still would go out for industry comment as normal. The third proposal would see the current process remain in place, but with tweaks for greater efficiency, possibly using AI tools.

For the third phase of development, balloting, MISO’s Todd Hillman listed three potential ideas. The first would involve replacing NERC’s current system of ballot pools formed from industry volunteers for each candidate standard, representing “somewhere in the neighborhood of 470 potential votes,” with a standing ballot body composed of about 24 members. These members still would represent the ERO’s industry sectors, but with a smaller, dedicated membership the authors hope that participation in each balloting process could be higher.

Another option would be to adopt an approach similar to FERC’s rulemaking process, which would replace the stakeholder balloting with a “notice and comment approach.” Under this model, NERC would post a draft standard for comments with questions to guide feedback. NERC then would analyze any comments received, update the draft based on the feedback, and then move forward to the board rather than calling for votes from industry. Finally, the third proposal under the balloting section would keep the existing system, with incremental changes.

NERC and the regional entities plan to hold industry outreach events during the comment period, with Q&A sessions the week of Aug. 4. Based on feedback, the MSPPTF will create formal recommendations with the goal of submitting them to the board at its February 2026 meeting.

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Report Calls U.S. Transmission Buildout Inadequate

A new study warns that the United States is not building anywhere near enough high-voltage transmission to support the anticipated needs of the evolving economy.

Americans for a Clean Energy Grid and Grid Strategies said July 21 that just 322 miles of lines rated at 345 kV or greater were completed in 2024, the third-lowest total among the past 15 years.

This creates potential stress for critical sectors whose electricity needs are growing, they said, such as artificial intelligence, computer chip fabrication and advanced manufacturing.

“We’re seeing a serious mismatch between where we are and where we need to be,” Christina Hayes, executive director of Americans for a Clean Energy Grid, said in announcing the report.

The two organizations called for ambitious multi-regional transmission planning as well as permitting reform.

“We know that thousands of miles of transmission can be built each year because in 2013 we did it, with California, Texas, the Southwest Power Pool and Midcontinent Independent System Operator all building hundreds of miles,” Grid Strategies President Rob Gramlich said in a news release.

The U.S. Department of Energy in October 2024 addressed the issue with release of its National Transmission Planning Study. (See DOE Funding 4 Large Tx Projects, Releases National Tx Planning Study.) That study found that under various scenarios, the transmission network in the contiguous United States would need to be 2.1 to 3.5 times larger in 2050 than in 2020.

The 2.1x model would imply an addition of roughly 5,000 miles a year, the ACEG/GS report states. The only year in the study period that approached this was 2013, when approximately 4,000 miles of 345-kV and 500-kV lines were completed.

As an added benefit, the report noted, high-voltage lines are more cost-effective per megawatt and enhance resource adequacy by allowing capacity sharing across regional boundaries at times of grid stress.

The Interregional Transfer Capability Study that NERC filed in November 2024 recommended 35 GW of such capacity be added. (See NERC Releases Final ITCS Draft Installments.)

The ACEG/GS report notes that significantly more miles of natural gas pipelines than high-voltage transmission have been built in the past five years, and notes that no siting authority for power lines exists that is comparable to FERC’s authority to site interstate gas lines.

Looking ahead, the report cites NERC data indicating 7,098 miles of lines greater than 345 kV under construction or planned through 2032 nationwide. And multiple regions are beginning to plan new 765-kV lines as higher-capacity corridors that move energy efficiently over long distances.

The ACEG/GS report concludes with the assertion that federal leadership in adopting the requirements of FERC Order 1920 now must be matched, and strongly, by regional implementation.

“Planners should treat Order No. 1920 as a floor, not a ceiling, building on its foundation for ambitious, proactive and multi-value regional transmission planning and cost allocation,” the authors wrote. “In parallel, permitting reforms, targeted funding and state-federal collaboration can help ensure that projects move from planning phases to steel in the ground.”

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Stakeholder Forum: Rubber Stamp? Has the NRC Lost Its Independence?

The pace of undermining the statutory authority of the Nuclear Regulatory Commission to serve as the cornerstone of nuclear safety in the United States and across the world is accelerating. 

The recent directive by Department of Government Efficiency (DOGE) staff member Adam Blake to NRC staff to “rubber stamp” Department of Energy (DOE) and Department of Defense (DOD) nuclear projects highlights how far and fundamentally these cracks have advanced in the pillars of nuclear safety culture within the federal government. 

