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November 26, 2025

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ISO-NE Provides More Detail on Responses to LTTP Procurement

ISO-NE has published a summary of proposals submitted for its first longer-term transmission planning (LTTP) procurement, which is aimed at reducing transmission constraints between Maine and southern New England and supporting 1,200 MW of new onshore wind in northern Maine.

The solicitation is the first run of ISO-NE’s new LTTP process, which the RTO and the New England states established to select solutions to needs identified in long-term transmission studies. (See FERC Approves New Pathway for New England Transmission Projects.)

Four project sponsors responded to the first LTTP procurement, submitting six proposals in total. The proposals represent “a good diversity of solution designs,” ISO-NE said.

The cost projections range from $962 million to $4.04 billion, though these projections may change as the bidders and ISO-NE work to standardize the cost calculations. The expected in-service dates range from the fourth quarter of 2032 to the third quarter of 2035.

Four of the six projects are joint proposals submitted in collaboration with incumbent transmission owners. ISO-NE has not disclosed the identities of the companies that participated in the solicitation but noted that three of the lead project sponsors are incumbents and one is a non-incumbent.

Three of the submissions propose new HVDC lines running from Maine to Massachusetts, along with new and upgraded AC infrastructure. These proposals are:

    • A 151-mile 400-kV line between Wiscasset, Maine, and Everett, Mass., with a total cost of $2.55 billion.
    • A 144-mile 400-kV line between Wiscasset and Wakefield, Mass., projected to cost $2.6 billion.
    • A 164-mile 320-kV line between the retired Maine Yankee Nuclear Plant (in Wiscasset) and the retired Mystic Generating Station (in Everett), with an expected cost of $4.04 billion.

The three other proposals rely on new AC lines and line upgrades. They are:

    • A $2.2 billion proposal to build two new 345-kV lines totaling 70 miles, upgrade 16 miles of 115-kV line in Maine to 345 kV and upgrade existing 345- and 115-kV lines throughout Maine and New Hampshire.
    • A $2.14 billion proposal that is nearly identical to the prior proposal, but with a reduction in total mileage of 345-kV upgrades.
    • A $962 million proposal that includes a new 43-mile 345-kV line and three new substations.

ISO-NE said all the proposals claim to meet the minimum requirements of the RFP, which are to increase the Maine-New Hampshire interface limit to 3,000 MW and the Surowiec-South limit to 3,200 MW and support the interconnection of 1,200 MW of onshore wind in northern Maine.

For context, when the New England Clean Energy Connect transmission line is online — it is expected to achieve commercial operations this winter — the Surowiec-South limit will be 2,800 MW and the Maine-New Hampshire limit will be 2,200 MW.

ISO-NE said some proposals claimed to increase the limits beyond the minimum requirements. The RTO noted that it received proposals to increase the Surowiec-South limit to 3,800 MW and the Maine-New Hampshire limit to 3,600 MW.

All proposals would build a new substation near Pittsfield, Maine, to enable a 1,200-MW injection of onshore wind. No submissions proposed infrastructure that would accommodate more than the required 1,200 MW of offshore wind.

Separate from the LTTP process, Maine is seeking to procure 1,200 MW of wind in northern part of the state, along with transmission to connect the power to the proposed Pittsfield interconnection point in central Maine. Maine officials have expressed hope that other New England states will join in the solicitation.

Maine issued a draft RFP for this procurement in October 2025 (PUC Docket No. 2024-00099), noting that the procurement “is designed to leverage the LTTP solicitation and is contingent on ISO-NE selecting a longer-term transmission upgrade project.”

To select a preferred solution in the LTTP process, ISO-NE will review the projects to ensure they meet the minimum requirements, evaluate effects on other interfaces and screen for adverse system impacts.

ISO-NE also will rely on a consultant to evaluate the financial health of the project sponsors, the feasibility of the construction proposals and the cost estimates. The RTO will rely on the participating transmission owners to estimate the costs of corollary upgrades.

For projects that meet all the requirements, the RTO will quantify costs and benefits. (See ISO-NE Releases Longer-term Transmission Planning RFP.) Projects must have a positive benefit-to-cost ratio to be eligible to be selected by ISO-NE as the preferred solution.

ISO-NE said it expects to select a preferred solution by September 2026, noting that it is “cautious about committing to an earlier date” because the RFP “involves utilizing numerous new processes.”

By default, the costs of a solution would be allocated by load, though the states could submit an alternative cost allocation methodology or opt to terminate the process following ISO-NE’s selection.

If no proposals pass the benefit-cost threshold, the LTTP process allows one or more states to cover a project’s costs that exceed the threshold, enabling it to proceed.

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GridEx Participants Report No Disruption from Shutdown

The federal government shutdown had “no notable impact” on logistics or planning for the upcoming GridEx VIII grid security exercise. ERO stakeholders, including Michael Ball, the new CEO of the Electricity Information Sharing and Analysis Center, said during a Nov. 17 media call.

GridEx VIII runs Nov. 18-20, with the first two days dedicated to a distributed play portion and an executive tabletop scheduled for the final day.

Both sessions are based on a scenario “designed to reflect real-world cybersecurity and physical threats,” Ball said. The scenario includes climate change impacts such as wildfires and heat domes, and attacks coinciding with a major world sporting event, an E-ISAC official told a NERC committee in September. (See E-ISAC Updates NERC Committee on GridEx VIII Scenario.)

“Well over 15,000 participants” from more than 370 organizations have signed up to participate in this year’s exercise, Ball said, a significant increase from the 252 organizations that took part in GridEx VII in 2023. (See NERC Flags Communication, Coordination in GridEx VII Report.) Ball called the growth “a real testament to engagement by small- and medium-sized utilities,” which comprised 70% of the new participants.

Canadian involvement is up from the last GridEx as well, Ball said, reflecting “the interconnectedness between Canadian and U.S. operations.” The CEO also emphasized the involvement of companies across the “broad spectrum of interconnectedness with other [critical infrastructure] sectors,” particularly natural gas, water, wastewater and telecommunications.

“I think what’s really important is cross-border [engagement], not just in North America, but across industries … makes us even stronger,” Bell said. “That’s going to be an aspect of this [exercise], and it’s really an important mission overall … to ensure that reliability and resilience of the [grid], and its significant ties into the grid security focus.”

Tim Kocher, deputy director of the Department of Energy’s Office of Cybersecurity, Energy Security and Emergency Response, echoed Bell’s comments, saying that partnerships both within and beyond the energy sector “are crucial to the work that we do to advance energy … security and resilience across the board.”

“Just in 2023, CESER … sponsored or participated in 36 energy sector exercises … across cyber, physical and natural scenarios,” Kocher said. “So we know that it takes all of us coming together, each with our own authorities on the government side and capabilities with our energy sector partners to prepare for and respond to the complex threats facing the sector today. Ultimately, GridEx is not just an exercise: It’s a national commitment to resilience.”

Along with the government shutdown, GridEx VIII will also happen in the wake of significant changes to the critical infrastructure security picture, such as the expiration of the Cybersecurity Information Sharing Act of 2015 on Sept. 30 and the Trump administration’s decision to terminate the Critical Infrastructure Partnership Advisory Council in March. (See Lawmakers Divided on CISA 2015 Reauthorization.)

Ball acknowledged that the E-ISAC had “certainly tracked” the end of CISA 2015, but the law’s temporary expiration — it was renewed through Jan. 30, 2026, as part of the continuing resolution signed by President Donald Trump on Nov. 12 — had caused “no impact to the level of [information] sharing or design of the scenario.”

