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December 18, 2025

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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. 

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Interior Dept. Places Solar, Wind Under Close Review

Every Department of Interior action pertaining to wind and solar energy development now must be reviewed and approved by the Office of the Interior Secretary — after two subordinate offices separately have reviewed them and signed off. 

The new policy continues the Trump administration’s assault on renewable energy and sets up a potential logjam for any facilities proposed to be built on federal land. 

An internal memo lists 68 specific actions subject to the new protocol, ranging from lease sales and records of decision to tribal impact reviews and visual impact assessments. The 69th and final entry on the list is a catchall: “any other similar or related decisions, actions, consultations or undertakings.” 

Interior also said it would “eliminate longstanding right-of-way and capacity fee discounts for existing and future wind and solar projects, bringing an end to years of subsidies for economically unviable energy development.” 

This is the polar opposite of the administration’s moves to speed and relax regulatory oversight for favored energy resources such as crude oil, natural gas, coal and uranium. In April, Interior went to an emergency footing, setting a 14-day target for standard environmental assessments of the favored energy projects and a 28-day time frame for more extensive environmental reviews. 

The memorandum about the new wind and solar protocol was issued internally July 15. It was leaked to the media soon after, then officially announced July 17. 

The American Council on Renewable Energy said: “Today’s announcement by the Department of the Interior amounts to a tsunami of red tape and road blocks for private investment in wind and solar energy projects. Requiring Interior Secretary Doug Burgum’s personal approval on at least 69 distinct permitting actions on potentially hundreds of projects represents an unnecessary and inefficient approach to permitting that will lead to significant delays and uncertainty.” 

In the July 17 news release, acting Assistant Secretary for Lands and Minerals Management Adam Suess repeated the administration’s position on wind and solar, which provided 14% of utility-scale generation in the United States in 2023 and accounted for 78% of capacity additions in 2024.  

“American energy dominance is driven by U.S.-based production of reliable baseload energy, not regulatory favoritism towards unreliable energy projects that are solely dependent on taxpayer subsidies and foreign-sourced equipment,” Seuss said. 

Interior took the opposite tack during the Biden administration, cutting lease fees for renewables development on public land and streamlining oversight. In December 2024, Interior said its Bureau of Land Management had approved 45 renewables projects on public lands with a total capacity of 33 GW since January 2021 — well exceeding the 25 GW goal. 

In January 2025, shortly before Biden left office, the National Renewable Energy Laboratory released an analysis showing federal lands hold the potential for 5,750 GW of utility-scale photovoltaics, 975 GW of geothermal and 875 GW of wind generation. 

Boosting fossil fuels and sidelining renewables was a central plank in Trump’s campaign platform. He began to deliver hours after his inauguration, declaring a national energy emergency and inflicting limiting uncertainty on the struggling offshore wind industry. 

The One Big Beautiful Bill Act he engineered through Congress inflicts sharp new limits on wind and solar, and his follow-up executive order directed Interior and other agencies to use the full extent of their powers to make those limits stick. (See Trump Executive Order Targets Renewable Energy Tax Credits and U.S. Clean Energy Sector Faces Cuts and Limitations.) 

This led directly to the July 15 memo to Interior staff. The July 17 news release states: “This enhanced oversight will ensure all evaluations are thorough and deliberative.” 

This language sets the stage for slow-walking anything related to wind and solar that falls under Interior’s review — which of course is exactly what conservatives accused the Biden administration of doing for four years with fossil fuel proposals. 

Interior said in the news release the directive would “level the playing field” for dispatchable and secure energy sources such as “clean coal and domestic natural gas” after the assault on them in the Biden years. 

ACORE was not the only organization unhappy with the changes. 

The Solar Energy Industries Association said: “There’s no question this directive is going to make it harder to maintain our global AI leadership and achieve energy independence here at home. It is deeply unfortunate that this administration’s energy policy continues to favor specific technologies rather than advance true American energy dominance.” 

The American Clean Power Association called the measure obstruction, not oversight: “In stark contradiction to the administration’s commitment to tackling bureaucracy, this directive adds three new layers of needless process and unprecedented political review to the construction of domestic energy projects. The Secretary of the Interior will apparently now be personally reviewing thousands of documents and permit applications for everything from the location and types of fences to the grading of access roads on construction sites across the country.” 

The National Resources Defense Council said the directive is a deliberate attempt to snuff out renewable energy on public lands: “Interior is putting a shadow ban on the new energy projects we need more than ever, delivering a shameless gift to the fossil fuel industry. Hundreds, if not thousands, of individual clean energy project-level decisions will now be left to the whims of a secretary who is already handing out every free pass possible to polluters.”

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LS Power to Buy bp’s U.S. Onshore Wind Business

LS Power has finalized a deal to buy bp Wind Energy North America, the U.S. onshore wind business of UK oil supermajor bp.