There is a saying: “Nuclear power is not inherently unsafe, but nuclear power is inherently unforgiving.” The implication is clear: Inattention to safety details has significant consequences. These concerns led Congress to wisely separate the original Atomic Energy Commission (AEC) into two agencies with constructive tensions. One is the DOE, which studies and promotes multiple forms of energy, including nuclear power. The other is the NRC, with the function of nuclear safety above all else. 

During the 70-plus-year experiment with nuclear power, “defense in depth” safety margins have prevented nuclear accidents from the mundane to the catastrophic. Yet we have also seen numerous near misses, such as Browns Ferry (1975) and Three Mile Island (1979), and tragic failures at Chernobyl (1986) and Fukushima (2011).  

With the advent of lower-cost hydraulically fractured fossil gas burned in combined cycle turbines and low-cost renewable wind, solar and storage, nuclear power no longer is a low-cost provider. New nuclear projects also failed to stay on budget and on schedule. 

Stephen A. Smith

The past three nuclear reactors to come online, all in the nuclear-friendly southeastern U.S., highlight the failures. TVA’s Watts Bar 2 was over 40 years behind schedule and cost $6.1 billion, while Georgia Power’s Vogtle 3 and 4 were seven years delayed and $21 billion over budget. While thoughtful utility managers have moved away from nuclear power to embrace less risky, more predictable, and less complex energy solutions, nuclear zealots have sought to blame “over-regulation” and “government bureaucracy” for problems inherent in nuclear technology itself. 

Over the past decade, the NRC has become the favorite whipping boy of zealots beholden to a stagnant industry. Industry lobbyists have persistently chipped away at the structural pillars of safety and independence at the NRC while justifying the restructuring — i.e., weakening — of the NRC as needed for nuclear power’s survival. 

The Nuclear Energy Innovation Capabilities Act (NEICA) of 2017, Nuclear Energy Innovation and Modernization Act (NEIMA) of 2019, and Accelerating Deployment of Versatile, Advanced Nuclear for Clean Energy Act (ADVANCE Act) of 2024 have all been the hammers and chisels in the legislative toolbox. These moved with bipartisan support, further eroding safety and the NRC’s independence. 

The ADVANCE Act proved particularly damaging, as it required the NRC to alter its mission statement to ensure licensing “does not unnecessarily limit the benefits of civilian use of radioactive materials and nuclear energy technology to society.” This represents a fundamental departure from the agency’s safety-first mandate, introducing promotional language that echoes the very conflicts of interest that led to the AEC’s dissolution in 1974. 

Former NRC commissioners have sounded the alarm about these dangerous trends. “An independent regulator is one who is free from industry and political influence,” warned Allison Macfarlane, who served as NRC chair under President Obama. “Once you insert the White House into the process, you don’t have an independent regulator anymore.” Three former NRC chairs jointly warned that recent changes “serve to weaken protections for those who work in or live near reactors.” 

The irony is profound: Just as the nuclear industry seeks to expand deployment of advanced reactor designs — technologies that are largely unproven and require more rigorous safety review, not less — the regulatory framework is being systematically weakened. These new reactor designs, from small modular reactors to advanced fast reactors, represent significant departures from existing light-water reactor technology. They require intensive safety analysis precisely because they lack the decades of operational experience that inform current safety protocols. 

This regulatory erosion threatens to undermine the very public confidence the nuclear industry desperately needs to expand. Edwin Lyman of the Union of Concerned Scientists warned that the Trump administration’s approach could “take talent and resources away from oversight and inspections and put them into licensing,” calling the strategy “totally misdirected.” 

The potential consequences extend beyond U.S. borders, as former NRC officials noted: “If it becomes clear that the NRC has been forced to cut corners on safety and operate less transparently, U.S. reactor vendors will be hurt” internationally, since “a design licensed in the United States now carries a stamp of approval that can facilitate licensing elsewhere.” 

As an unbridled Trump returned to the White House pontificating about a “golden era” and “energy dominance in America,” the die was cast for the NRC. DOGE staff infested the NRC and DOE, Trump’s May nuclear executive orders solidified the collapse of the NRC’s safety role and independence, and Adam Blake’s “rubber stamp” comment was just the silent part said out loud. The structural pillars that have protected Americans from nuclear accidents for five decades are cracking under the weight of industry pressure and political interference. 