Edison International CEO Pedro Pizarro added that the administration had “efforts underway to consider replacements for” the information sharing protections in both CISA 2015 and CIPAC. Tri-State Generation and Transmission Association CEO Duane Highley said that during a “recent cyber incident,” his organization had found that “all those channels of communication” with the E-ISAC and the federal government remained “open throughout the shutdown.”

“This is critical stuff, and it still works,” Highley said. “So despite the [termination of] CIPAC, we still have means of being able to communicate those threats and share them.”

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PJM Stakeholders to Vote on Large Load CIFP Proposals

PJM stakeholders are to vote on a record-breaking number of proposals on how the RTO should integrate large loads without impacting resource adequacy. (See PJM Stakeholders Present CIFP Options for Meeting Rising Data Center Load.)

A dozen packages of changes are to be voted on at a special Members Committee meeting Nov. 19, which will immediately follow the Critical Issue Fast Path (CIFP) stage 4 meeting, in which sponsors will present to the PJM Board of Managers. The voting will be advisory to the board, which outlined its intent to direct PJM to make a December filing on a path forward for large loads in its letter initiating the CIFP process. The stage 4 meeting is closed to the media.

The bulk of the packages mix and match elements of several design components that have been developed across 10 meetings held since August.

Bring-your-own-generation or capacity (BYOG or BYOC) would incentivize, or require, new large loads to have resources to serve themselves. This could take the form of expedited interconnection, penalties for large loads that don’t self-supply or prohibiting interconnection. Proposals differ on whether the resource can be existing or must be new, as well as whether it must be located adjacent to the load.

Instituting queues for large loads also features prominently in some proposals, requiring them to hold off on interconnection until there is sufficient capacity to serve them or they procure their own capacity. Opponents have argued these models could impinge on state jurisdiction over retail interconnection.

Load flexibility would allow large loads that agree to curtail similar to demand response to either qualify for expedited interconnection or subject them to mandatory curtailment under new emergency procedures if they do not bring their own generation. Some proposals include limited-duration products with a maximum number of hours a customer could be dispatched during one event and across a delivery year. In the executive summary of its proposal, PJM said limited-duration DR would not be implementable until the 2029/30 Base Residual Auction (BRA).

PJM’s original CIFP proposal featured a mandatory non-capacity backed load (NCBL) model in which large loads would not pay for or receive firm service unless they brought their own generation; the RTO has dropped that concept, but versions have been adopted in alternative packages.

Bifurcating the capacity market would add a second phase to auctions where large loads would clear after all other RTO loads, potentially receiving a higher clearing price. They differ on whether the resources participating in the second phase would be limited to new resources or could include existing assets.

PJM Proposal

PJM’s proposal would create a 10-month expedited interconnection pathway for state-sponsored resources, with reduced readiness deposits for projects paired with large loads. It would also rework how price-responsive demand (PRD) is dispatched and add state review of large load adjustments (LLAs) before PJM determines if they will be included in its load forecast.

The RTO lowered the threshold for projects to qualify for the proposed expedited interconnection track (EIT) from 500 MW to 250 MW, which several stakeholders requested to allow a broader range of projects to qualify. It opted to retain the state-sponsorship element, requiring a letter from either the governor or siting authority for the state the project is in demonstrating “commitment to expedite consideration of permitting and siting.”

The requirements were loosened to allow standalone and uprate projects, not just resources paired with large loads. The readiness requirements for unpaired projects would be doubled at $20,000/MW. The resource in a paired configuration would need to be at least as large as the load, which would be required to have a signed electric service agreement (ESA) with its utility.

The changes to the load forecast would require utilities submitting LLAs to ask the customer requesting service if its project is duplicative of any other requests for service at different locations and, if so, to specify the number of sites and the share of the load that is duplicative. A concern that has been voiced throughout the discussion is that a significant portion of the load expected could include speculative or exploratory interconnection requests.

Outside review of PJM’s forecast would also be added, empowering the RTO to bring on a third-party to conduct a broader analysis of how its estimates fit into the broader national picture.

The changes to PRD would replace the dynamic retail rate with an energy market bid price and align the resource class with DR by requiring it to respond to dispatch regardless of bid price, subject it to performance assessment interval penalties and mirror their 30-minute energy bid price caps.

The proposal includes a request for the board to initiate a second phase of the CIFP process focused on changes to the reliability backstop and incentives for large loads to bring their own generation or participate in DR programs.

“To solidify such incentives, it will be important, among other things, to ensure that loads are prioritized appropriately when load shedding is required in order to maintain supply and demand balance in real-time operations,” PJM wrote.

IMM Proposal

The Independent Market Monitor’s proposal would establish a large load queue, in which PJM would study the projects for impacts to transmission security and resource adequacy. If a project is determined to compromise either, it would be prevented from coming online until the issue had been mitigated by network upgrades, new resources entering the capacity market or the load bringing new capacity covering its demand plus the reserve margin.

There would be an expedited interconnection pathway for BYOC resources, which would be required to go online at the same time as the load. Full deliverability would be mandated both to the customer and the PJM system.

In its executive summary, the Monitor said participation in PRD and DR does not provide the same value as new generation and would not count toward the BYOC process. The high strike price for PRD and Capacity Performance penalty structure do not present sufficient incentives for demand-side resources to regularly be deployed. If DR was to qualify, it would need to be dispatchable any time capacity is needed with no run hour limits, which could result in frequent deployments if forecasts of 30 GW of data centers are correct.

The Monitor stated that if PJM does not believe it has the authority to hold off on interconnecting load it cannot reliably serve, the RTO should seek clarification from FERC. Defending its position against arguments that putting requirements on large loads would be discriminatory, it argued the proposal would prevent one set of customers from shifting costs onto others.

“The options that accept the premise that PJM must interconnect new large data center loads that cannot be served reliably means by definition that reliability will be degraded. PJM will be in the position of allocating blackouts rather than ensuring reliability,” the Monitor wrote.

Joint Stakeholder Proposal

A joint package from Amazon, Calpine, Constellation Energy, Google, Microsoft and Talen Energy aims to improve the accuracy of the load forecast, create new forms of load flexibility and establish an alternative reliability backstop that would trigger if a capacity auction clears below 98% of the reliability requirement.

Large loads would be required to demonstrate they have made financial commitments supporting their interconnection before they are fully reflected in PJM’s load forecast. That can include entering into ESAs, funding infrastructure, entering into bilateral transactions for capacity or credit support. The ramp rate and utilization of the new load would also be captured in forecasting, and protections against double-counting projects would be added, as well as a “reality check” overview of PJM’s forecast comparing it to national trends and the availability of equipment needed for data center construction.

Two new voluntary DR products would be available for large loads that can provide some flexibility with a cap on the amount of curtailments they see in a year. The first would be limited to six-hour deployments with a maximum of 24 hours in a year, and the second would allow 10-hour deployments capped at 100 hours per year. The effective load-carrying capability (ELCC) rating for the products would be reduced compared to standard DR to reflect the lower availability.

Another form of DR would be created for large loads with backup generation, which would curtail their grid service as the final emergency procedure before manual load dump. The product would likewise have its ELCC rating reduced to account for the fewer deployments.

The alternative reliability backstop would allow certain resources to submit capacity offers for up to seven-year terms. Eligible resources would be new or reactivated resources; existing resources with offers higher than the maximum price for the BRA that cleared short; and traditional DR. The clearing price they receive in subsequent auctions would remain the same, and there would be prioritization for selecting offers with shorter commitment periods. It would be effective through the 2031/32 BRA and then sunset.

Data Center Coalition, Utility and Governor Proposal

Building off PJM’s proposal, an alternative from the Data Center Coalition (DCC), Exelon and PPL, as well as the governors of Maryland, New Jersey, Pennsylvania and Virginia, would add financial requirements for LLAs, introduce a limited DR product and loosen the requirements for EIT projects. It would also extend the collar on capacity market clearing prices by one year to the 2028/29 BRA to stabilize prices while the changes are implemented. (See FERC Approves PJM-Pa. Agreement on Capacity Price Cap, Floor.)