The agreement, announced July 18, includes five facilities wholly owned by bp and five partly owned. The 10 wind farms span seven states and provide power to more than 15 off-takers. They have a gross nameplate capacity of 1.7 GW, of which bp’s ownership share equals a net 1.3 GW output.

The deal is expected to close by the end of 2025, at which point LS subsidiary Clearlight Energy would own and operate bp Wind, bringing its fleet capacity to approximately 4.3 GW.

The sale agreement followed a competitive bidding process. Terms were not disclosed.

Bp said the deal is part of the $20 billion divestment program by which it is simplifying and refocusing on its most profitable businesses, and stepping back from energy transition efforts it now considers to have been too far and too fast.

William Lin, bp’s executive vice president for gas and low carbon energy, said in a news release: “We have been clear that while low carbon energy has a role to play in a simpler, more focused bp, we will continue to rationalize and optimize our portfolio to generate value. The onshore U.S. wind business has great assets and fantastic people, but we have concluded we are no longer the best owners to take it forward.”

The company expects $3 billion to $4 billion in divestment in 2025 and said it had signed or completed deals worth $1.5 billion in the first quarter alone.

LS CEO Paul Segal said the bp Wind fleet is a good fit for LS Power, which owns a 21-GW operating portfolio and more than 780 miles of high-voltage transmission lines, with more than 350 additional miles under construction or development.

“As an integrated business,” he said, “bp Wind Energy is a natural addition to Clearlight Energy’s growing portfolio of scalable solutions that will broaden our reach geographically and supports our strategy to make energy more efficient, affordable and available.”

The 10 wind farms, their location, their gross capacity and the percentage owned by bp are:

      • Fowler Ridge 1, Indiana: 288 MW, 100%
      • Fowler Ridge 3, Indiana: 99 MW, 100%
      • Flat Ridge 1, Kansas: 44 MW, 100%
      • Flat Ridge 2, Kansas: 470 MW, 100%
      • Titan, South Dakota: 25 MW, 100%
      • Cedar Creek 2, Colorado: 248 MW, 50%
      • Fowler Ridge 2, Indiana: 200 MW, 50%
      • Mehoopany, Pennsylvania: 141 MW, 50%
      • Auwahi, Hawaii: 21 MW, 50%
      • Goshen 2, Idaho: 125 MW, 50%

     

  • All but Auwahi are operated by bp Wind Energy North America.
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NEPOOL Reliability/Transmission Committee Briefs: July 15-16, 2025

RNS Rate Decrease

ISO-NE’s regional network service (RNS) rate is set to decrease by about 1% in 2026, dropping from $185.28/kW-year in 2025 to $183.71/kW-year in 2026.

The slight decrease in the rate primarily is the result of a regional true-up and a year-over-year increase in load, which lowered the unit rate, Jim Augelli, representing the region’s transmission owners, said at the summer meeting of the NEPOOL Reliability and Transmission Committees on July 15. He added that these factors were partially offset by ongoing transmission system investments.

The rate increased by about 20% in 2025, which the TOs attributed to increased revenue requirements. (See NEPOOL Reliability/Transmission Committee Briefs: Aug. 13-14, 2024.)

Over the next five years, the TOs forecast the RNS rate to increase to $220/kW-year by 2030, driven by growing transmission investments. However, the TOs reduced their RNS rate projections for 2027-2029 compared to the five-year forecast presented in 2024, lowering the forecasted 2029 rate from $217/kW-year to $210/kW-year.

Dave Burnham, also representing the TOs, stressed that the five-year forecast is based solely on “incremental revenue requirements attributable to forecasted capital investments” and “should be used for illustrative purposes only.”

According to the data presented by the TOs, asset-condition projects make up 72% of the forecasted regional investments in 2025 and 2026, accounting for about $1.67 billion of $2.31 billion in anticipated capital spending.

Rising asset-condition costs are a key concern of states and consumer advocates in the region, and ISO-NE is working to establish a new non-regulatory “asset condition reviewer” role at the RTO to help increase transparency and oversight on the spending. (See ISO-NE Open to Asset Condition Review Role amid Rising Costs.)

Costs Associated with FERC Order on Interconnection Complaint

Following up on a FERC ruling in December 2024 that TOs cannot charge interconnection customers for operations and maintenance costs associated with network upgrades, the TOs estimated that compliance with the order will increase the RNS revenue requirement by about $11.6 million and local network service revenue requirements by about $5.3 million across New England (EL23-16). (See FERC Sides with New England Developers on Interconnection Complaint.)

Regional Energy Shortfall Threshold

Also at the meeting, ISO-NE presented tariff changes associated with its proposed Regional Energy Shortfall Threshold (REST), which is intended to quantify “the region’s level of risk tolerance with respect to energy shortfalls during extreme weather.”