The ultimate tragedy is that weakening safety oversight precisely when unproven reactor technologies need the most rigorous review sets the stage for the kind of serious accident that could devastate public confidence in nuclear power for generations — the very outcome the industry claims to want to avoid. 

Stephen A. Smith is executive director of the Southern Alliance for Clean Energy. 

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PJM MRC/MC Preview: July 23, 2025

Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability and Members committee meetings on July 23. 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 be covering the discussions and votes. See next week’s newsletter for a full report.

Markets and Reliability Committee

Consent Agenda (8:35-8:40)

The committee will be asked to endorse a consent agenda that includes:

C. proposed revisions to Manual 10: Pre-Scheduling Operations, Manual 11: Energy & Ancillary Services Market Operations, Manual 14D: Generator Operational Requirements, Manual 21B: PJM Rules and Procedures for Determination of Generating Capability, Manual 27: Open Access Transmission Tariff Accounting and Manual 28: Operating Agreement Accounting to conform with the third phase of PJM’s market rules for hybrid resources. This phase aims to make clarifications to the rules developed in the earlier stages and further develop rules for non-inverter-based hybrids, such as gas and storage.

Issue Tracking: Hybrid Resources Enhancements (Hybrids Phase 3)

D. proposed revisions to Manual 14C: Generation & Transmission Interconnection Facility Construction, drafted through the document’s periodic review. The changes would add detail to the milestone requirements for generation interconnection agreements and interconnection service agreements.

E. proposed revisions to Manual 18: PJM Capacity Market to conform with several rule changes approved by FERC (ER25-682, ER25-785, ER24-2995 and ER25-1357). The package includes codifying how PJM will model the output of some resources operating on reliability-must-run agreements as capacity; maintaining a combustion turbine as the reference resource; establishing a uniform Capacity Performance penalty rate; removing a categorical exemption allowing intermittent, storage and hybrid resources to avoid submitting capacity offers; eliminating the energy efficiency addback; and instituting a capacity price floor and lowering the maximum price for the next two capacity auctions. (See FERC OKs Changes to PJM Capacity Market to Cushion Consumer Impacts.)

Endorsements (8:40-11:25)

2. Operating Reserves Clarification (8:40-9:05)

PJM’s Lisa Morelli will review a joint proposal from the RTO and Independent Market Monitor to rework how uplift credits and deviation charges are calculated in an effort to encourage resources to follow dispatch instructions. It includes the creation of a new tracking ramp-limited megawatt desired (TRLD) metric designed to follow how resources respond to instructions over time, rather than being limited to five-minute intervals. (See “Stakeholders Narrowly Endorse Uplift Changes,” PJM MIC Briefs: April 2, 2025.)

The committee will be asked to endorse the proposal and corresponding tariff and Operating Agreement revisions.

Issue Tracking: Operating Reserve Clarification for Resources Operating as Requested by PJM

3. Manual 14H: New Service Requests Cycle Process Revisions (9:05-9:30)

PJM’s Michelle Farhat will review revisions to Manual 14H: New Service Requests Cycle Process to conform with a FERC-approved settlement between the RTO and several developers seeking changes to the site-control requirements for new resources (ER25-1544, EL25-22). The RTO is also seeking to rework the site control needed for each project milestone to clarify when parcels can be added or removed. (See PJM Presents Settlement on Site Control Requirements.)

The committee will be asked to endorse the proposed manual revisions upon first read.

4. 2027/2028 Base Residual Auction, Installed Reserve Margin and Forecast Pool Requirement (9:30-9:55)

PJM’s Josh Bruno will present the RTO’s recommended forecast pool requirement and installed reserve margin. Both values would increase for the 2027/28 Base Residual Auction over the previous auction.

The committee will be asked to endorse the values upon first read. Same-day endorsement will be sought at the MC.

5. Sub-annual Capacity Market Issue Charge (9:55-10:20)

Jacob Finkel, with the office of Pennsylvania Gov. Josh Shapiro, will present a proposed problem statement and issue charge to explore implementing a sub-annual capacity market. (See Pennsylvania Brings Seasonal Capacity Issue Charge to PJM.)

The committee will be asked to approve the issue charge.