Large loads would be required to provide an ESA or transmission security agreement or pair with an EIT project to be included in the forecast, as well as provide information about potential duplication of their load and characteristics such as ramp and utilization rates.

The limited DR product would be capped at between 24 and 240 hours of curtailment a year and could specify daily maximums as well. Large loads could also opt-in to a voluntary program where they would be curtailed as the final emergency procedure before manual load dump.

In response to stakeholders arguing that any new DR products should be curtailed at the same time as existing DR participants, package sponsors said that would be the case with the limited DR option, while the additional emergency procedure would exist outside the DR paradigm.

The EIT rules would be relaxed to allow multiple resources to serve one large load, allow resources that would otherwise deactivate to qualify, resources that did not clear in the capacity market and generators switching their fuel type. The 10-per-year limit on EIT projects and minimum output qualification would both be removed.

PJM would be required to explore changes to its energy resource interconnection service pathway as an alternative for resources seeking faster time to market without immediately providing capacity.

Protecting Ratepayers Proposal

The Protecting Ratepayers proposal from the Natural Resources Defense Council and dozens of state legislators is based on the DCC proposal but would remove large loads from the capacity market and prevent them from receiving firm service unless they procure their own capacity.

Interruptible service would be allocated to states based on the amount their load exceeds committed capacity, with the relevant electric retail regulatory authority (RERRA) allocating interruptible service to customers, similar to PJM’s NCBL model.

New resources could be expedited through the bilateral integration of generation portfolios and load (BIGPAL) model proposed by Eolian Energy in the second phase of the CIFP. Resources adjacent to a large load would qualify for a shortened study process, bypassing full deliverability to the grid and forgoing capacity interconnection rights (CIRs). Participating resources could enter the standard interconnection process to receive CIRs. (See “Eolian BIGPAL Proposal,” PJM Stakeholders Present CIFP Options for Meeting Rising Data Center Load.)

Large loads could also receive firm service through participation in PRD or DR programs or by contracting other consumers in the same locational deliverability area to participate on their behalf. The limited DR product in the DCC proposal is copied over.

PJM would hold off on purchasing an amount of load in the BRA that matches the amount of new generation it expects to be completed by the third Incremental Auction, at which point the held back capacity would be purchased.

The proposal calls on PJM to initiate a stakeholder process for large loads to fund network upgrades needed for their interconnection.

Consumer Advocate Proposal

The consumer advocates for Pennsylvania and Maryland proposed a mandatory BYOC model in which load-serving entities would be required to report the amount of contractually committed LLAs they have and procure new capacity to serve them.

“A mandatory backstop ensures that service interruption to existing customers is minimized, while allowing LSEs to serve LLAs. If the stakeholders supporting voluntary BYOC are correct that LLAs will voluntarily bring sufficient capacity, then the proposed mandatory requirements and backstop would be harmless discipline at a time when clear rules of the road are needed,” they wrote in their executive summary.

The BYOC resources would participate in the capacity market and be subject to CP penalties if they do not meet their obligations during an emergency.

States would be able to participate in a pre-emergency curtailment program for large loads, which the advocates said would reduce the risk of manual load dump in those regions.

“If these curtailments do not happen because [electric distribution companies]/states opt not to align and coordinate with PJM in protecting residential consumers, this would mean that manual load dumps will likely affect LLAs concurrently with existing residential, commercial and industrial consumers, which can exacerbate the duration and recurrence of blackouts for residential consumers,” they wrote.

Dominion Proposal

Dominion Energy Virginia’s proposal seeks to orient capacity around bilateral transactions and re-establish BRAs making up any residual needs.

The proposal would require utilities to procure new capacity for at least 70% of LLAs in the BRA for which those loads are participating and to purchase the remainder in the third IA. Utilities that fail to do so would be subject to an insufficiency penalty equal to the maximum price for that auction times the shortfall between its capacity obligation and procurement.

“The objective of the penalty design is to incentivize [load entities] to proactively procure new generation capacity to meet their new large load additions and to not rely solely on the BRA. A behavioral change in how capacity is secured for new large loads is necessary for the [capacity market] to remain a functional and viable market for existing load,” Dominion wrote in its executive summary.

The proposal would modify the EIT to include resources being constructed through state integrated resource plans and projects already proceeding through the standard interconnection cycles that meet the EIT participation requirements.

Dominion wrote that PJM’s existing LLA process balances protecting consumers against speculative service requests in near-term forecasting without being overly conservative and allowing EDCs to have discretion on the loads they believe should be included in the long-term analysis. It supports adding a third-party review of the assumptions around data center load, so long as utilities are able to provide input on any changes PJM would make. It said the Independent State Agencies Committee is the proper venue for state regulators to review LLAs.

EKPC Proposal

The East Kentucky Power Cooperative proposed a model that aims to assign the risk associated with large growth to the utilities, LSEs and EDCs that serve them. It would establish a collateralized penalty for those that enter a BRA without enough supply, including imports, to meet its demand.

The penalty rate would be set at 1.5 times the BRA clearing price times the amount of new large load. The revenue would flow to utilities that did procure sufficient capacity.

The proposal adopts PJM’s load forecasting changes and EIT model, though it would remove the state sponsorship requirement for expedited resources. Large loads would not be included in PJM’s forecast until the utility that will serve them has been identified. In its executive summary, EKPC supported Dominion’s modifications to EIT.

Recognizing that the 2026 Load Forecast is already well underway, the cooperative proposed to hold a midterm adjustment to implement the LLA forecasting changes for the 2029/30 BRA.

The cooperative opposes PJM’s load flexibility components, stating that the mechanism for curtailing PRD is unclear and participants receive firm service funded by other customers.

LS Power Proposal

A proposal from LS Power would bifurcate the capacity auction to first clear existing “organic” load and large loads paired with new generation, then run a second phase to clear new large loads without contracted generation. The latter would pay an entry fee of about $1,800/kW.

It includes a seven-year price lock that resources can opt in to for longer commitment periods, which the executive summary said would address hesitation that investors may have when using one-year price signals to determine whether to back projects with long construction and capital recovery timelines.

An expedited interconnection process for dispatchable resources with ELCC class ratings above 60% is included, with lower entry fees for pairing with large loads.

DR Coalition Proposal

A coalition of DR providers will present a package that largely mirrors PJM’s proposal while adding a limited DR product available between 24 and 100 hours a year. It also adds DR to PJM’s BYOG model for LLAs seeking to be included in the load forecast as an offset.

PSEG Proposal

A proposal from Public Service Enterprise Group includes a modified version of the EIT without the state sponsorship requirement, substituting a site control requirement for the three-year in-service qualification, and a trigger for when it is effective.

The utility wrote that only initiating the EIT when there is a resource adequacy need would prevent impacts to cluster projects, and that being able to maintain site control is a preferable metric for determining that a project will be constructed. The proposal would also replace the 10-per-year limit on EIT projects with a state-by-state limit.

The proposal would break data center load out in PJM’s load forecast, with an outside consultant contracted similar to how electric vehicle load is analyzed. PJM’s guidance for LLA requests is included as a component, requiring that large loads have an ESA or construction commitment to be included in the three-year forecast and adding characteristics like ramp rates to the information utilities should include.

PSEG wrote that data center developers and operators are not PJM members and therefore not subject to the RTO’s rules around load forecasting, adding that only they can know whether a project is speculative.

The proposal calls for an issue charge for a second phase of the Sub-Annual Capacity Market Senior Task Force to explore how a sub-annual capacity market design could be implemented. The task force is currently charged with reviewing the work of a consultant drafting a report on the topic.

