Search
February 2, 2026

Posted on

FERC Approves PJM CIR Transfer Proposal

FERC approved revisions to PJM’s tariff to streamline the process for the owners of a deactivating resource to transfer its capacity interconnection rights (CIRs) to a new unit at the same point of interconnection (ER26-403). (See PJM Preparing Alterations to Rejected CIR Transfer Proposal.)

Replacement resources would qualify for replacement generation interconnection studies in lieu of the full slate of network impact studies new resources must undergo. The replacement resource cannot exceed the maximum output of the retiring unit, and it must interconnect at the same substation bus and voltage. The studies are expected to take 180 days to complete.

Since the CIRs for the deactivating resource already have been studied and the unit included in PJM’s system modeling, the commission wrote it is not necessary for a replacement to undergo the full suite of studies to ensure deliverability. The creation of a parallel queue would not constitute queue jumping because the CIRs already have been studied and determined to be deliverable, while the network impacts of a greenfield project are unknown.

The filing is PJM’s second crack at creating a fast track for replacement resources after the commission rejected its first proposal in August 2025 because of two carveouts from the proposed requirement that projects be capable of entering service within three years. Those provisions would have created a one-time extension of the in-service date requirement and an exception for resources with long development timelines, which the commission wrote would undermine the purpose of PJM’s proposal: bringing replacement resources online faster (ER25-1128).

“PJM’s proposal permits milestone extensions only in certain circumstances, and only for up to a specific amount of time, which will help ensure that the replacement generation interconnection process results in the timely and efficient replacement of generating facilities. Unlike the prior proposal that allowed replacement generation project developers to unilaterally extend the commercial operation date for their project without restriction, the instant proposal allows PJM to ‘reasonably extend’ the in-service date or other milestones under specified conditions,” the order states, adding that if a developer requires a longer extension, a waiver can be requested from the commission.

Those milestone extensions would be permitted only for “delays not caused by the project developer and that could not have been remedied through the exercise of due diligence,” PJM wrote in its transmittal letter. Milestone extensions would be capped at three years past the original commercial operation date.

PJM wrote the proposal is one of several changes to PJM’s planning and interconnection processes intended to allow resources to come online more quickly as the RTO seeks to ward off a looming resource adequacy shortfall. Other efforts include the Reliability Resource Initiative, which allowed 51 resources that could quickly add capacity to be inserted into Transition Cycle 2, and expanded eligibility for surplus interconnection service. (See FERC Approves PJM’s One-time Fast-track Interconnection Process.)

“At a time when PJM needs additional capacity resources in the near term to meet serious resource adequacy challenges, the expedited processing of replacement generation interconnection service requests claiming a deactivating facility’s CIRs can yield significant reliability benefits by facilitating the timely addition of new capacity while promoting the efficient use of existing infrastructure,” PJM wrote.

The Independent Market Monitor protested the filing, arguing it would divert planned resources from the cluster-based interconnection queue to a less efficient serial study process and further slow development by creating an incentive for resource owners to withhold CIRs until they can be sold to a developer.

During the stakeholder process that led to PJM’s filing, the Monitor proposed a model under which the CIRs associated with a deactivating resource would be made available to all resources on the grid as transmission headroom. It reiterated the argument that CIRs should not be for sale in its protest. (See “Voting on CIR Transfer Proposals Deferred to October,” PJM PC/TEAC Briefs: Sept. 12-13, 2024.)

“The basic purpose of the process is to permit existing generators to sell their CIRs to the highest bidder rather than to identify the best replacement resource. The proposal is inconsistent with open access and the purpose of CIRs. A proposal to truly reform CIRs would terminate CIRs immediately at the time a resource deactivates, and thereby avoid undue discrimination, promote competition and facilitate the rapid entry of needed new generation,” the Monitor wrote.

The commission wrote the proposal would not implicate market power as the ability to transfer CIRs already is codified in the tariff.

“This filing simply establishes an expedited review process for replacement generation resources interconnecting at the same location as a deactivating generating facility that would not change the voltage or maximum generation output at that location. Nothing in the instant filing would modify the existing rights to transfer CIRs or the transfer process,” the order states.

Posted on

IESO: Few Capacity Downgrades from Performance Adjustment Factor

IESO downgraded less than 100 MW of capacity for November’s auction in the first application of its Performance Adjustment Factor (PAF) in both the winter and summer seasons.

The PAF ensures the ISO procures only capacity that has been confirmed by testing.

“It really was a small number of megawatts that ended up being derated because of the [PAF] … less than 100; probably less than 50 megawatts. But it was a very small amount,” Laura Zubyck, IESO’s capacity auction supervisor, said during a Jan. 29 engagement. “We’ve seen good performance in our capacity tests, and so we rarely derate.”