6. Dual-fuel Capacity Definitions (10:20-10:45)

Dominion Energy’s James Davis will review a proposed problem statement, issue charge and proposal to revise the definition of dual-fuel capacity contained in the Reliability Assurance Agreement (RAA) to include dedicated fuel sources that are not strictly “on-site.” (See “Dominion Presents Proposal to Change Dual-fuel Definition,” PJM MRC/MC Briefs: June 18, 2025.)

The committee will be asked to approve the issue charge and endorse the proposed solution and corresponding RAA revisions. The proposal is being advanced under the quick-fix process, which allows an issue charge to be voted on concurrently with a proposed solution.

7. Storage Integration (Phase II): Transmission Asset Utilization in Operations (10:45-11:25)

A. PJM will review a proposed problem statement and issue charge exploring how storage as a transmission asset (SATA) could be operationally implemented.

B. Juliet Anderson of Constellation Energy will present an alternative issue charge that includes more consideration of the potential market impacts of SATA.

C. Alex Stern of Exelon will present an alternative issue charge to consider both market impacts and the use cases SATA could address.

The committee will be asked to approve one of the issue charges. (See “Stakeholders Bring Alternative SATA Issue Charges, Endorsement Delayed,” PJM MRC/MC Briefs: June 18, 2025.)

Members Committee

Consent Agenda (3:05-3:10)

The committee will be asked to endorse a consent agenda that includes:

B. proposed revisions to PJM’s tariff, RAA and OA as endorsed by the Governing Documents Enhancements and Clarifications Subcommittee. The changes include removing outdated references and codifying the second phase of PJM’s rules for hybrid resources.

Endorsements (3:10-3:40)

1. Nominating Committee Elections (3:10-3:20)

PJM’s Michele Greening will present the sector nominees for the 2025-2026 Nominating Committee. The proposed candidates are:

    • Generation Owner: Josh Ghosh, Constellation
    • Transmission Owner: Alex Stern, Exelon
    • Electric Distributor: Kevin Zemanek, Buckeye Power
    • Other Supplier: Noha Sidhom, Viribus Fund
    • End Use Customer: Susan Bruce, PJM Industrial Customer Coalition

The committee will be asked to elect the sector representatives upon first read.

2. 2027/2028 Base Residual Auction, Installed Reserve Margin and Forecast Pool Requirement (3:20-3:40)

Bruno will review the recommended IRM and FPR values for the 2027/28 BRA.

The committee will be asked to endorse the values on first read.

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Canadian Utilities Push Action on Net-zero Goals, Tax Credits

Canada’s utilities are encouraged by the country’s new government but say legislation to fast-track high-priority infrastructure projects does not address needs for permitting relief and more flexible clean energy targets and investment tax credits.

The Building Canada Act (Bill C-5), approved in June, gives the federal government the ability to override some laws, regulations and environmental assessments for projects designated as in the national interest. The bill has sparked opposition and litigation from Indigenous groups.

“I think the view generally is C-5 sends a good message, but it does not address any of the fundamental issues that need to be addressed,” Francis Bradley, CEO of trade group Electricity Canada, said during a presentation at IESO’s Strategic Advisory Committee meeting July 16. Electricity Canada, formerly the Canadian Electricity Association, represents 42 generation, transmission and distribution companies in Canada’s 10 provinces and three territories.

C-5 is expected to fast-track permitting for 10 to 12 projects.

“If your project is not on that list, what happens?” Bradley asked. “We have not addressed any of the fundamental challenges that we have with getting infrastructure built in the country. So, we haven’t addressed the Clean Electricity Regulations [CERs]; we haven’t addressed the Fisheries Act; we haven’t addressed the Impact Assessment Act.”

‘Concierge’ Approach

Julia Muggeridge, Electricity Canada’s vice president of communications and sustainability, recalled a meeting with the new Major Projects Office — the hub of a “one project, one review” model to eliminate duplication between federal and provincial governments — shortly after the April 28 federal elections.

“It was a very positive meeting. … They said that there’s going to be this concierge approach to [C-5] projects, but then there’s going to be the second tranche of projects that will have less of a white-gloved approach, but they’ll also be given their own process. We haven’t seen that yet, but it was something that was introduced to us.”