SMECO Proposal

The Southern Maryland Electric Cooperative proposed a variant of PJM’s proposal modifying its PRD components.

It would lower the strike price to $1,000/MWh, compared to PJM’s $1,849, and only subject PRD participants to CP penalties if the resource is dispatched when the strike price or PAI conditions have not been met. It would also require that the PRD provider have supervisory control over the load and the ability to curtail.

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‘There’s Room for Everybody’: California Ports Prepare for OSW Development

At a two-day workshop held by the California Energy Commission, offshore wind experts and fishermen identified challenges associated with building offshore wind turbines in Humboldt Bay and other parts of the coastline while not displacing the fishing industry.

Recent federal policy changes have left the future of the renewable energy resource in limbo, but California officials continue to push ahead with offshore wind design and development plans. (See CEC Approves 5 Offshore Wind Projects at California Ports.)

At the CEC’s Nov. 13 workshop, engineers, fishermen, developers and port officials, among others, talked about the path towards a future in which offshore wind turbines send electrons to the Golden State’s grid.

“It really takes a lot of our California ports working together to be able to realize this vision,” said Matt Trowbridge, a vice president with infrastructure design company Moffatt & Nichol.

No existing port terminals along the West Coast can support the equipment that’s needed to build offshore wind facilities, he said.

“How much of these manufacturing sites that are building the components needed for offshore wind are going to be in the U.S. and in California, and how many are going to come from other places?” Trowbridge asked. “What’s the right amount of in-state fabrication that will allow this industry to move?”

The fishing industry wants certainty that it will continue to be a viable career for people when offshore wind farms operate in the state.

“Fishing is one of the oldest industries in the United States,” said Ken Bates, vice president of the Humboldt Fishermen’s Marketing Association. “For old fishermen like me and the younger guys that are looking at this, nobody understands how they’re going to survive ocean industrialization.”

Humboldt Bay is the second-largest estuary in California and a huge nursery ground for tons of commercial species, he said.

Ports are the starting and stopping point for fishing operations: When fishing boats come back into the port, “there’s a whole other set of things that they require to keep their businesses running and to get the fish processed for the customer,” Bates said.

“And in the last 25 to 30 years, the priority of the fishing industry and its position in the pecking order, has moved down and down and down. Do we place any value on having a fish processing plant in a little port? There’s room for everybody.”

Another challenge with building offshore wind in California is ensuring that wind farm developers have more certainty about the amount of transmission infrastructure that will be available for offshore projects, said Martin Christensen, senior onshore works manager with Vineyard Offshore.

The Humboldt region does not have enough transmission capacity to bring the power from offshore wind projects to load centers, Christensen said.

“Right now, I think Humboldt can only accept, like, 150 MW, and our project’s going to be between 1 and 2 GW,” Christensen said. “The math just doesn’t add up.”

Most existing offshore wind farms are built with fixed-bottom turbines, which anchor using piles or truss jackets, Trowbridge said. But in the Pacific Ocean, the outer continental shelf drops off near California’s coastline, which makes fixed-bottom turbines inadequate. California will need to therefore install floating turbines that connect to the seabed using mooring lines and anchors.

CEC Approves Port Funding

At the CEC’s Nov. 12 business meeting, the commission approved about $9.2 million for research on deepwater HVDC substations and ocean monitoring methods capable of detecting entangled debris.

As part of the funding, Alliance for Sustainable Energy will develop a standardized concept design for a floating HVDC substation. California’s offshore wind farms may be in water that is 1,800 to 4,300 feet deep, making fixed-bottom substations infeasible, the CEC’s resolution says.

HVDC equipment can be affected by the motions of a floating platform, so an HVDC substation’s mooring system must be designed to constrain the motions. This design results in a complex system engineering problem that requires balancing considerations in platform stability, HVDC equipment robustness, mooring stiffness and cable excursions, the resolution says.

Alliance for Sustainable Energy will develop the first open-source floating HVDC substation design, which should reduce the cost of the substations and make them less environmentally harmful.

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State Regulators Ponder Federal Role in Large Load Interconnections

SEATTLE — The Trump administration’s push to give FERC jurisdiction over large load interconnections could leave the agency biting off more than it can chew around complex state-run processes, while failing to accomplish the intended goal of speeding approvals of hyperscale data centers.

That was a top takeaway from a Nov. 12 panel discussion on the role of U.S. states in the permitting of “critical” energy infrastructure, held at the National Association of Regulatory Utility Commissioners annual meeting in Seattle.

The discussion among state regulators replaced a previously scheduled meeting of the Federal and State Current Issues Collaborative on the same topic, which was canceled because FERC representatives were restricted from travel because of the federal government shutdown.

The context of the discussion was shaped by Energy Secretary Chris Wright’s Oct. 24 Advance Notice of Proposed Rulemaking (ANOPR), which seeks for FERC to extend its authority to include the interconnection of large loads. The NARUC conference featured passage of a resolution pushing back against that effort. (See Regulators Urge FERC to Honor State Authority over Large Load Interconnections and DOE Request to FERC on Large Load Interconnections May Further Limit State Powers.)

Virginia State Corporation Commission Judge Kelsey Bagot kicked off the panel saying state and federal regulators mostly seek the same outcome in the large load interconnection issue, “which is this idea of speed to power.”

But Bagot posed the key question confronting regulators facing the potential for massive load growth in their states: how to ensure permitting is “as efficient as possible” without “losing out on the really important pieces that underlie why we have this permitting process in the first place” — namely protections around customer affordability, livability and the environment.

Panel participants raised crucial points, including:

    • State permitting of transmission and energy resources needed to interconnect large loads entails a highly complex process that includes not just utility commissions but environmental agencies, siting boards, localities, community groups, Tribes, landowners and various kinds of utilities.
    • Those permitting processes are efficient, often being completed within a year.
    • FERC may not be equipped to take on the added responsibility of such complex processes, often rooted in local concerns, and its control could invite more protests and delays of projects.

‘Extremely Complicated’

Florida Public Service Commissioner Gabriella Passidomo Smith emphasized how her state already prioritizes speed in permitting. She noted Florida has three different statutes covering the siting of natural gas infrastructure, power plants and transmission lines.

“These siting acts really address the environmental impacts of power plant, transmission line and natural gas pipeline construction and operation, with the primary goal of streamlining the permitting process while ensuring the protection of Florida’s natural resources,” Passidomo Smith said.

While the Florida Department of Environmental Protection is the lead agency for siting permits, the process includes the Department of Economic Opportunity, the Florida Fish and Wildlife Conservation Commission and a siting board comprised of the governor and the cabinet.

Throughout the process, Passidomo Smith said, affected local governments can provide land-use consistency determinations, with regional planning councils and water management districts participating in the review.

The role of the PSC, she said, is to be the first stop to determine need for new capacity after a generation or load-consuming project has been proposed. The proposal starts a 45-day clock for the commission to hold a hearing, followed by a requirement to issue a determination within 60 days of the hearing.

Certain transmission projects can be “extremely complicated, if you’re talking about going through conservation land, tribal lands,” she said. “You might just have one property owner and a NIMBY issue that could be involved. You know, it could be simple; I think it increasingly is less so.”

Illinois Commerce Commissioner Stacey Paradis said she was speaking for fellow commissioners in the Mid-America Regulatory Conference region in saying they want to ensure efficient permitting. But they’re also “very interested in maintaining state control” over large load interconnections and are concerned that local community engagement could be lost through federal control over the process.

Paradis said Illinois law sets specific requirements for public participation, stakeholder engagement, environmental assessments, and public and evidentiary hearings before the commission can act on an application.