ISO-NE proposes to use the REST for short-term reliability assessments, performed ahead of upcoming summer and winter seasons, and for annual long-term assessments, looking five to 10 years into the future. The RTO plans to rely on two metrics, focused on shortfall magnitude and duration, to quantify shortfall risks against the threshold. (See ISO-NE Details Regional Energy Shortfall Threshold Metrics and “Regional Energy Shortfall Threshold,” ISO-NE Cuts Winter, Summer Peak Load Forecasts for 2033.)

The RTO plans to focus the REST on the 0.25% most extreme 21-day cases it evaluates and proposes setting the threshold at 3% shortfall magnitude and 18-hour shortfall duration. The REST would be violated if the probability-weighted average shortfall duration and magnitude of the tail cases exceeds these thresholds.

It plans to publish seasonal assessments in June and November, ahead of the summer and winter seasons, and long-term assessments in November.

ISO-NE will continue stakeholder discussions at the Reliability Committee meetings in August and September.

Order 2023 Conforming Changes

Alex Rost, director of interconnection services at ISO-NE, discussed potential changes related to deliverability assessments for resources not subject to the RTO’s interconnection procedures.

Rost noted that ISO-NE’s compliance with FERC Order 2023 “removed milestones related to the assessment of deliverability” and the establishment of capacity network resource capability (CNRC) for interconnecting resources under the RTO’s jurisdiction, adding that “these milestones now reside fully within the ISO interconnection process” (ER24-2009, ER24-2007).

Rost said ISO-NE will need to clarify its deliverability monitoring process for interconnecting resources not subject to the RTO’s interconnection processes in advance of the 2026 interim reconfiguration auction qualification process.

“The ISO is proposing to formalize the concept of ‘equivalent CNRC’ for all resources not subject to the ISO interconnection procedures … to avoid confusion when tracking assignment of deliverability capability,” Rost said.

ISO-NE also has proposed to align deliverability analysis screenings for non-RTO-jurisdiction resources with the deliverability screenings performed in interconnection cluster studies and would perform these screenings “right after the conclusion of a cluster study.”

Rost said the RTO is considering tariff changes to set milestones for resources seeking to establish “equivalent CNRC,” to ensure these resources “will likely achieve commercial operation.” He asked for feedback from stakeholders by the end of July on potential “demonstrable commitment milestones” for these resources.

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NY Steps Back from OSW, Halts Offshore Tx Planning Process

New York is pausing its ambitions and halting the planning of an underwater transmission network as President Donald Trump strangles the offshore wind sector. 

It is the latest of several states and developers to step back from such efforts since fall 2024. 

New York’s most recent solicitation for wind turbines remains in play, but it is behind schedule, and the finances of the proposals submitted in 2024 might be altered by the recent loss of tax credits. 

And of course, any of the proposals that rely on the planned underwater grid will need a different strategy. 

The New York Public Service Commission on July 17 shut down the process to build an underwater transmission network to bring electricity to shore from the hundreds of wind turbines the state hopes to see spinning off its coastline. 

With the Trump administration actively thwarting offshore wind development, the goal of 9 GW of offshore wind capacity by 2035 is out of reach, the PSC said. 

It became necessary to stop the planning of a transmission network to serve wind turbines that will not soon be built, lest New York ratepayers be liable for unknown and potentially large expenses. 

Unlike wind turbine developers, who begin to collect their ratepayer-funded subsidies only when their project enters commercial operation, the transmission developer would be eligible for cost recovery immediately — even if the wind turbines the wires were to connect to were delayed or never built, even if the wires themselves never were built, only planned. 

PSC Chair Rory Christian lamented the pause being placed on the state’s offshore wind program, which has been in the works for more than a decade. He blamed the Trump administration’s “deliberate and systematic action” to block offshore wind in New York and in other states. 

“We at the commission cannot in good conscience ask New York ratepayers to shoulder the cost and risk of a project where we know we’ll be stymied going forward,” he said. 

The early projects — South Fork Wind, Empire Wind 1 and Sunrise Wind — rely on radial lines, each sending their own export cable ashore in different locations. There is limited space for routing and landing such cables in the crowded downstate region, however, so the strategizing turned to a meshed design where multiple wind projects would use a single export line built through a separate transmission project. 

The now-withdrawn Public Policy Transmission Need (PPTN) was formally identified by the Department of Public Service in June 2023 (22-E-0633). It called for NYISO to solicit and evaluate proposals for a transmission project that could deliver 4.8 to 8 GW from multiple wind farms to NYISO Zone J (New York City). 

At the time, it seemed like New York had a good chance of achieving its 9-GW goal. But since then, little in the offshore wind sector has proceeded as state planners had hoped. 