Canada’s annual electricity demand is projected to at least double to 1,200 TWh by 2050. | Electricity Canada

Muggeridge said some of her group’s members are concerned over the speed with which the bill was approved and the lack of consultation with them in advance. “But I believe that’s being rectified throughout the month of July. We’re hoping for positive conversations over the next two weeks, but that’s generally what I’ve been hearing from members who are excited and looking at how they can ensure their projects are on this list of 10 to 12.”

Indigenous leaders, however, were not mollified by a meeting with Prime Minister Mark Carney on July 17, saying consulting First Nations after the legislation had passed was disrespectful.

The 2025 priorities that Electricity Canada will be presenting to the government in August will “look a lot like they did in 2024,” with an emphasis on improving the country’s competitiveness, Muggeridge said.

“It is too difficult to build in Canada,” she said. In “the latest ranking with the [Organization for Economic Cooperation and Development], we were like 64th for permitting in the world.”

The group says CERs’ goal of an emissions-free electric grid by 2035 will harm affordability and reliability, with impacts most acute in Alberta, Saskatchewan, Ontario, Nova Scotia and New Brunswick.

It also is seeking to change investment tax credits to include intra-provincial transmission and revise the definition of eligible small modular nuclear reactors; extend timelines for full value credits from 2030 to 2035; and eliminate the requirement that provinces and territories commit to a net-zero grid by 2035.

‘Startup Vibe’

Muggeridge said the new government has “a bit of a startup vibe.”

“This happened with [Prime Minister Justin] Trudeau in 2015 … an excitement and an urgency. Ministries are being staffed with new young folks that are excited to meet with Electricity Canada. We’re delighted with the engagement that we’ve had with the new government so far.”

Bradley agreed. “Clearly, the tone is different. … Seven or eight months ago, nobody around the Cabinet table would even engage in a conversation about some of these topics. Now, those conversations are at least taking place. … Whether or not it actually results in in making it easier to get good projects moving forward remains to be seen.

“What we need more than anything else is … certainty so that those investments can happen,” he added. “We’d like to remind people that we’re not talking about investments that have a three-year lifespan or a five-year lifespan. We’re talking about investments that that need to be able to stand up to the test of time for 20, 30, 40 years. These are generational investments that are required.”

13 Systems

Bradley said Canada’s electric regulations also are a challenge. “There is not that one electricity system in this country. There are 13 systems. And each of those systems — each province and territory — has constitutional authority over its own electricity regulation. And provincial autonomy often leads to resistance against federal initiatives, including, for example, net-zero targets or national infrastructure projects. In some jurisdictions, it’s principally Crown-owned companies. In other jurisdictions, it’s investor-owned companies. There’s a different level of market access and market maturity.

“I will often hear from folks in the western Canadian context, talking about the interconnection between [British Columbia] and Alberta,” he continued. “Why would one build more interconnection between these two jurisdictions when the current interconnection are not being maximized? Well, the current interconnection is not being maximized because there’s a mismatch between the markets.”

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WRAP Task Force Explores Optimization Under Day-ahead Markets

A new task force is examining how the Western Power Pool’s Western Resource Adequacy Program (WRAP) can continue to operate efficiently under the new multimarket environment emerging in the West.

The WRAP Day-Ahead Market (DAM) Task Force held its second meeting July 17 and discussed some of the thorny issues that lie ahead for the resource adequacy program as CAISO and SPP prepare to launch their respective day-ahead markets. The group’s members include entities like Bonneville Power Administration, Idaho Power, Portland General Electric and Powerex.

The purpose is to present a proposal aimed at enhancing WRAP’s Operations Program to make it compatible with both SPP’s Markets+ and CAISO’s Extended Day-Ahead Market (EDAM). The task force is focusing on market optimization and changes to transmission requirements in WRAP’s Southwest Region. (See WRAP Members Align on Key Issues to Prioritize.)

Representatives from participant organizations will chair the task force and formulate the proposal.

“WRAP was designed to work alongside all markets, as well as for participants who do not join a market,” Michael O’Brien, WPP’s senior policy engagement manager for the WRAP, told RTO Insider. “Much of WRAP’s design was created before EDAM and Markets+ existed, though. This task force will look at if and how WRAP should be optimized to work alongside the markets. It’s a chance to re-examine WRAP’s Operations Program through the lens of the day-ahead markets to potentially identify any efficiencies and opportunities, such as taking advantage of market optimizations and internal connectivity.”