She noted the ICC in the past decade has taken on responsibilities related to integrated resource planning, resource adequacy, the siting of solar, the development of new nuclear resources and the examination of pipeline siting. That’s all part of a state strategy to consolidate energy-related processes within one agency, although the ICC also works with sister agencies such as the Illinois Power Agency, Illinois EPA and the state Department of Natural Resources.

Despite that workload, Paradis said that in the past 15 years, the ICC has completed permitting on every electricity-related project within 365 days.

“So, all of that moves still relatively quickly, even though we have those five stages,” she said.

Single-size Permitting

Bagot, who previously worked as an attorney at FERC, pondered how Virginia’s process of permitting a high volume of large load projects would compare under federal authority.

Bagot said under existing practice the SCC has authority to issue certificates for public convenience and necessity (CPCNs) for nearly all projects rated at 115 kV and above. While the state’s Department of Environmental Quality is separately responsible for environmental reviews, its findings are incorporated into SCC’s CPCN proceeding. She said Virginia’s process gives localities a “strong role” in the permitting process.

Bagot said that while Virginia has no statutory deadline for the SCC to issue a CPCN, the agency’s typical timeline has been eight to nine months, which doesn’t include “the random exception here or there for particularly challenging projects” or instances when a utility itself seeks alternative routes after local feedback.

“So, to the extent the process is delayed, it’s often on the part of the utility after community engagement, and they’ve come to some resolution, and want to make sure that that resolution is reflected in the filing, which we obviously want to encourage, because those types of solutions, I think are a win-win for everybody,” she said.

Bagot pointed out that, over the past three years, the SCC has received about eight to 20 transmission CPCN applications annually, compared with FERC dealing with 15-20 natural gas CPCN applications a year in the same period.

“They’re doing about the same amount of certificates each year as the Virginia commission is doing for transmission, and that’s just one of many states,” she said. She added that she wants to understand what amount of resources and staff FERC or another federal agency would require “to really engage meaningfully in these permitting processes for transmission to the extent it is smooth.”

The rapid spread of data centers has made transmission siting in Virginia’s “Data Center Alley” in Loudoun County particularly contentious. The process requires much more engagement with increasingly sophisticated community groups to negotiate solutions, which reduces the kind of appeals and litigation risk that slows projects, Bagot said. She added that states “are working very hard” at the legislative and commission levels to make processes “as efficient as possible.”

“I don’t want to lose the progress that’s there in search of the sort of one-size-fits-all solution that may or may not result in faster permitting processes, or permitting processes that may be faster on the front end but end up tied up in litigation for many, many years,” Bagot said.

‘Strong Track Record’

Pointing out that Virginia is “an outlier” in the number of transmission requests the state is fielding, Washington Utilities and Transportation Commission (UTC) Chair Brian Rybarik still echoed Bagot’s concern that FERC would be shouldering “a lot” in assuming authority over large load interconnections in every state.

But more important was Bagot’s “one-size-fits-all” concern about a federal process, Rybarik said.

“How do you get that connection to the landowners that are actually being impacted?” he said. “The energy transition, load growth, everything we’re seeing, is a really important thing for the country, but it affects a certain number of people a lot more than others, and so we really need to make sure that we make that connection to everybody.”

On the topic of state permitting of transmission, Rybarik said that while critics among industry stakeholders “tend to focus on the negative,” Washington’s Department of Ecology approves 83% of applications that come before the agency.

“I think that’s a pretty strong track record to look at. We can focus on the outliers for the negative, but it really is working well, and states are working well to move these things forward,” he said. “Agencies like the UTC are bringing leaders together and asking our stakeholders, ‘How can we advance our processes?’”

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NYISO Meeting Briefs: Nov. 10-13, 2025

Operating Committee

Aaron Markham, NYISO vice president of operations, presented the 2025-2026 Winter Capacity Assessment and Winter Preparedness forecasts to the Operating Committee on Nov. 13.

The ISO found that 29,893 MW of resources are available to meet a forecasted peak demand of 24,200 MW. The peak last winter was on Jan. 22, 2025, at 23,521 MW. Under more extreme forecast conditions, capacity margins could be as tight as 993 MW, assuming only firm fuel. Roughly 2,100 MW of power is available this winter through emergency operating procedures.

Markham also presented the Operations Report for October. Peak load was 20,278 MW on Oct. 6 around 6 p.m. Wind set an all-time record of 2,389 MW generated on Oct. 31, while solar peaked at 4,502 MW on Oct. 1. Several transmission facilities associated with Smart Path Connect came on service incrementally throughout the month.

The committee passed a motion updating the Reliability Analysis Data Manual to clarify certain sections and include data requirements for recently adopted rules.

Business Issues Committee

The Business Issues Committee on Nov. 12 voted to recommend that the Management Committee approve the Winter Reliability Capacity Enhancements tariff revisions.

The changes would, among other things, split the capacity market into seasons with separate requirements. (See NYISO: Winter Reliability Proposal to Increase Market Efficiency.) The motion passed over opposition from NRG Energy and Hydro-Quebec. The New York Utility Intervention Unit, the New York Energy Research and Development Authority, and Danske Commodities abstained.

Matt Schwall of AlphaGen was elected as the committee’s vice chair.

Budget & Priorities Working Group

The Budget & Priorities Working Group held a short meeting Nov. 10 to discuss the ISO’s draft corporate incentive goals and possible consumer impact analysis studies for 2026.

The corporate incentive goals are structured as penalties to a pooled “incentive payout” awarded at the end of the year. The draft goals for 2026 include maintaining the continuity of the bulk power system in compliance with NERC and NYISO operating procedures; maintaining ERO and state reliability standards; the day-ahead market schedule being posted 100% of the time; and not creating market problems with material adverse impacts greater than $100 million in a calendar year.

NYISO also included a “quality goal” of posting the Gold Book by April 30, 2026, and the Reliability Needs Assessment by Dec. 31, 2026. “Strategic goals” include deploying the software required to incorporate the Champlain Hudson Power Express; updating the ISO’s reliability planning process; and completing the additional system deliverability upgrade studies in time to inform interconnection customers in the transition cluster study and avoid termination of the study.

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Updated: SPP Markets+ Cruising Through Early Development

EDITOR’S NOTE: CAISO’s EDAM will go live in May 2026 for PacifiCorp and in the fall of 2026 for Portland General Electric.The original version of this story incorrectly reported the go live date for PGE.

TEMPE, Ariz. — This is the easy part, says Scott Miller, executive director of the Western Interconnection’s competitive market advocate, Western Power Trading Forum.

Indeed. Members of SPP’s Markets+ Participant Executive Committee unanimously endorsed every proposed tariff and protocol revision, with the occasional abstention here or there, during their Nov. 13 meeting. They agreed — again, unanimously — to retain the stakeholder group’s leadership for additional two-year terms during the day-ahead market’s implementation phase.

Nary was a discouraging word heard.

“We’re getting to the nub of things, but people are understanding them and digesting them,” Miller told RTO Insider after the meeting. “They’re getting used to the process, and this is obviously a lot of detail that people were dealing with. It still is a collegial group. It’s come a long way since it first started two years ago.”

Miller has seen these conversations and debates before. He said he saw firsthand the difficulties CAISO ran into as it drafted and filed its implementation tariff for its Extended Day-Ahead Market.

“There will obviously be harder issues as they get closer to the go-live date,” he said. “When you start getting into implementing tariffs and things like that, that’s where difficulties and disagreements and things pop up that people didn’t realize were there. I think we’ll find some things that will surprise us when the implementation tariffs for Markets+ get filed.”

Miller speaks from experience: He helped lead PJM’s market development in the early 2000s and later spent nine years at FERC advising commissioners and staff on electric and natural gas markets.