Developers canceled contracts that no longer were viable and rebid them at much higher prices. An entire solicitation had to be canceled due to the specified turbine not being available. Proposals were withdrawn ahead of the 2024 presidential election and paused afterward. Trump’s Day One directive froze some development in U.S. waters outright and cast paralyzing uncertainty over other efforts. A federal stop-work order was slapped on Empire Wind 1 for a time. 

Most recently, the budget reconciliation bill throws future projects’ finances into turmoil by eliminating tax credits and introducing new challenges with foreign components. 

Against this backdrop, NYISO issued the PPTN solicitation in April 2024. NYISO reported in October 2024 that all 28 proposals received from four developers were eligible for evaluation. 

On June 25, NYISO presented an analysis to stakeholders showing that preliminary independent estimates of the cost of those projects ranged from $7.9 billion to $23.9 billion. 

NYISO was on track to potentially select a project later in 2025 under terms of the PPTN, which would result in costs beginning to accrue for ratepayers. 

DPS staff looked for ways to pause, modify or break the PPTN down into phases but found none. They recommended the PSC withdraw the PPTN. 

The commissioners voted 6-0 for this move July 17, and each expressed worry, frustration or even anger beforehand. 

“We live at a moment when a philosophical battle is going on between those vying to wield the levers of governmental power at all levels. The battle is not between right and left, but between empiricism and magical thinking,” Commissioner John Maggiore said, adding: 

“But we should not respond with our own form of magical thinking — sustaining a zombie process that could result in transmission lines to nowhere will not help us achieve our 9 GW legal mandate. It will just end up costing already-stressed ratepayers more money for which they will get nothing in return.” 

Christian said the state remains convinced of the importance and value of offshore wind but must defer it to a future where federal policy is more supportive. 

Offshore wind has been a centerpiece of New York’s decarbonization strategy, but it is only one piece, he said: “In the meantime, we have to focus our attention on building the clean energy infrastructure we can, to advance to completion while remaining focused on progress toward meeting the state’s goals.” 

The New York State Energy Research and Development Authority, a lead agency in the energy transition and manager of the offshore wind solicitations, said later July 17 that it will use this pause to refine its efforts to support the industry in New York State and engage with stakeholders and the supply chain. 

It also said it’s continuing to process its fifth wind solicitation, which attracted four developers in 2024 and is lagging behind the expected timeline for completion. 

Many stakeholders and interested parties who submitted comments to the DPS about the PPTN earlier in 2025 had urged that the PSC not give up on it. 

Some expressed regret that it did. 

“Now is not the time for us to hold back the potential contribution of any energy source,” Turn Forward Executive Director Hillary Bright said. 

The New York League of Conservation Voters said it was deeply disappointed. “While the federal government continues to undermine progress on clean energy, New York should be doubling down on our commitment to become energy independent, not stalling it.” 

The Alliance for Clean Energy New York and its New York Offshore Wind Alliance said: “Offshore wind projects can take more than a decade to develop, spanning far beyond state and federal election cycles. We encourage New York State to continue developing infrastructure in the near-term that will enable new generation to come online, addressing reliability and affordability for New Yorkers.” 

Christian acknowledged these sentiments before the vote but said ignoring the Trump administration’s hostility to offshore wind would be “incredibly risky” for ratepayers: “Offshore wind is unique in that the federal government has a direct permitting and financial role, and the federal government has repeatedly and deliberately withdrawn its support.” 

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SPP Adds OG&E’s Shuart to External Affairs Leadership

SPP has bolstered its external affairs group in the face of massive industry changes by plucking Emily Shuart from Oklahoma Gas & Electric, where she compiled more than 20 years of experience in federal and state regulatory and legislative affairs, energy policy and stakeholder relations.

Shuart will take over as the RTO’s senior director of external affairs and stakeholder relations, effective Sept. 2. She is expected to work closely with Mike Ross, senior vice president of external affairs, in leading SPP’s engagement with government officials, legislators, industry organizations and stakeholders.

“Emily brings an outstanding track record of leadership in energy policy and stakeholder engagement,” Chief Strategy Officer Kevin Bryant said in a July 17 press release. “Her expertise will be instrumental in helping SPP foster productive dialogue with our partners and communicate the value we bring to the region.”

Carrie Dixon | SPP

Shuart, who will report directly to Bryant, most recently served as director of federal, RTO and environmental affairs for OG&E and represented the company on SPP’s Members Committee. She holds a bachelor’s degree from Baylor University and a law degree from the University of Oklahoma.

The grid operator also promoted Carrie Dixon as technical director, market policy and operations. She will help align the coordination and development of market policies with SPP’s goals, tariff and other governing documents amid the evolving national regulatory and industry landscape. The move is effective Aug. 4.

Dixon joined SPP in 2024 and currently serves as market policy principal in support of Markets+. She has more than 15 years of electric utility experience, holding leadership positions at NextEra Energy and Xcel Energy. She represented both companies in various SPP stakeholder groups.