Attendees of the July 17 meeting discussed issues such as data sharing between WRAP and market operators, handling holdback requirements, energy deployment and delivery, serving load in different markets and settlement pricing, among other potential challenges.

The group will meet throughout the summer and fall to create a formal proposal that will go out for public comment and review by program committees.

“If approved, the proposal could result in changes to business practice manuals or a potential FERC filing to make changes to the WRAP tariff,” according to O’Brien. “While the task force will look at WRAP through the lens of the day-ahead markets, the scope of the task force is limited to modifications of WRAP only.”

WPP launched the WRAP in response to industry concerns about resource adequacy in the West.

Under the program’s forward-showing requirement, participants must demonstrate that they have secured their share of regional capacity needed for the upcoming season. Once WRAP enters its binding phase, participants with surplus must help those with a deficit in the hours of highest need.

The binding phase also includes penalties for participants that enter a binding season with capacity deficiencies compared with their forward showing of resources promised for that season.

In 2024, the binding phase was postponed by one year at the request of participants, who said they were facing challenges including supply chain issues, faster-than-expected load growth and extreme weather events that would make it difficult for them to secure enough resources and avoid penalties. The binding phase is now expected to start in summer 2027. (See WRAP Members Vote to Delay ‘Binding’ Phase to Summer 2027.)

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Retiring ISO-NE CEO van Welie Reflects on 25 Years at the RTO

When Gordon van Welie first started working for ISO-NE in 2000, the organization had about 300 employees, few formalized systems and processes in place, and a resource mix dominated by nuclear, coal and oil generation.

Now, 25 years later, as he prepares to retire from the organization, ISO-NE has roughly doubled in size and oversees a rapidly evolving grid set to serve as the backbone of an electrifying and decarbonizing economy. (See ISO-NE CEO Gordon van Welie Announces Retirement.)

“The organization I came into was very much still in startup mode,” said van Welie, who is the longest-serving head of any ISO or RTO in the country. “There was a lot of work that had to be done just to set up all the formality around an organization that’s going to clear, in some years, $20 billion.”

ISO-NE was created in 1997 to manage the region’s grid and power markets amid restructuring, and van Welie was brought in just a few years later, initially serving as the organization’s COO before his appointment as CEO in May 2001.

“I was very fortunate to be in at the early stages of the design and development of the wholesale market structure as we know it today,” van Welie said.

In the few years after van Welie took over as CEO, ISO-NE developed and launched its day-ahead and real-time markets and navigated a potential three-way merger with PJM and NYISO. The merger, which was explored in response to FERC’s interest in expanded ISO footprints, ultimately was abandoned due to the challenges of reconciling the differences between regions, van Welie noted.

He also oversaw ISO-NE’s transition to becoming an RTO in 2005, after FERC incentivized transmission owners to join RTOs across the country. This transition, and the negotiations that surrounded it, led to NEPOOL turning over filing rights for market rules to ISO-NE and codified ISO-NE’s responsibility for transmission planning in New England.

“The next big adventure,” van Welie said, was the creation of the region’s forward capacity market, which led to a “major settlement proceeding down in Washington, D.C.”

ISO-NE eventually ran its first forward capacity auction in 2008 for the 2010/11 capacity commitment period. The auction has been through 18 auction cycles, and the RTO in the midst of a major overhaul of the market intended to prepare the region for anticipated demand and supply changes associated with decarbonization efforts.

The Rise of Gas Generation

ISO-NE’s resource mix has experienced a dramatic shift during van Welie’s time with the RTO. As the fracking boom caused gas prices to plummet, the competitive wholesale markets helped speed the transition from oil and coal to gas generation, van Welie said.

In 2000, natural gas accounted for just 15% of generation in the region, while oil and coal accounted for a combined 40% of generation. By 2012, gas resources were responsible for 52% of generation, while oil and coal resources combined to account for about 4% of generation. Gas increased to about 55% of generation in the region by 2024. (See New England Gas Generation Hit a Record High in 2024.)

Following restructuring, “there were billions upon billions of dollars invested in the region in generation assets,” van Welie said. “That, I think, would not have occurred as quickly as it occurred without the establishment of wholesale markets.”