Clearing prices hit a record $471/MW-day for summer 2026, nearly double the $243 from 2024, and $530/MW-day for winter, more than five times the previous $102. (See Big Jump in Ontario Capacity Prices Signals Tightening Supplies.)

IESO year-over-year capacity auction comparisons for winter. | IESO

IESO’s Paulo Antunes said the results reflected short-term changes in supply combined with a 200-MW increase in the target capacity. The auction cleared 1,832.8 MW for summer 2026 and 1,125.3 MW for winter 2026/27.

IESO cleared no imports from New York, a loss of 200 to 300 MW compared with previous years. Antunes said. In addition, about 200 MW of Ontario-based generation that had previously participated in the auction instead signed contracts with the ISO under its second medium-term procurement.

“The remaining available supply in the market was not enough to offset the combined impact of these two factors,” said Antunes, who also noted the impact of increasing electricity demand and ongoing nuclear refurbishments.

Virtual hourly demand response resources made up the largest share of cleared capacity, representing almost 41% in summer and 60% in winter. (See related story, IESO, Stakeholders Ponder Changes to Hourly DR.)

The largest increase in cleared summer capacity came from system-backed imports, which accounted for almost one-third of cleared capacity.

The increase was largely enabled by increasing the Hydro-Québec import limit from 400 MW to 600 MW.

Generation-backed imports, in contrast, declined.

The 2025 auction also showed a narrowing gap between offered and cleared capacity. “In previous years, the gap has been much bigger, and this is resulting in an upward pressure on price,” Antunes said.

Julien Wu, of Brookfield Renewable, thanked the ISO for providing more detail on auction results than in past years but asked officials to provide still more, including information on the technology types that experienced derates due to the PAF.

“The more information we have, the easier it is for us to make scheduling and trading decisions,” he said.

Posted on

NYISO, Stakeholders Debate Changes to Demand Curve Reset

NYISO staff presented more of their initial ideas for improving the Demand Curve Reset process, centered on alternative shapes, slopes and points of the curve.

The ISO’s goal is to simplify the process for both staff and stakeholders. (See Resetting the Reset: Demand Curve Reform Discussions Begin.)

“The demand curve is at the core of aligning system reliability needs to market fundamentals,” Michael Ferrari, market design specialist for NYISO, told the Installed Capacity Working Group on Jan. 21. “Modifying them can enhance the efficiency of market signals to improve capacity market outcomes.”

The DCR shape and slope govern the value of capacity under different market conditions, sending price signals for new resource development and retirement of old units. The more installed capacity that is on the grid, the less any given megawatt is worth, and vice versa.

The curve is drawn from the zero crossing point (ZCP) to a reference point set by the cost of new entry and locational minimum capacity requirement. The ZCP is where the marginal price of an additional megawatt of capacity is equal to zero.

Currently, the curve slopes downward from the maximum clearing price plateau in a straight line to the reference point and the ZCP. Ferrari said NYISO had investigated “kinking” the demand curve into multiple slope segments, increasing the steepness of the curve to change prices more rapidly and increasing the ZCP. The ISO also discussed pinning the loss-of-load expectation reliability criteria to losing the largest generation unit in each location, similar to the N-1 contingency analysis in transmission planning.

“We are not trying to indicate an endorsement of any particular change or option,” Ferrari said, explaining that the presentation reflected “early analysis” of reform options.

Stakeholders said adjusting the ZCP might be difficult. Howard Fromer of Bayonne Energy Center said the first time the ZCP was set was a heavily negotiated process. Doreen Saia, of Greenburg Traurig, agreed.

“All of our locality curves have to work within the [New York state] curve,” she said. “If you extend out some of the curves too far, it eats into the ‘Rest of State’ price. … If you go too tight, then New York City gets problematic very quickly.”

Saia said that she welcomed looking at the demand curve and ZCP “with fresh eyes” because the situation has become much more complex, from both a regulatory and market player standpoint. More entities of more types are in the market trying to sell power.

One stakeholder mentioned that in the current DCR process, there are provisions to revise the shape and slope of the curve, but in practice this does not happen regularly. Ferrari said that the last time he recalled discussing changes to the ZCP was in 2014.

“Mike, I think you’re absolutely right,” Saia said. “We could have always looked at shape and slope, but for the first six or seven reset processes, the only thing that was even slightly considered was moving to a combined cycle gas facility” for the reference point.

Pinning the LOLE to a contingency analysis based on the largest generator also stirred discussion among stakeholders. Some said this would establish an incentive to build “really large generators” by essentially announcing that the demand curve would shift to accommodate them. One said that a contingency in the capacity requirement created uncertainty in developer cost-benefit calculations.

A NYISO staffer argued that using the largest generator had the benefit of greater clarity and transparency for understanding how the market would behave and would not necessarily increase market complexity.

Time-differentiated Transmission Congestion Contracts

NYISO is also considering alternative ways to divide transmission congestion contracts into more granular products.