He said he’s not concerned about Markets+’ sometimes-languid pace of development. With a targeted go-live date of Oct. 1, 2027, SPP already is at least 16 months behind CAISO’s EDAM. That market is to go live in May 2026 for PacifiCorp and in the fall for Portland General Electric, with others following in later months.

“It’s a considered pace,” Miller said, noting that Western entities have never dealt with tariffs and organized markets until recently.

“The differences between market participants will begin to show themselves once you get into actual market operations, but for now, everybody’s pulling on the same oar,” he said. “People are taking things very seriously. Protocols associated with tariffs require a lot of attention.”

One complication is that SPP and CAISO are both relying on the West’s 37 existing balancing authorities, rather than a consolidating BA as grid operators normally do. Transmission operations will remain with their control areas, and SPP will clear units, but the BAs will still be responsible for dispatch.

“For reasons that still escape me, you’re taking a step toward something like an RTO but making it very complex by the fact that you maintain balancing areas and tariffs that don’t exist in RTOs,” Miller said. “It’s a step toward an RTO, but it’s much more complex than an RTO.”

MPEC members were unable to agree on whether to hire an external market design adviser and tabled the issue a second time. It will remain tabled until “interested parties” submit a proposal with specific issues for the committee’s consideration.

An SPP survey of MPEC’s 41 members found only minimal support, 17-16, to engage an external consultant or adviser during the market implementation’s early stages, given its “new design approach.” Those voting against the proposal said they saw little benefit for the expense.

Western Resource Advocates (WRA) proposed the position in 2023, and SPP began working on a plan and structure for the adviser in early 2024 before it was tabled the first time later that year. Staff have suggested the position report to SPP.

WRA saw the position as possibly filling a market monitoring role, but SPP in September brought on Tim Vigil to lead the 16-person Markets+ Market Monitoring Unit that will identify market design flaws and ensure compliance with market rules. Vigil was previously chief member relations and strategy officer for the Pacific Northwest Generating Cooperative and also spent time with the Western Area Power Administration. (See SPP Names Director to Lead Markets+ Monitoring.)

Tim Vigil, Markets+ MMU | © RTO Insider LLC

Vigil stressed the MMU’s independence in introducing himself to the MPEC.

“The independence allows us to be objective [and] impartial while we’re monitoring the market, investigating potential problems and protecting the market to ensure workable competition,” he said. “It just puts us in a place to accomplish these things without any undue influence.

“The MMU is committed to be transparent … with FERC, SPP and all the stakeholders that are sitting here today,” Vigil added. “Our obligation is to inform FERC of any proposed tariff changes with something that we identify that we’d like to see. We’re not trying to surprise anybody.”

The Markets+ MMU will be separate from the SPP MMU. The Western monitor will increase the MMU’s total staff from 23 to 38.

Readiness Activities Progressing

Kevin Morelock, an SPP Markets+ program manager, said stakeholders’ decision to run the market in the Pacific Time Zone has created issues as the grid operator tries to save on infrastructure costs.

The RTO’s Integrated Marketplace in the Eastern Interconnection uses the Central Time Zone for its operating day procedures.

“It’s causing some complexity with our design and being able to operate both in a CT time zone for the RTO and Integrated Marketplace and then PT for Markets+,” he said, citing the challenge of modeling both markets at the same time and the boundaries between monthly releases.

Still, Morelock said the program implementation’s design phase is on track. Staff have refined the timeline, work plan and operating time zone effects to downstream SPP systems, and an internal strike team has been assembled to mitigate issues and risks.

Chief among the risks are staffing and registration delays, Morelock said. The grid operator had hired 42 of 47 full-time-equivalent employees through September. It expects hiring to pick up in January and eventually reach a target of 206 FTEs in June 2027.

The RTO has completed 52 of 60 market registrations for BAs and non-BA transmission providers. Entities desiring to register as market participants face a Dec. 1 deadline, but Morelock said staff may adjust the schedule to ensure it doesn’t miss embedded entities or transmission customers of the BAs or transmission providers.

The Markets+ Phase 2 schedule | SPP

“We’re really continuing to ask MPs to come forward and declare their interest in joining Markets+ for those entities that are transmission customers or embedded entities,” he told MPEC.

The program is operating under its budget through September, Morelock said, and is on pace to meet its forecast $149.7 million total. That includes almost $10 million in financing charges.

The Markets+ Design Working Group is leading a holistic review of the protocols — including checking for alignment with the Markets+ tariff, improving readability and adding late changes — working with stakeholders first. The group plans to bring the finished product to a Dec. 18 MPEC conference call for its approval.

MSC to Gear up Involvement

Idaho Public Utilities Commissioner John R. Hammond Jr. stood in for Arizona Corporation Commission Vice Chair Nick Myers, chair of the Markets+ State Committee, and told MPEC members that state commissioners will participate in and monitor the stakeholder groups as the market’s development phase moves forward.

Much of the MSC’s focus will be on the tariff’s development, implementation effort, revision request process, seams issues and interchange transactions, he said.

Hammond, the MSC’s vice chair, said the increasing load growth across all states has been “truly amazing.”

“There are commonalities between all the jurisdictions, and there are differences,” he said. “Working together, we can really make a big difference for this country.”

The Western Interstate Energy Board’s (WIEB) staff, which provide independent staffing for the MSC and offer analysis on the market’s development and operations, told MPEC the committee’s 2026 budget will increase when it aligns with the standard fiscal cycle.

Lisa Brohaugh, WIEB’s director of finance and administration, said the MSC’s budget will grow to $437,923, up 12.4% from the 2025 budget of $389,680, which covered just nine months. Brohaugh noted that the previous budget of contractual expenses covered the last nine months of 2025.

The Interim Markets+ Independent Panel, composed of three SPP independent directors, will consider the budget when it next meets. SPP will then allocate the budget’s costs to Markets+ participants.

Trolese, Walter to Again Lead MPEC

MPEC members accepted staff’s nominations of The Energy Agency’s Laura Trolese and Arizona Public Service’s Kent Walter to serve additional two-year terms as the committee’s chair and vice chair, respectively.

“Their leadership has been excellent so far,” SPP’s Kelli Schermerhorn said.

The MPEC will also retain the leadership of its four key working groups after the incumbent chairs were all nominated for additional terms: Nick Detmer (Markets+ Design WG) and Joe Taylor (Markets+ Transmission WG), both with Xcel Energy subsidiary Public Service Company of Colorado; Tuuli Hakala (Markets+ Seam WG), Chelan County Public Utility District; and Libby Kirby (Markets+ Operations & Reliability WG), Bonneville Power Administration.

MPEC’s approval of the consent agenda added Chelan PUD’s Peter Graf to a vacant public power seat on the MORWG; Tri-State Generation and Transmission Association’s Kyle Cunningham to an open public power seat on the MSWG; and Black Hills Energy’s Raena Orr to an available investor-owned utility seat on the MDWG.

The consent agenda also included a scope change for the MORWG, clarifying its responsibility to provide guidance on reliability functions and not just balancing authorities.

SPP Schedules Seams Symposium

SPP has scheduled a Western Seams Symposium for Feb. 26 that follows the MPEC’s next in-person meeting.

The final details are still being worked out, but staff have invited representatives from other grid operators as part of a broader regional discussion of the boundaries between entities.

SPP has touted its seams management experience with its MISO and ERCOT neighbors as preparing it for Western operations, where the markets have been placed on top of the seams between BAs and transmission providers. (See SPP’s Experience with Seams Could Help Markets+.)

The symposium will be held at the Salt River Project’s PERA Training & Conference Center in Tempe. In-person registration closes Feb. 19.