The introduction of wholesale markets also has helped protect consumers from poor investments during this period, van Welie said. He highlighted Dominion Energy’s decision to spend nearly a billion dollars to refurbish the Brayton Point coal plant, only for the plant to become uneconomic in just a few years because of the rise in low-cost fracked gas. The plant retired in 2017.

“That was a billion-dollar investment made by private capital that New England ratepayers never incurred,” van Welie said. “It was not a good investment, and ultimately, wholesale market structure shielded consumers from those investments.”

Transmission Investments

The gas generation boom was aided by the agreement in the early 2000s on a transmission cost allocation framework to regionally share the costs of reliability projects expected to bring system-wide financial benefits, van Welie said.

This helped enable major investments in transmission infrastructure, which increased transmission rates but reduced congestion costs and the need for reliability must-run contracts to retain retiring resources. These investments made it easier for new gas plants to come online, speeding up the turnover of the fleet, van Welie said.

Today, New England has the lowest congestion costs of any RTO, coupled with transmission rates that are “more than double the average rates in other RTO markets,” according to Potomac Economics. (See NEPOOL PC Briefs: June 24-26, 2025.)

The transmission investments made during this period also have helped New England prepare for accelerating load growth and a growing influx of renewable energy, van Welie said. The RTO forecasted in its 2050 Transmission Study that the region likely will need to spend an additional $22 billion to $26 billion to meet load growth associated with heating and transportation electrification. (See ISO-NE Prices Transmission Upgrades Needed by 2050: up to $26B.)

“I think we made that investment at exactly the right time,” he said, noting that the cost of new transmission infrastructure has increased rapidly in recent years.

“We laid a foundation at a time when transmission was … inexpensive relative to today,” he said. “If you look at where we are today, we’ve got a very strong transmission system. It’s well positioned to support the next stage of growth.”

Resource Adequacy and Energy Transition

He said he’s confident ISO-NE has adequate resources to meet load and ensure reliability through 2030 but acknowledged there are valid questions about how to ensure resource adequacy in the 2030s and beyond.

“I’m confident the ISO is going to do what it needs to do,” he said, pointing to the ongoing capacity market overhaul as a “foundational ingredient to maintaining the successful trajectory we’ve had over the last 25 years.”

However, ISO-NE cannot succeed on its own, and will need “a supportive regulatory environment for markets to be successful,” van Welie added, emphasizing the need for support from both federal and state regulators and policymakers.

“If we have people pulling in opposite directions … it’s going to make it that much harder for investors to have confidence in the market construct,” he said.

Reiterating his testimony from the recent FERC technical conference on resource adequacy, van Welie said policymakers should work to reduce barriers to entry for new resources. He stressed that the wholesale market “rests on the premise that you can price the prevailing supply and demand conditions and produce a price signal that will attract the investment.” (See FERC Dives into Thorny Resource Adequacy Issues at Tech Conference.)

But whatever challenges lay ahead for ISO-NE, van Welie will be off the hook come Jan. 1, 2026, when longtime COO Vamsi Chadalavada is set to take over at the organization’s helm.

“I definitely will miss the ISO,” van Welie said, adding that he is looking forward to spending more time with family. “I would like to stay involved in the industry in some way. So that’s a new chapter in my life that I’m thinking through.”

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SPP ‘Blazes Trail’ with Consolidated Planning Process

LITTLE ROCK, Ark. — SPP stakeholders have unanimously approved a tariff change (RR684) that replaces current planning processes with an integrated three-year cycle composed of long-term 20-year and annual 10-year studies the grid operator says could “blaze a trail” for others to follow. 

The Consolidated Planning Process (CPP) transitions SPP from its “request-then-analysis” framework to a “ready-to-go” construct, where the system needs and costs are identified before the generator asks to connect. It replaces the RTO’s separate transmission planning and generator-interconnection studies and aligns system modeling, planning assumptions and cost allocation across load and generation needs.  

Too often, said Sunny Raheem, SPP’s director of system planning, the current process can lead to separate decisions and determinations and overlook “optimal opportunities for holistic transmission identification.” 

“This is really aligning cost commitment and collaboration together to aim at the right direction, the right targets and shared costs,” Raheem told the Markets and Operations Policy Committee on July 15. “We believe that we’re establishing a blueprint under CPP that’s going to enable us to plan for the modern era of grid integration. Today, we react to requests showing up; CPP will be proactively planning for guiding them to the positions that we really want the interconnection’s request to connect.” 