Currently, TCCs are a 24-hour product only. NYISO is the sole RTO/ISO to offer only 24-hour financial transmission rights. This has been criticized by stakeholders as limiting the effectiveness of TCCs to serve as hedging mechanisms against congestion because they cannot distinguish between congestion patterns that change during the day or over the course of a week.

NYISO considered time-differentiated TCCs in 2021, proposing products for on-peak workdays, off-peak weekends and holidays, and off-peak “all other hours.” In 2025, Calpine proposed a system that broke TCCs into on-peak and off-peak hours. (See Calpine Sees Support for TCC Auction Proposal.)

The ISO is planning on finalizing a proposal in 2026, building off both its 2021 design and Calpine’s. Tariff language will not be pursued until it passes the annual project prioritization process.

Champlain Hudson Power Express Integration

NYISO provided stakeholders with an update on the Champlain Hudson Power Express integration process.

CHPE is a 1,250-MW HVDC line that will run between Quebec and New York City. It is expected to go into service in 2026, but the exact date is unknown. (See NYISO Proposes ICAP Changes for New Entry Ahead of CHPE.)

The capacity market is predicated on annual inputs with limited seasonality, and the capability year starts in May. If CHPE’s integration into the grid is mistimed, it could have major implications for capacity market parameters, such as the transmission security limit for the New York City-area capacity zones.

To accommodate this uncertainty, the ISO created two sets of market parameters, one assuming CHPE is operating and one assuming it is not. This creates two sets of TSLs, locational capacity requirements, capacity accreditation factors, unforced capacity demand curve parameters and load-serving entity minimum capacity requirements.

If CHPE provides notice by March 2 to participate in the ICAP market in May, NYISO will set the market to reflect its participation. The ISO intends to issue a notice by March 9 to market participants as to whether CHPE will be in the market.

Posted on

British Grid Operator to Highlight ERCOT Innovation Summit

ERCOT says Fintan Slye, CEO of Great Britain’s National Energy System Operator, will join ERCOT CEO Pablo Vegas to kick off the Texas grid operator’s third annual Innovation Summit.

Slye leads the publicly owned NESO, which manages Great Britain’s electric system and is responsible for planning the nation’s energy systems and markets. He has held leadership positions with the country’s Electricity System Operator and EirGrid, Ireland’s transmission system operator.

“NESO is at the heart of Great Britain’s energy system, and innovation is at the heart of everything we do,” Slye said in a statement. “At NESO, we are always looking to use innovation to help drive value for consumers and improve security of supply.”

He said it is “brilliant and timely” to participate in the summit and to collaborate with U.S. industry peers on grid upgrades, new data center demand, and other learnings and solutions that can benefit Great Britian’s energy system. The 2026 Innovation Summit, to be held March 31 at Kalahari Resorts and Conventions in Round Rock, Texas, will bring together industry stakeholders and thought leaders to share technological advancements and innovative solutions that advance grid transformation in Texas and beyond.

“Collaboration with our industry peers in the U.S. and across the globe is essential as we work toward building more resilient and intelligent solutions for rapidly evolving grids,” Vegas said.

The grid operator announced in September a Grid Research, Innovation and Transformation (GRIT) initiative designed to improve industry collaboration through expanded shared research and technology prototyping. The program’s technology initiatives focus on a range of areas, including smart controls for distributed energy resources, machine learning models to improve power flows and improvements to large load modeling.

ERCOT says between 850 and 950 participants attended each of the first two summits, either in person or virtually.

PJM CEO Manu Asthana highlighted the 2025 summit, also held in Round Rock.

Posted on

MISO Suggests Reliability Requirements, Partial Supply Deals to Handle Large Loads

MISO said it likely will create interconnection reliability requirements and explore new rules that could bring large customers online in stages, as capacity becomes available, to get a handle on large loads eyeing MISO locales.

MISO anticipates drafting “a set of guidelines and requirements” for large loads that wish to interconnect to maintain reliability. The RTO made the announcement at a Jan. 30 stakeholder workshop dedicated to large load preparation.

Executive Director of Markets and Grid Research DL Oates said MISO’s stakeholders view the grid operator as having a role in providing reliability interconnection guidelines.

Manager of Strategic Assessments Beibei Li said MISO can draw on its existing inverter-based resource requirements for ideas. She said MISO would need loads’ telemetry to maintain system reliability and stability and that it would use their data in modeling and planning.

MISO plans to introduce the topic to the Planning Advisory Committee for discussion in the next few months with the goal of working on a ruleset sometime around mid-2026.

Oates said MISO “is hesitant to provide exact dates” on when it could file tariff changes with FERC on the reliability requirements.

Oates said for years MISO has operated with an approximate 120-GW peak demand across its 45 million customers. He said by 2030, MISO could add anywhere from the “low 10s to the high 20s” of gigawatts.