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DOE Request to FERC on Large Load Interconnections May Further Limit State Powers

Peter Kelly Detwiler

On Oct. 23, U.S. Secretary of Energy Chris Wright ordered FERC to initiate a new rulemaking proceeding in order to “ensure efficient, timely and non-discriminatory load interconnections” for large loads exceeding 20 MW.

In his letter to FERC, Wright observed that, “Historically, the commission has not exerted jurisdiction over load interconnections.” However, Wright added, “It is my view that the interconnection of large loads directly to the interstate transmission system to access the transmission system and the electricity transmitted over it falls squarely within the commission’s jurisdiction.”

Wright then ordered FERC to consider a proposed rule, with action to occur no later than April 30, 2026, and attached an Advance Notice of Proposed Rulemaking (ANOPR) entitled, “Ensuring the Timely and Orderly Interconnection of Large Loads.”

The ANOPR suggested numerous changes to the status quo that would accelerate future interconnections, cut study times and reduce associated interconnection costs. Among other aspects, the proposed DOE approach would enable customers to file joint, co-located load and generation interconnection requests directly to FERC.

An Argument for Arrogating This Power to the Feds

This initiative constitutes an entirely new approach to load interconnections, which historically have been regulated by individual states. In asserting an expanded legal ambit for FERC in this arena, the ANOPR makes several arguments:

    • Large load interconnections constitute a “critical component of open access transmission service.” They are similar in nature to generator interconnections and thus need “minimum terms and conditions to ensure non-discriminatory transmission service.”
    • FERC already oversees wholesale electricity rates and owns the mandate to ensure that wholesale rates are just and reasonable. This mandate should be extended to large loads and data centers.
    • FERC also exercises jurisdiction over transmission in interstate commerce. Since large loads generally interconnect directly to high-voltage transmission, they should be regulated by FERC.
    • States’ regulatory authority is not affected or limited, since the ANOPR does not affect retail sales or the siting of power plants.

Proposed issues addressed include the speed of interconnection studies, treatment of hybrids (large loads with on-site generation) and net power flows at or near the same point of interconnection, and the flexibility of operations and capability of being curtailable.

The ANOPR also suggests that load and hybrid facilities should be treated similarly to assets in supply interconnection queues — paying standardized deposits for studies, risking penalties for withdrawals from the queue, and being subject to readiness requirements.

The States Push Back

Not surprisingly, state regulators quickly made their concerns known. In its Nov. 11 meeting, the National Association of Regulatory Utility Commissioners (NARUC) adopted a resolution urging FERC “to preserve and affirm states’ retail regulatory authority under the Federal Power Act, ensure that large load interconnections do not compromise grid reliability or impose undue costs on retail customers, and respect state tools for promoting system flexibility and equitable cost allocation.” (See Regulators Urge FERC to Honor State Authority over Large Load Interconnections and State Regulators Ponder Federal Role in Large Load Interconnections.)

Among topics NARUC raised were a fear that FERC might assert its authority over retail end-use sales, a concern that large infrastructure investments to serve loads might unduly burden other ratepayers, and the recognition that “at least 20 states have approved or have pending large load tariffs or similar measures, which may include financial commitments, curtailment protocols and minimum contract terms to allow for the rapid interconnection of large loads without compromising grid reliability or unduly burdening existing retail customers.”

In other words, they already were addressing the problem.

‘Bright Line’ Separating Powers Has Been Fading in Recent Years

State regulators raise some valid points, especially concerning the affirmation of regulatory responsibilities that were clarified by the 1935 passage of the Federal Power Act. That law gave federal regulators authority over interstate electricity commerce, created the Federal Power Commission (the precursor to today’s FERC) and established a “bright line” separating regulatory powers of state and federal authorities.

However, if recent history is any guide, NARUC may not have much success in opposing or even influencing this new DOE effort, as recent FERC orders and related legal decisions have succeeded in greatly blurring the formerly bright line, with state regulatory oversight increasingly diminished as a consequence.

That dynamic began with the restructuring of power markets in numerous states during the 1990s, with FERC Order 888 (1996) that established open access to transmission while introducing the concept of ISOs, and Order 2000 (1999) that created larger regional transmission operators.

FERC Order 719 (2008), in addressing demand response, further helped fray the strength of state regulators, requiring grid operators to accept demand response bids into wholesale markets, though 719 did not establish a framework for compensation. This order signaled an explicit federal regulatory reach across the bulk power into the state-regulated distribution system for the first time.

That incursion was further strengthened by FERC Order 745 (2011), which directed that “demand response resource must be compensated for the service it provides to the energy market at the market price for energy.” This was the first time that assets in the distribution system were incorporated into federal oversight, but states had the critical right to opt out, thus maintaining an important regulatory prerogative.

FERC Order 841 (2018), focusing on energy storage, went a step beyond that initial movement into the states’ realm. It specifically addressed storage resources behind the meter in the utility distribution system. Most critically, it did not allow individual states to opt out. Unsurprisingly, Order 841 did not sit well with state regulators, who saw this as an overreach into their jurisdiction.

NARUC filed suit in an attempt to overturn Order 841 but eventually lost in the D.C. Circuit of the U.S. Court of Appeals. That appellate court ruling indicated that since the activity of these storage assets affected wholesale markets, FERC authority should prevail.

FERC Order 2222 (2020) went a step further down this path, allowing all types of customer-sited assets to be aggregated and to participate in wholesale markets. In this instance, NARUC, the Edison Electric Institute and other parties sought a rehearing but were denied.

What’s Next

Comments on the ANOPR are due Nov. 21, and there certainly will be many provided, as the size of the prize at stake is enormous: interconnection requests in the many hundreds of gigawatts (even excluding Texas with its more than 200 GW of interconnection not subject to FERC oversight), capital expenditures worth hundreds of billions of dollars and outsized potential effects on ratepayers.

With two newly minted appointees and a new chair, FERC will have its work cut out for it. The current fragmented approach of interconnection management has quickly become an unruly Tower of Babel. Demand forecasting is imprecise and inconsistent, and one can point to inflationary pressures (estimated in the billions of dollars in PJM alone) that already have resulted from this lack of precision.

Today, each utility and grid operator is developing its own processes and procedures, in the face of loads that are simply unprecedented in scale, and few — if any — approaches are consistent with one another.

State regulators’ toes may be stepped on once again, and the regulatory bright line further blurred. But given the size of what is at stake, that pain may prove to be necessary, bringing some standardization, clarity and consistency to the very complex and interwoven system-of-systems that is our U.S. power grid.

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

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Transmission Delays Mean Higher Costs for Customers, Study Finds

For every $1 billion in transmission investments that is delayed, consumers lose between $150 million and $370 million in net benefits per year of delay, according to a study by Grid Strategies released Nov. 12.

“That’s a pretty impactful amount when it comes to this debate around affordability, and it speaks for the need to get more transmission built faster in order to lessen the impact on consumers,” WIRES Executive Director Larry Gasteiger said in an interview Nov. 14. WIRES commissioned the study.

The losses come from lower reliability, diminished access to lower-cost generation and the lack of efficiency from new transmission lines, the report says.

Grid Strategies analyzed eight regional transmission portfolios from ERCOT, MISO, NYISO and SPP. It extracted total reliability and economic benefits identified in each portfolio and converted them to annualized benefits and calculated annualized costs from the transmission planners’ assumptions.

Transmission projects face delays from factors including siting and permitting and other regulatory delays, Gasteiger said.

“There are supply chain issues that have developed, particularly over the last five to six years, where it just takes longer to get the items needed in order to build transmission,” Gasteiger said. “There’s been a lot of regulatory uncertainty, frankly, around transmission, in terms of what the rate of return is going to be, what the incentives are for transmission, and there’s no question that that ultimately impacts the timing on getting transmission built.”