Raheem said the CPP sets a 20-year regional transmission vision and forms the basis for its grid-contribution rates. The annual 10-year assessment includes a GI capability study, a GI decision point and a regional assessment that recommends projects for construction, all within three years. 

He said the CPP’s forward-looking interconnection study and a “levelized” cost calculation based on benefits from using the transmission system make for a robust process. According to SPP’s 2025 Transmission Expansion Plan report, 92% of system upgrades are funded by load. 

According to a recent Enverus study, new SPP operating projects in 2024 spent about six years in the GI queue, about the industry average.  

Queue times for projects in GI queues. | Enverus

“[The CPP] helps mitigate those binary cost assignment decisions for generator interconnection. It also increases the cost sharing for generators to contribute to transmission upgrades,” Raheem said. 

MOPC’s endorsement — and that expected from the Board of Directors in August — culminates a process that consumed more than 200 meetings, discussions and presentations with eight stakeholder groups over two-and-a-half years. The proposal was endorsed unanimously by every stakeholder group that voted on it. Staff also reached out to educate FERC and SPP’s state regulators on the CPP. 

“[This journey] may have seemed like a pie-in-the-sky idea that has progressed through incremental policies to get it to this point,” Raheem said. “When we’re assigning billion-dollar portfolios out of the ITP [Integrated Transmission Planning study], we really need transmission, load and generation all playing together.” 

Spearmint Energy’s Michael Ratliff, while holding reservations as a storage developer, said his company will support the CPP. 

Sunny Raheem, SPP | © RTO Insider 

“We recognize the need for creative queue reform, the value of creating more cost certainty and spreading the cost of transmission upgrades more evenly across the user base,” he said. “We would appreciate some assurances that SPP will be willing to collaborate with developers to make the CPP work for different resource types and the changing resource mix. We’re a little concerned that site planning may limit options for energy storage resources and prevent SPP from fully realizing the value of storage.” 

Some of SPP’s more outspoken stakeholders praised the grid operator and staff for completing the work in less than three years. 

“It is a bright spot for SPP and the stakeholder process,” Golden Spread Electric Cooperative’s Mike Wise said. “We have had a lot of input over a long period of time, and we have a lot of discussion and a lot of blood, sweat and tears developing this compromise and this approach that can work. We should applaud the SPP staff for sticking with us and managing through this very difficult process, and I am 100% behind it.” 

“We’re here in large part because Sunny and his team and everybody, I feel like on the CPP, really worked hard to try to find a path when we ran into walls, and we did,” the Advanced Power Alliance’s Steve Gaw said. “Is this the end result? No, we have a lot more work to do on this. Despite the communication that’s gone, there’s a huge challenge of getting this through at FERC because this is a very different approach than FERC has really seen in the past. 

“I think a lot of that groundwork and education that’s gone on has been very important,” Gaw added. The potential help with load issues is great, he said, if it will “get us to the point where the administrative part of interconnecting both gen and load is no longer the obstacle.” 

Evergy’s Derek Brown, alluding to SPP’s now-defunct “evolutionary, not revolutionary” value principle, said he was asked within the company’s headquarters whether the CPP process was evolutionary or revolutionary. (See SPP Embraces Need for Speed to Meet Change Head-on.) 

“It is revolutionary, there’s no doubt about it. If there was a bright spot for the SPP process, this is it. It took a very long time to get here, to write the tariff language, to take concepts and whiteboard drawings to actual language,” said the Transmission Working Group’s chair. “But like others said, there’s still work to be done.” 

Brown and other stakeholders will spend the next three months working on the CPP manuals. SPP plans to file the tariff change in the third quarter of 2025. Assuming FERC’s approval, the first CPP cluster study will begin in April 2026.  

MOPC also unanimously approved the scope and work schedule for a combined assessment of the 2026 ITP study, the 2026 20-year evaluation and the CPP transition. The document includes the initial policy items for incorporating the long-term CPP assessment and supports the study to kick off the process. 

Staff and stakeholders already have completed model development and a resource plan and siting and set the assessment’s futures. They now will begin a second phase, which involves a needs assessment, solutions evaluation and portfolio development. 

The scope’s CPP technical policies will be converted to planning criteria, the ITP manual, the 20-year assessment manual and GI manual.