“So, something like 15% of growth with a fair bit of uncertainty around that,” he said.

Oates said the new load coming MISO’s way is unlike anything MISO has seen: “It is, to put it very simply, very big.”

Jordan Bakke, MISO’s director of strategic insights and assessments, said there’s sizable reliability risk that large load customers could introduce.

“We expect large loads to behave in a way that’s hard to predict,” Bakke said. He said large loads have “unique disturbance behaviors,” including frequency sensitivity, low fault current and oscillations. He also said these loads have “unknown and varied ride-through performance” alongside complex protection schemes that make for complex stability assessments.

Minnesota Power’s Tom Butz said MISO appeared to have a great number of concerns over stability that come with large load customers. He asked if MISO has existing study processes to test how large loads specifically strain the system.

“MISO itself has very limited study as it relates to large load interconnection,” Bakke said.

Vice President of Operations Renuka Chatterjee said MISO will be “looking at some AI tools” for study assistance and promised “more to come.”

‘Speed to Partial Power’

MISO is toying with the idea of providing what it calls “speed to partial power.”

MISO Director of Expansion Planning Jeanna Furnish said large loads can make it online in a little more than a year, while generation takes about four years and transmission typically takes about seven to 10 years. She said load could be left trying to withdraw before generation or transmission arrive on scene.

Furnish said MISO’s ongoing work to create zero-injection generator interconnection agreements can help speed up generation projects that plan to send their output solely to their dedicated loads, not the greater system. (See Questions Abound over MISO Idea for Zero-injection Agreements.)

However, Furnish said MISO could implement ideas “while we wait on infrastructure.”

Enter MISO’s “partial power” brainchild. The grid operator said in some cases, it probably could serve a portion of large load customers’ needs with existing transmission for an interim period. Load then could be scaled up incrementally as generation or transmission is constructed. Finally, once construction is complete, the full load could be served with firm withdrawal capability at its interconnection point.

Furnish said providing service to fractions of load “helps address the challenges of using the system that is available and manage service as conditions change.” She said a ramp-up to firm service allows service even as upgrades come online.

Furnish said discussions on partial service applications similarly will be held at Planning Advisory Committee meetings.

Butz cautioned that MISO and members need to focus on energy adequacy because new large load customers have “twice the load factor” of MISO’s average load. He said the load surge comes as MISO’s highest-capacity-factor thermal resources plan to retire in droves.

“It’s really crucial that we understand how to serve high-load-factor load,” Butz said.

Chatterjee said MISO will strive to create “timely paths” for integrated large loads but “must keep the system reliable today and in the future.”

Chatterjee said MISO would examine which initiatives it could move fast on “without boiling the ocean.” She said the RTO already has done the “foundational work” to open up grid capacity through its expedited transmission project work.

Furnish also said MISO wouldn’t “copy and paste” other RTOs’ proposals in the large load space but is evaluating their work.

Reserve Product Revamp

Additionally, MISO said it needs to recalibrate its reserve products to account for greater uncertainty introduced by large loads.

Director of Reliability Coordination John Harmon said the “behavior of large load” isn’t reflected today in MISO’s ancillary service setup. He said it probably will have to keep more reserves and revise reserve products’ demand curves.

Harmon said large loads can quickly increase or decrease demand, especially when co-located generation or the load itself suddenly goes offline.

Harmon said the Reliability Subcommittee would handle modernizing the reserve scheme and noted the group already is working to create a dynamic regulation and ramp product that calls up a greater volume of reserves as system uncertainty rises.

Stakeholders asked what role MISO sees itself playing in controlling added costs on the system from load growth.

Bakke said that while MISO cannot influence much of the consumer costs that come with large loads, it views itself as responsible for cost-effective regional transmission planning to minimize the volume of more expensive, piecemeal transmission upgrades. He said the RTO likely must overhaul some of its process for furnishing reserves, since it expects that reserves will be used more often.

MISO will hold three more workshops on large loads over 2026: on April 30; July 31; and Oct. 29.

Posted on

EIA Charts Varying Impact of Gas Prices on Electricity Costs

The U.S. Energy Information Administration reported average wholesale day-ahead electricity prices were higher in 2025 than in 2024 at most but not all major trading hubs in the contiguous 48 states.

The largest decrease was $14/MWh at the Mid-Columbia hub in the Northwest. The largest increase was $29/MWh in ISO-NE.

In one of its regular “Today in Energy” posts, EIA said the national average was pushed higher largely by rising prices for natural gas, the leading source by far for U.S. electricity. Average benchmark Henry Hub spot prices were 56% higher in 2025 than the historic low prices seen in 2024.

This contributed to a minor shift in generation away from natural gas: Electricity generation in the 48 states increased 93 BkWh or 2% year over year, despite 2025 being one day shorter than 2024. Natural gas generation decreased 3% (53 BkWh), while coal increased 11% (76 BkWh) and solar jumped 32% (66 BkWh) to make up the difference.