When transmission owners do not know what the regulatory framework is going to be, that causes risks, which in turn leads to delays, he added.

A little regulatory uncertainty is baked into the system, and the industry is facing some as FERC undergoes a leadership shuffle now.

“We’re waiting to see how this new commission handles issues around affordability,” Gasteiger said. “And I think one of the factors that has to come into play is that building out more transmission can have some serious positive impacts associated with consumers, such as gaining access to cheaper, more affordable power sources, generation sources, better reliability and things of that nature.”

New Chair Laura Swett has participated in a cost allocation order already, denying a complaint from the Kentucky Public Service Commission and allowing American Electric Power’s tariff to spread the costs of supplemental projects in PJM across all its utilities in the market. (See FERC Rejects Kentucky Complaint Against AEP’s Tx Cost Allocation.)

One major issue the new commission will have to deal with is Order 1920 implementation, as the regions file their compliance filings with the planning and cost allocation reforms passed by FERC during the previous administration.

“It’s going to be interesting to see whether the commission affords a lot of flexibility in the regions, or do they want to try and use a much more standardized approach?” Gasteiger said. “I don’t know. I can’t predict where they will come out on that, but in a way, you almost have the feeling like that some of the issues that were dealt with in 1920 have been eclipsed to some extent, by focus on things like the ANOPR that just came out from DOE.”

The Advance Notice of Proposed Rulemaking asks FERC to assert jurisdiction over the interconnection of large loads, which are driving significant demand growth, often in regions that had seen effectively no real growth for decades.

“With load growth, the more customers you have signing on to the system, the more you can spread the costs out among those customers, so that winds up having the ability to kind of reduce costs generally, because you have more people paying for it,” Gasteiger said. “There are a lot of issues around getting access to cheaper power for all of those resources. And the administration’s made clear it is focused on the effort to help integrate AI and data centers, and the only way you’re really going to be able to do that is to have more transmission built as well.”

The report spends time discussing load growth, which it says has led to a growing consensus around the need for new large-scale transmission investment. FERC’s 2024 State of the Markets Report said that 1,000 miles of new lines were placed into service over the last year because of higher demand, an amount second only to projects aimed at reliability, it noted.

That trend is going to continue based on projects in the works, as NERC summarized in its 2024 Long-Term Reliability Assessment.

“The 2024 LRTA reports there are 28,275 miles of transmission (>100 kV) planned or under construction through 2034,” according to the Grid Strategies report. “This estimate is almost 10,000 miles higher than the 2023 LTRA 10-year projections and is well above the average of 18,900 miles over the past five years of NERC’s LTRA reporting.”

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MISO Agrees with All 4 IMM State of the Market Recs

MISO said all four recommendations in the Independent Market Monitor’s 2024 State of the Market Report likely are viable. The quartet of recommendations from IMM David Patton involve transmission congestion, the Midwest-South transmission link, market-to-market coordination and price settlements after grid devastation.

At a Nov. 13 Market Subcommittee meeting, Director of Market Design Zhaoxia Xie said MISO is working on the pricing recommendation and has made plans to address the other three.

Xie said MISO agrees with the Monitor that it should improve its criteria for pricing when an extreme event forces portions of the grid offline.

Patton recommended that MISO tweak portions of its “forced-off asset” declaration, namely its constraint management and dead bus criteria, to trigger the settlement style.

MISO’s forced-off asset event declaration sets real-time prices equal to day-ahead prices for offline facilities. MISO created the new settlement practice in 2024 for generators physically disconnected from the grid during extensive transmission outages triggered by extreme events. It’s designed to prevent generation from excessive penalties or undeserved windfalls. (See FERC OKs MISO Settlement Rules for Widespread Tx Outages.)

Patton said even though 2024’s Hurricane Beryl forced transmission offline that disconnected most loads in the Southeast Texas Load Pocket, the storm failed to qualify as a forced-off asset event.

Patton said MISO defines its revenue inadequacy criteria too narrowly to have activated the pricing. Patton said to address the issue, MISO should add price volatility make-whole payment criteria to the revenue inadequacy criteria when making the call on forced-off asset declarations.

Xie said MISO would include price volatility make-whole payment criteria in the financial criteria for declaring a forced-off asset event. The change would require only a minor tariff edit, she said.

Squeezing More out of Midwest-South Constraint

Xie said MISO agrees it should look into more effectively using its Midwest-South transfer constraint. However, she said MISO needs to first evaluate the issue and the effects of rolling out the IMM’s suggestion.

Patton proposed that MISO maximize its Midwest-to-South transmission limit by being less circumspect with the space it reserves for unforeseen flows.

MISO actively derates its Midwest-South transfer constraint to keep flows in either direction below the contractual limit. It also reserves space for unmodeled flows over the constraint that can violate the limit.

Patton said MISO’s cautiousness has caused the transfer’s use to be just 84% of what’s contractually allowed. He said MISO should work in extra, lower-value steps to the transmission limit’s demand curve and raise its energy-plus-short-term reserve limit to the highest-penalty step on the transfer to use the transmission more. Patton said a more detailed curve and relaxed limits could increase the path’s use when the value of transfers is high.

M2M Improvements

Xie said “efforts are underway” to review MISO’s and its neighbors’ criteria for assigning and managing market-to-market flows.

Patton advised MISO to stop accepting SPP’s requests that constraints be designated for market-to-market coordination unless MISO is sure it can help ease the constraint.

Xie said MISO could suggest revisions or create new rules for when monitoring roles change on a flowgate or to better define effective control conditions. Xie said MISO would engage SPP especially on potential changes.

“This is a part of our continual coordination with our neighbors to manage transfers through market-to-market flowgates as well as requests for relief,” Xie said.

Patton said MISO in some cases has accepted an M2M designation for flowgates from SPP even when it cannot deliver economic respite. He was among the first to alert stakeholders that MISO could offer little relief for a MISO-SPP flowgate in North Dakota strained by a new cryptocurrency mining facility. The situation in 2023 spurred complaints from the MISO side and a FERC refusal to refund about $40 million in congestion costs. (See FERC Again Declines Changes, Refunds on Crypto-burdened MISO-SPP Flowgate.)

Seasonal or Monthly FTR Auctions

Finally, MISO said it would consider the IMM’s proposal that MISO shift most of its transmission capability to seasonal and monthly financial transmission rights auctions and auction revenue rights.

Patton has said the move would lead to more participation and liquidity in near-term auctions; reduce the risk of overselling; and improve price convergence, where FTR prices better reflect actual system conditions and values of the congestion hedges.

The IMM has said buyers often overpay for counterflow in seasonal and monthly FTR auctions with low participation, and incremental capacity is underpriced. He also has said low participation in FTR auctions by holders of ARRs suggests sluggish competition. Compounding matters, Patton said transmission owners report outages to MISO too late, which can lead to the overselling of FTRs.

“MISO agrees there’s some value to moving to seasonal auctions from annual auctions and even monthly auctions,” Xie said. She added that more frequent auctions would have more accurate modeling assumptions and more up-to-date outage information.

Xie said the IMM’s counsel would be considered under MISO’s larger work to improve its ARR/FTR Market.

MISO has become increasingly concerned over its congestion-hedging market’s underfunding in recent years. It has said there’s a growing discrepancy between awarded ARRs and the footprint’s actual congestion patterns. As a result, load-serving entities hold a historically smaller share of FTRs, and the ARRs’ congestion value has fallen. (See MISO FTR Underfunding Hits $60M in Spring, Improvements Coming in 2025.)

The RTO is in the exploration phase of solutions but said it wants to bolster FTR market performance and participation, improve model accuracy, ensure funding and better link the day-ahead market to the FTR market.