The details of the shift varied by region.

In the PJM and MISO regions, total generation rose 3% (49 BkWh) in 2025 as gas generation decreased by 24 BkWh from 2024 levels, solar increased 24 BkWh and coal increased 49 BkWh.

In Texas, demand increased 5% (22 BkWh) in 2025; the major movers were natural gas (down 6 BkWh) and solar (up 20 BkWh).

In the Northwest, which saw a less severe winter in 2025 than in 2024, total generation decreased 4% (17 BkWh). Natural gas prices reached historic lows in the Northwest in 2025 amid subdued demand and ample supply from Canada, but natural gas generation nonetheless decreased 8 BkWh. Other movers were hydropower (3 BkWh higher), solar (2 BkWh higher) and nuclear (2 BkWh lower, thanks to a 65-day refueling outage).

Posted on

ERCOT Leaned on Mobile Gens, RMR Unit During Storm

ERCOT says Texas’ 15 mobile generating units and a reliability-must-run unit all played an “important reliability function” during the Jan. 25-27 winter storm, the state’s first major cold-weather event since 2021’s disastrous Winter Storm Uri.

Grid operator staff told the Texas Public Utility Commission during its Jan. 29 open meeting that CPS Energy completed repairs to its Braunig Unit 3 before the storm arrived and that it was committed throughout the event.

Dan Woodfin, ERCOT’s vice president of system operations, told commissioners that Unit 3 provided “necessary support” to relieve overloads in the San Antonio region after a large unit in Central Texas tripped Jan. 25. The trip caused “brief exceedance” on the South Texas export constraint and post-contingency overloads on some transmission lines between the region and Houston, necessitating a localized transmission emergency declaration that lasted about 13 hours.

Woodfin said the grid operator also committed the mobile generating units that were moved from Houston to San Antonio in 2025 to provide reliability support for the South Texas constraint. The constraint was binding throughout the storm, he said.

“The combination of these actions was sufficient to operate the system reliably until the large unit came back on” Jan. 26, Woodfin said.

CPS had intended to retire the 55-year-old gas unit in 2025, but ERCOT determined that it was needed to address the South Texas constraint. The RMR is the grid operator’s first since 2016, when it entered into an agreement with NRG Texas Power over a previously mothballed gas unit near Houston. (See “Braunig Outage to End in December,” ERCOT: New Ancillary Service Key to Resource Adequacy.)

“Kudos to ERCOT and to everyone involved for how the grid played out during this storm,” PUC Chair Thomas Gleeson said. “I think everyone resoundingly said this was a success [in] probably the most difficult storm we’ve had to endure since Winter Storm Uri. Everyone should be commended for the work done on this.”

ERCOT navigated the storm without resorting to calls for conservation, issuing energy emergency alerts or suffering systemwide power outages. Demand peaked at nearly 76 GW on Jan. 26, far short of early projections of 83 GW. Staff said the state’s cloud cover and closures of businesses and schools helped reduce demand.

“In summary, ERCOT successfully managed the Texas electric grid through this cold-weather event. As always, we will continue to learn from this event to improve our tools and processes going forward,” Woodfin said.

FFSS Criteria Approved

The commissioners approved staff’s proposal establishing the criteria for participation in ERCOT’s Firm Fuel Supply Service (FFSS) program and the grid operator’s requirements to implement it, a result of a law passed during the 2021 legislative session in Uri’s aftermath (58434).

The rule codifies requirements to procure FFSS during natural gas curtailments and cold-weather events. Staff identified three categories of resources eligible to provide the service: on-site, resource-controlled and contractual off-site. The latter expands the program, although its budget remains unchanged at $54 million.

Jeff McDonald, the Independent Market Monitor’s director, objected to the inclusion of gas-fired resources but said he understood that the 2021 storm “precipitated a need on the reliability side.” He said he was more concerned that FFSS, other ancillary services and residential demand response are all out-of-market actions that affect the ERCOT energy-only market’s reliance on shortage pricing to incent investment.

“They suppress the shortage-pricing mechanism from being able to adequately signal that there’s shortages,” McDonald said. “Therefore, there’s less revenue in the market. Therefore, you’re going to have delayed or reduced new investment.

“I would like to see these programs be diminished over time and more focus placed on the kernel of resource adequacy for ERCOT, which is shortage pricing,” he added. “I do understand the need after Uri. Cracks were exposed that needed to be filled. Enough time has passed now that I think it’s time to … focus more on in-market price signaling to provide reliability services to fill those cracks.”

Gleeson said he agreed with McDonald about the need to allow the market to provide revenues from scarcity, but he also said the rule makes sense “where we sit right now.”

“I think what you’ll see is continued discussion about that and the right timing to actually implement those changes,” Gleeson said.

Batch Zero’s Phased Study

ERCOT will conduct its first “batch” study of large load interconnection requests in two phases, Jeff Billo, vice president of interconnection and grid analysis, told the PUC.

The grid operator has proposed a “Batch Zero” process to address the 232 GW of interconnection requests from AI facilities, cryptocurrency miners and other large loads. Now, that batch’s first phase, or Phase A, will be limited to large loads that want to be energized early in 2027. Projects in that batch will undergo an abbreviated version of the Batch Zero study. (See ERCOT Again Revising Large Load Interconnection Process.)

A longer, full Phase B study will be for projects with longer timelines. It would begin in August and be completed early in 2027. Even then, the loads will have to pass ERCOT’s quarterly stability assessment five to eight months before they are energized.

“We need to do an operational assessment before those loads connect … to see if there’s anything that has changed since the studies were performed and see if we need to implement any sort of operational constraints to make sure that we know where the constraints are on the system,” Billo said.

The Batch Zero study will serve as a foundation for the other batch studies that follow every six months, beginning in the first quarter of 2027, Billo said. ERCOT will share the draft criteria for large load requests during a Feb. 3 workshop.

Responding to Federal Issues

Staff told commissioners that the PUC has joined the ballot pool for NERC’s Long-Term Planning Energy Assurance project (2024-02), allowing it to participate in future votes and comment windows (54987).

NERC has scheduled a workshop and meetings Feb. 17-19 to discuss concerns and start drafting revisions to the proposed standard, which has drawn pushback from utilities over a requirement to create corrective action plans. The standard failed to pass a first round of voting, garnering only 17.8% support.

PUC staff plan to return to the commission with comments to file in the proceeding.

“I think that’s the right course of action. I think corrective action plans seem out of scope for” NERC, Gleeson said.

The PUC has adopted a reliability standard that sets criteria for frequency, duration and magnitude of loss-of-load events. (See Texas PUC Sets Reliability Standard for ERCOT.)

Following a closed session, the PUC voted to file amicus briefs supporting FERC in two dockets before the D.C. Circuit Court of Appeals: Clean Wisconsin, the Natural Resources Defense Council and the Sierra Club’s appeal of the commission’s approval of MISO’s Expedited Resource Addition Study process (25-1264), and Advanced Energy United, Advanced Power Alliance, American Clean Power Association and Solar Energy Industries Association’s challenge to SPP’s Expedited Resource Adequacy Study (25-1265).

Posted on

IESO Seeks Input on RFP for 3rd Toronto Transmission Line

IESO is seeking stakeholder input on its first competitive transmission solicitation: a $1.5 billion HVDC line under Lake Ontario that will become the third major supply line for Toronto.

The ISO recommended the 65-kilometer, 900-MW Toronto Third Line (TTL) in September 2025, saying it would be more “future proof” than two cheaper options. Planners say the line, which was approved by Ontario’s Minister of Energy and Mines in January, is needed to meet a potential doubling of Toronto’s electricity demand by 2050. (See Ontario OKs Underwater HVDC Line to Toronto.)

In July, IESO opened enrollment in its Transmitter Selection Framework (TSF) Registry, a prequalification mechanism for competitive procurements. (See IESO Removes Credit Requirement for Transmission Registry.) As of Dec. 12, two transmission companies — Fortis and Emera — were approved for listing in the registry.

The ISO’s tentative procurement plan, outlined in a Jan. 28 stakeholder engagement, calls for closing the TSF registry in the fourth quarter and opening the request for proposals in the first quarter of 2027, with proposals due in the third quarter and an award in the fourth. The projected in-service date is 2037 “or sooner,” IESO said.

Electricity demand is expected to exceed the capacity of the two transmission lines currently supplying Toronto by 2038. Closure of the 550-MW gas-fired Portlands Energy Centre would accelerate that “reliability need” to 2034.

Design Elements

Although the TTL will be the first HVDC and underwater line in Ontario, similar projects have been built elsewhere in Canada, as well as in the U.S. and Europe.

Under IESO’s standard competitive model, the winning bidder would receive a contract covering all costs for the transmission line’s first 10 years of commercial operation, with the contract transitioning to traditional rate regulation under the Ontario Energy Board in Year 11.

But IESO said the TTL’s “unique technical, environmental and delivery risks [are] not well suited to a contractual model that only allows limited cost adjustments over a longer contract term.”

Tentative procurement plan for the Toronto Third Line | IESO

The ISO said schedule commitments and costs that proponents can reasonably scope and price will be subject to an IESO contract. Uncertain or “externally influenced” costs will be subject to review by the OEB under its “just and reasonable” prudency standard. The OEB’s cost of capital parameters and deemed capital structure also will apply.

“We are seeking input on potential appropriate cost adjustment mechanisms to reduce unnecessary risk premiums while protecting ratepayer value,” the ISO said.

IESO also asked for comments on how prescriptive its technical requirements should be at the RFP stage.

Experience, Indigenous Engagement

Bidders will be required to have experience developing, constructing, operating and mitigating environmental impacts of underwater transmission projects as well as engaging with Indigenous communities, “including undertaking rights-based consultation within treaty and traditional territories.”

IESO is seeking feedback on how to define experience and whether it should be demonstrated at the corporate level or through individual team members, including partners and subcontractors.

All bidders will be required to submit an Indigenous Engagement & Participation Plan (IEPP) to “ensure Indigenous communities are provided with meaningful opportunities to participate” in the project. IESO’s evaluation of the IEPPs will include proposed equity participation structures and non-equity opportunities, including employment, contracting, supply chain participation, training and scholarships.

It asked for input on how it should weight the importance of equity and non-equity participation and how it can ensure early Indigenous community engagement without “inundating communities with requests for engagement from prospective bidders.”

“We’re not setting up a system that rewards who can get a signature [from communities] first,” IESO’s Andrew Lee said.

The Ministry of Energy and Mines says dozens of Indigenous communities have rights or interests in the project area, including the Mississaugas and Chippewas. The ministry’s delegation letter will identify the Indigenous communities to be consulted and the level of consultation.

Aaron Detlor, a lawyer for the Haudenosaunee Development Institute, which represents the Haudenosaunee Confederacy Chiefs Council (HCCC) in the development of lands within areas of Haudenosaunee jurisdiction, questioned the legality of the IESO’s RFP.

“We haven’t had any engagement with the Crown on this RFP process, and that itself is a breach of the honor of the Crown,” he said. “You’ve excluded all kinds of Indigenous people from even bidding on this. So, what you’re doing is you’re creating an RFP process to exclude Indigenous people.”

Amy Gibson, manager of the ministry’s Indigenous Energy Policy unit, said the ministry has not delegated any consultation duties to IESO and is “directly consulting with communities,” including the HCCC.

The ISO is “separately having early engagement around design features because of the timelines associated with this project, but we have not given the direction to the IESO yet on the specific criteria that they will proceed with. So, this is information gathering,” she said.

Detlor declined officials’ offer to continue the discussion offline.

“I’ve written you dozens of times on different IESO hearings and meetings, and I’ve never gotten an answer back,” he said. “I’ve written to the ministry, and I’ve written to IESO … 60 times.”

Engagement Sessions

IESO plans to hold engagement sessions on the procurement every two or three months through 2026, with a March session on RFP and IEPP design considerations.

The ministry is seeking comments on the RFP until Feb. 21 through an Environmental Registry of Ontario posting.

Comments on the Jan. 28 engagement are due Feb. 18 to engagement@ieso.ca using the feedback form posted on the engagement webpage.

IESO is pausing engagement on the competitive process while the TTL procurement is under development. However, it continues to develop recommendations for upcoming transmission projects and determining which ones would also be suitable for competitive procurements.

Posted on

Pathways’ ROWE Incorporated in Delaware, Board Search Underway

Delaware has approved the certificate of incorporation for the Regional Organization for Western Energy (ROWE), and an executive search firm has been hired to vet candidates for the organization’s initial board, the West-Wide Governance Pathways Initiative’s Launch Committee announced.

ROWE was incorporated Jan. 21, and the committee is preparing the next steps in establishing the organization that will assume governance over CAISO’s energy markets, consultant Sarah Davis said during a Pathways stakeholder meeting Jan. 30. Next up is registering for nonprofit status and submitting the bylaws and conflict-of-interest policy with the Internal Revenue Service.

The Launch Committee’s Formation Board must approve the IRS documents. The Formation Board’s sole purpose is to serve in an administrative role before the initial board takes over, Davis explained. It will approve the initial board’s first five members and hand off its duties to them. (See Pathways Takes Key Step Toward Establishing ROWE.)

“This is a big milestone,” she said.

The committee has hired Lyceum Leadership Consulting to run the selection process for the initial board. Members of the committee’s nine sectors have each selected a representative to serve on the Nominating Committee, which began its work Jan. 23, according to Davis.

The work will be split into two phases. The first phase includes refining the search strategy and developing the role specification for the full seven-member board. The second phase includes conducting the board search with the goal of having the first five members seated by July.

ROWE is the product of California Assembly Bill 825, which implements Pathways’ “Step 2” plan to create an independent organization to oversee CAISO’s Western Energy Imbalance Market and soon-to-be-launched Extended Day-Ahead Market, and authorizes the ISO and California’s investor-owned utilities to join ROWE. (See Newsom Signs Calif. Pathways Bill into Law.)

One goal in establishing ROWE was to remove what some see as a barrier to wider participation in CAISO-run markets by ensuring they are not governed solely by officials and stakeholders in California.

The market governance structure still is being defined by a working group, Davis said.

“The work group has a few objectives,” she explained. “The first is providing clarity for FERC oversight. The second is providing clarity for stakeholder processes. We’re also wanting to set up a structure that we can use for a potential transition to Step 3 at some point in the future.”

Step 3 in Pathways’ plan includes expanding the scope of ROWE’s functions and services.

“We’re also being mindful of the resource commitments for these potential approaches and those constraints,” Davis said.

Some areas still will be under joint authority between CAISO and ROWE, but sole authority over market policy rules will go to ROWE, Adam Schultz, CAISO manager of regional coordination, said during the meeting.

The joint areas are not related to market policy but concern certain overlapping areas such as financial and corporate issues, he clarified.

The Launch Committee seeks between $7 million and $8 million to fund ROWE’s implementation costs over the next two years, Jim Shetler, general manager of the Balancing Authority of Northern California, said during the meeting. The committee is exploring funding primarily through stakeholder contributions, grants and debt financing.

“We’re looking at somewhere around $750,000 to $800,000 in stakeholder contributions that we should have here in the next month or so,” Shetler said.

The committee anticipates an additional $300,000 in grants, Shetler added.

With a balance of about $1.1 million, Shetler said the committee has enough money to continue operations through the middle to third quarter of 2026. The committee is working with several banks to fund the remaining portion through debt financing, he said.

Posted on

EPRI Suggests Path to Limit Grid Costs of Data Center Surge

The expected rapid addition of large loads to the grid need not raise electricity rates, EPRI explains in a new research paper.

The authors conclude that if the incremental costs of serving the new loads are below the current average costs, new demand can actually lower the average retail rates as the system costs are spread across a wider base.

However, this depends on excess grid capacity or a relatively cheap source of new electrons being available.

If, instead, expensive grid investments are needed to serve that new load, or if the new load reduces its demands before those investments are paid for, the opposite effect can be seen: Prices could rise for other customers on the grid.

That is the root of the growing consternation about the largest component of the large load influx expected for the U.S. grid, data centers and the growing calls to make them pay their own way as electricity rates surge far above inflation. (See U.S. Utility Rate Increase Requests Topped $30B in 2025.)

EPRI President Arshad Mansoor said in a Jan. 29 news release the research paper shows a path toward the right balance: “As AI, electrification and industrial onshoring reshape the U.S. energy landscape, understanding how load growth interacts with system costs has never been more important. This research shows that with planning, pricing structures and flexible demand, growing electricity needs can support affordability and reliability for all.”

“Win-Win Watts: When Can Data Centers, Efficient Electrification and New Loads Lower Electricity Prices?” suggests three main action points:

    • rate design and cost allocation that protect existing customers;
    • demand flexibility; and
    • proactive planning that links demand with clean energy and grid investments.

Striking the right balance could lower costs, accelerate clean energy resources, support emerging technologies, reduce emissions and support better system operations.

The authors acknowledge the challenges implied in all this: “Whether those ‘win-win’ outcomes are realized depends on rate design, infrastructure needs and policy choices that affect whether new loads cover their costs and risks. Some answers depend on testing new technologies and business models, such as [EPRI’s DCFlex Initiative’s] demonstrations of data center load flexibility, that could offer new tools for managing growth while protecting affordability.”

The factors that help determine whether a new load raises or lowers electricity prices include:

    • system conditions: generation mix, current average costs, demand profiles, spare capacity, investments in the pipeline and reliability requirements;
    • shape of new loads: size, load factor, coincidence with net system peaks and ability to shift or curtail demand during stress periods;
    • technologies available: costs and performance of new generation, energy storage and demand-side options, including how quickly they can be financed, permitted and built; and
    • regulatory and market context: in cost-of-service regions, more of the new infrastructure costs show up directly in rates; in restructured markets, more of the impact shows up in wholesale prices and contracts that large customers sign with suppliers.

A correlation emerges in state-level analysis: States with faster load growth from 2019 to 2024 experienced smaller price increases or even price decreases, but states with flat or decreasing power sales saw larger price increases.

Large loads, the authors note, tend to locate where they expect future costs to be favorable.

Factors identified as supporting affordability amid large load growth:

    • incremental costs for generation, transmission and distribution additions being lower than present average costs;
    • high and predictable rates of utilization, to avoid wide gaps between contracted and realized load;
    • data availability and baseline transparency, so that flexibility can be incorporated into planning;
    • favorable load shapes and flexibility, so the new demand either flattens the system profile or does not contribute to its coincident peaks; and
    • well-designed tariffs and cost allocations that ensure large load customers cover the costs and risks they impose and are compensated for flexibility they offer.

EPRI, which describes itself as “rigorously objective,” has a board of directors populated almost entirely by top executives of major power providers.